technical support document draft air emission permit no

Technical Support Document, Permit Number: 01300098-101 of 19

Technical Support Document For

Draft Air Emission Permit No. 01300098-101

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: 4911)

Mankato Energy Center LLC/Mankato Energy Center II LLC (owners) 500 Delaware Avenue Suite 600 Wilmington, Delaware 19801 Calpine Operating Services Company, Inc. (operator) Calpine Corporation (owner) 717 Texas Avenue Suite 1000 Houston, Texas 77002

Mankato Energy Center LLC 1 Fazio Lane Mankato, Blue Earth County, Minnesota 56001

Contact: Heidi Whidden Phone: 713-570-4829

1.2 Facility description Mankato Energy Center, LLC (MEC I) owns an electric generating plant with a capacity of 375 MW at winter conditions, which is a 1X1 Siemens-Westinghouse combined cycle power block consisting of one combustion turbine, one heat recovery steam generator (HRSG), and one steam turbine. This turbine is fired primarily by natural gas with distillate fuel oil as backup. The combustion turbine exhausts to a separate HRSG with supplementary duct firing capacity of 800 mmBtu/hr. Steam generated in the HRSG exhausts into the steam turbine. Mankato Energy Center II, LLC (MEC II) will install a new combustion turbine/HRSG train converting the facility to a 2X1 combined cycle power block. The new CT/HRSG train will generate an additional 345 megawatts for a total of 720 megawatts of electricity at winter conditions. The new combustion turbine will be fired with natural gas only and exhaust to the new HRSG having a supplementary duct firing capacity of 824 mmBtu/hr. The duct burners will also fire with natural gas. The steam generated by the new HRSG will also exhaust to the existing steam turbine. Calpine Operating Services Company, Inc. (COSCI) is the operator for the entire facility. All entities are wholly owned indirect subsidiaries of Calpine Corporation. The facility is subject to the requirements of federal Prevention of Significant Deterioration (PSD) at 40 CFR Section 52.21 for PM, PM10, PM2.5 (MEC II), SO2, NOX, CO, VOC, GHG (MEC II) and H2SO4. The facility uses Best Available Control Technology (BACT) to control emissions. The facility is also subject to hazardous air pollutant (HAP) limits to avoid being a major source under 40 CFR Section 63.2. The facility also has an auxiliary boiler, fire pump engine, fuel oil storage tank for the CTG and for the fire pump, cooling tower, bath heater and a diesel fired emergency generator.

1.3 Description of the activities allowed by this permit action This permit action is a major amendment. With this permit action MPCA is authorizing construction for Calpine to install a new combustion turbine (CT) (EQUI 16)/HRSG train. This proposed expansion project will


be owned by MEC II and operated by COSCI. The new turbine will generate approximately 200 MW at 6 degrees F and be natural gas-fired. This will bring the total electric output capacity of the facility to 720 MW at 6 degrees F. The combustion turbine will exhaust to a new HRSG having supplementary duct firing capacity of 824 mmBtu/hr. The duct burners (EQUI 17) will also be natural gas-fired. Steam generated by the new HRSG will exhaust to the existing steam turbine. This expansion project will trigger a major modification under PSD for PM, PM10, PM2.5, NOX, VOC, CO and GHG. The Permittee will install selective catalytic reduction (SCR) (TREA 11) and combustion turbine dry low NOX burners to reduce NOX emissions and catalyst oxidation (TREA 12) to control CO and VOC emissions from the turbine. The HRSG duct burner exhaust will be controlled by SCR, catalyst oxidation and low NOX duct burners. The new combustion turbine will be an F-Class turbine with similar characteristics to the existing turbine. The new HRSG will be designed to produce steam conditions matching the existing equipment. Four new cells will be added to the existing cooling tower (FUGI 1) to provide additional cooling capacity to the expanded facility, bringing the total number of cells in the cooling tower to twelve (12). The cooling tower will continue to operate within the existing drift rate BACT limit of 0.0005%, but will be expanded to include PM2.5 emissions. An anhydrous ammonia tank will be installed to provide reagent to the new SCR. The facility also will add a water tank, condensate tank (insignificant activity, ACTV), a small diesel tank (EQUI 23) for the proposed diesel emergency generator, natural gas piping (FUGI 2) and electrical equipment insulated with sulfur hexafluoride (SF6) (FUGI 3). The facility has an existing bath heater (EQUI 19) that is included in this permit action. The facility will add a diesel fired emergency generator (EQUI 18). The emergency generator will be limited to 100 hours of non-emergency operation per year and operated and maintained in accordance with the manufacturer’s specifications. Natural gas fugitives (FUGI 2) and breaker fugitives (FUGI 3) for EQUI 16 and EQUI 17 are both new fugitive emissions sources at the facility.

1.4 Description of notifications and applications included in this action Table 2. Notifications and applications included in this action

Date received Application/notification type and description 11/03/2015 Major Amendment

1.5 Facility emissions: Table 3. Title I emissions summary

Pollutant

Emissions increase from the modification (tpy)

Limited emissions increase from the modification (tpy)

Net emissions increase (tpy)

NSR/112(g) Significant thresholds for major sources (tpy)

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

PM 68.00 68.00 68.00** 25 Yes PM10 54.83 54.83 54.83** 15 Yes PM2.5 52.15 52.15 52.15** 10 Yes NOx 1199.43 167.44 167.44 40 Yes SO2 30.46 30.46 30.46 40 No CO 1288.76 768.64 768.64 100 Yes Ozone (VOC) 425.54 382.58 382.58 40 Yes Lead 6.61E-03 6.61E-03 6.61E-03 0.6 No CO2e* 1,585,055 1,585,055 1,585,055 75,000 Yes Beryllium 4.24E-05 4.24E-05 4.24E-05 0.004 No Mercury 9.20E-04 9.20E-04 9.20E-04 0.1 No Total HAPs 3.17 3.17 3.17 10/25 No

* Carbon dioxide equivalents as defined in Minn. R. 7007.0100.


** Facility is not taking credit for past actual emissions from FUGI 1

Table 4. 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

189.1

175.9

173.2

98.58

354.0

1266

3,100,582

647.0

9.0*

22.5*

* Permit limit (Single HAP limits for Formaldehyde and Hexane)

Table 5. Facility classification

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

2. Regulatory and/or statutory basis

2.1 New source review (NSR)

The facility is an existing major source under New Source Review regulations. This permit action is for a major modification under NSR/PSD. See discussion in Section 3 of this TSD. An Endangered Species Assessment (ESA) was required for this project. A consultation letter was sent from the facility to EPA Region 5 on June 12, 2015. An email response to the consultant was received May 17, 2016 stating that for the proposed project, a response from a threatened or endangered species to an environmental stressor is unlikely and no further consultation is necessary under Section 7 of the Endangered Species Act (See Attachment 7). A National Historic Preservation Act (NHPA) submittal was required for this project. A consultation letter was sent from the facility to EPA Region 5 on June 12, 2015. An email response to the consultant was received May 17, 2016 stating for this proposed project, U.S. EPA had determined the project is not likely to affect historic properties and no further action is required under Section 106 of the National Historic Preservation Act (See Attachment 7).

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

2.3 New source performance standards (NSPS) The proposed diesel emergency engine (EQUI 18) is subject to 40 CFR pt. 60, subp. IIII, Standards of Performance for Stationary Compression Ignition Internal Combustion Engines. The emergency engine is manufactured after April 1, 2006, and is not a fire pump engine. The new combustion turbine #1 (EQUI 16) and duct burners for CT #1 (EQUI 17) are subject to 40 CFR pt. 60, subp. KKKK, Standards of Performance for Stationary Combustion Turbines. The new CT #1 (EQUI 16) and duct burners (EQUI 17) are also subject to 40 CFR pt. 60, subp. TTTT, Standards of Performance for Greenhouse Gas Emissions for Electric Generating Units.

2.4 National emission standards for hazardous air pollutants (NESHAP)

The facility has accepted limits on single (hexane and formaldehyde) and total HAP emissions to qualify as an area source under 40 CFR § 63.2. Thus, no major source NESHAPs apply. That status does not change with this permit action.


The fire pump engine (EQUI 11) and proposed diesel emergency engine (EQUI 18) are both subject to 40 CFR pt. 63, subp. ZZZZ, which applies to both major and area sources of HAP. The emergency engine (EQUI 18) complies with 40 CFR pt. 63, subp. ZZZZ by meeting the requirements of 40 CFR pt. 60, subp. IIII for compression ignition engines. The combustion turbines (EQUI 5, EQUI 16) are not subject to 40 CFR pt. 63, subp. YYYY, National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines because the facility is not a major source of HAP emissions. The existing (EQUI 6) and proposed (EQUI 17) duct burners are classified as Electric Utility Steam Generating Units (EUSGU) under 40 CFR pt. 63, subp. UUUUU. The EUSGU source category definition includes coal-fired and oil-fired EUSGUs. Since the duct burners EQUI 6 and EQUI 17 burn natural gas, 40 CFR pt. 63, subp. UUUUU does not apply to these units.

2.5 Acid rain program

The combustion turbines #2 and #1 (EQUI 5 and EQUI 16) and duct burner systems (EQUI 6 and EQUI 17) are new utility units subject to the Acid Rain Program requirements. As such, the Permittee is required to hold SO2 allowances, and monitor and report emissions of SO2, NOX and CO2. EQUI 5 qualifies as a gas-fired and diesel-fired utility unit whereas EQUI 16 is a gas-fired utility unit, and therefore opacity monitoring for both units is not required as allowed by 40 CFR Section 75.14(c) and (d). The Acid Rain Permit Application is included in Appendix C to the permit.

2.6 Clean Air Interstate Rule (CAIR) and the Transport Rule (TR)/Cross-State Air Pollution Rule (CSAPR) Mankato Energy Center was subject to CAIR when initially promulgated in 2005. MEC submitted their CAIR application on June 26, 2008. On November 3, 2009, the U.S. Environmental Protection Agency (EPA) published a final rule administratively staying the effectiveness of CAIR in Minnesota, as of December 3, 2009. MPCA returned MEC’s CAIR application on March 8, 2011. CAIR was replaced by TR/CSAPR in 2011, but TR/CSAPR was stayed by the D.C. Circuit, and EPA was told to go back to CAIR. The Supreme Court reversed the decision in 2014 and requested the D.C. Circuit to lift the stay. The D.C. Circuit court did this with an extension of the original compliance dates by three years. Minnesota is subject to 40 CFR pt. 97, subp. AAAAA, TR NOx Annual Trading Program and 40 CFR pt. 97, subp. DDDDD, TR SO2 Group 2 Trading Program. The applicable CSAPR requirements from 40 CFR pt. 97, subps. AAAAA and DDDDD are added to EQUI 5, EQUI 6, EQUI 16 and EQUI 17 in the permit. These are the two combustion turbines and duct burners at the facility. The TR Trading Program Title V Requirements describing the TR monitoring provisions are included in Appendix D to the permit.

2.7 State implementation plan (SIP)

There are no SIP conditions applicable to this facility. 2.8 Compliance assurance monitoring (CAM)

The table below lists the sources which are subject to CAM, whether the source is a large pollutant specific emission unit (PSEU), and the monitoring for the applicable pollutants. Table 6. CAM summary

Unit Control CAM applicability Pollutant Monitoring EQUI 16, 17 TREA 11 SCR Large NOx NOx CEMS EQUI 16, 17 TREA 12 Oxidation

Catalyst Large CO/VOC CO CEMS

For large pollutant specific emission units, records of the monitored parameter must be made at a minimum of four times per hour, or once every 15 minutes. See Attachment 4 to this document for the CAM Plan submitted by the applicant.


SCR (TREA 11) reduces NOX emissions from EQUI 16 and EQUI 17. EQUI 16 and 17 are subject to post-April 15, 1990 NSPS promulgated standards exempting them from CAM for the NSPS limits. However, EQUI 16 and 17 are also subject to a BACT limit that is subject to CAM. MEC II will install a NOX CEMS (EQUI 21) to demonstrate compliance with the proposed NOX BACT limit. The oxidation catalyst (TREA 12) reduces CO and VOC emissions. MEC II will install a CO CEMS (EQUI 22) to demonstrate compliance with the EQUI 16 and 17 CO BACT limit. The CAM rule indicates that use of a CEMS meets the requirements of the CAM rule. The CO CEMS is also proposed as a surrogate for VOC emissions.

2.8 Environmental Review This project is subject to Environmental Review and conducted an air emissions risk analysis (AERA). Calpine applied to the Minnesota Public Utilities Commission for a Site Permit in accordance with the Minnesota Power Plant Siting Act (Minn. Stat. 216E and Minn. R. ch. 7850) on August 5, 2015. The Site Permit application contains environmental information as specified by Minn. R. 7850.1900, subp. 3. Data and other information on air impacts is one area that is covered in the Site Permit application.

2.9 Air Emissions Risk Analysis (AERA) The purpose of the AERA is to assess the potential health risk attributed to air emissions from a given source. An AERA includes quantitative and qualitative analyses. In the quantitative portion of the analysis, the potential increment cancer risks and non-cancer hazard indices are estimated using procedures outlined in MPCA guidance. The qualitative portion of the analysis identifies and discusses items of potential interest that cannot be easily quantified. The AERA was triggered due to emissions increases of CO and VOC greater than 250 tpy as shown in Table 3.

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

· Minn. R. 7011.0515 Standards of Performance for New Indirect Heating Equipment · Minn. R. 7011.0715 Standards of Performance for Post-1969 Industrial Process Equipment · Minn. R. 7011.1505, subp. 3 Standards of Performance for Post-June 11, 1973 Storage Vessels · Minn. R. 7011.2300 Standards of Performance for Stationary Internal Combustion Engines

Table 7. Regulatory overview of units affected by the modification/permit amendment

Subject item*

Applicable regulations Rationale

COMG 5 (HAPs Limits)

Title I limit to avoid major source under 40 CFR 63.2

National Emission Standards for Hazardous Air Pollutants. Limit set on HAPs emissions to avoid major source classification under 40 CFR Part 63.

STRU 14 (CT/DB #2 Stack)

Title I Condition: 40 CFR § 52.21(j)(BACT) & Minn. R. 7007.3000 Minn. R. 7007.0800, subp. 2

Prevention of Significant Deterioration (PSD). Existing requirements for Startup and Shutdown Operating Mode and Control Equipment Operation During Startup and Shutdown were changed to Title I Conditions for BACT for STRU 14. Limits for PM2.5 for natural gas and fuel oil use.


Subject item*

Applicable regulations Rationale


Title I Condition: 40 CFR § 52.21(j)(BACT) & Minn. R. 7007.3000 40 CFR pt. 60, subp. KKKK 40 CFR pt. 60, subp. TTTT

PSD BACT limits set for NOX, CO, VOC, PM, PM10, PM2.5, and CO2e. Startup/Shutdown BACT limits set for NOX, CO and VOC. Standards of Performance for Stationary Combustion Turbines · CT with heat input at peak load greater than or equal to 10

mmBtu/hr based on HHV; and · The unit was constructed after February 18, 2005. Standards of Performance for Greenhouse Gas Emissions for Electric Generating Units · the unit was constructed after January 8, 2014; · the unit has a base load rating greater than 250 mmBtu/hr of

fossil fuel; and · the unit serves a generator capable of selling greater than 25 MW

of electricity to a utility power distribution system. EQUI 5 (CT #2), EQUI 6 (Duct Burners CT #2), EQUI 16 (CT #1), EQUI 17 (Duct Burners CT #1)

40 CFR pt. 97, subp. AAAAA 40 CFR pt. 97, subp. DDDDD

Transport Rule (TR) NOX Annual Trading Program · CT serving after January 1, 2005, a generator with nameplate

capacity of more than 25 MWe producing electricity for sale. TR SO2 Group 2 Trading Program · CT serving after January 1, 2005, a generator with nameplate

capacity of more than 25 MWe producing electricity for sale.

EQUI 5 (CT #2), EQUI 16 (CT #1)

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

EQUI 18 (Emergency Generator)

40 CFR pt. 60, subp. IIII 40 CFR pt. 63, subp. ZZZZ Minn. R. 7011.2300

Standards of Performance for Stationary Compression Ignition Internal Combustion Engines National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines Standards of Performance for Stationary Internal Combustion Engines

EQUI 19 (Bath Heater)

Minn. R. 7011.0515 Standards of Performance for New Indirect Heating Equipment · Construction commenced after January 31, 1977.

EQUI 21 (CT #1 NOX CEMS)

40 CFR pt. 75 CEMS CEMS Certification and Operation via 40 CFR pt. 75

EQUI 22 (CT #1 CO CEMS)

40 CFR pt. 60 CEMS CEMS Certification and Operation via 40 CFR pt. 60

EQUI 23, 24 (Tanks)

Title I Condition: 40 CFR § 52.21(j)(BACT) & Minn. R. 7007.3000 Minn. R. 7011.1505, subp. 3.B

Title I BACT limits to install a fixed roof tank and maintain the tank in good working condition (EQUI 23, diesel emergency generator tank) and maintain the tank in good working condition (EQUI 24, natural gas condensate tank - plant) Standards of Performance for Post-June 11, 1973 Storage Vessels

FUGI 1 (Cooling Towers)

Minn. R. 7011.0715/0735 Standards of Performance for Post-1969 Industrial Process Equipment

FUGI 2 (NG fugitives) FUGI 3 (breaker fugitives)

Title I Condition: 40 CFR § 52.21(j)(BACT) & Minn. R. 7007.3000

FUGI 2 BACT limit to conduct quarterly audio/visual/olfactory inspections. FUGI 3 BACT limit to use state-of-the-art enclosed-pressure SF6 circuit breakers with leak detection and monthly pressure inspections.

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


3. Technical information 3.1 Combustion Turbine/HRSG train with Duct Burners

The two combustion turbine/HRSG trains will provide steam to an existing steam turbine generator. The current (EQUI 5) and proposed (EQUI 16) combustion turbines are F-Class models utilizing compressed air and fuel to produce electricity and high temperature exhaust gas. The proposed combustion turbine will fire natural gas only. The HRSG recovers the waste heat from the combustion turbine and is used to produce steam, creating additional power generation in combination with the steam turbine. The exhaust heat from the combustion turbine is taken by the HRSG to heat water and convert it to steam. The steam turbine then receives the steam from the two HRSGs and as the steam expands it causes the steam turbine shaft to rotate. This drives the generator and produces electrical power. Pollution control equipment for the new combustion turbine includes selective catalytic reduction (SCR) (TREA 11) to control NOX emissions, and a catalytic oxidizer (TREA 12) to control CO and VOC emissions. The proposed HRSG low-NOX duct burners (EQUI 17) will also be controlled by SCR (TREA 11) and the catalytic oxidizer (TREA 12). Combustion of natural gas produces low amounts of particulate and SO2 emissions so no pollution control equipment is proposed for either of these pollutants. Dry low-NOX (DLN) burners limit NOX production by premixing compressed air with natural gas before being injected into staged lean combustors. This results in a cooler combustion zone. Typically, the higher the combustion temperature, the more NOX produced. The SCR control uses anhydrous ammonia and a catalyst converting NOX to elemental nitrogen and water. The combustion turbines (new and existing) have the ability to operate with or without duct burners. The duct burners take excess oxygen in the exhaust gas to combust additional natural gas, thus increasing steam production. As mentioned above the duct burners will add 824 mmBtu/hr of heat input. The new CT/DB system will operate in parallel to the existing CT/DB system and both will provide steam to the existing steam turbine.

3.2 Additional Equipment

The facility will also add a diesel emergency generator (EQUI 18). This generator will be subject to New Source Performance Standards for Stationary Compression Ignition Internal Combustion Engines (40 CFR pt. 60, subp. IIII). EQUI 18 will also be subject to 40 CFR pt. 63, subp. ZZZZ for Stationary Reciprocating Internal Combustion Engines at area sources of HAP. It will comply with 40 CFR pt. 63, subp. ZZZZ by complying with the applicable requirements of 40 CFR pt. 60, subp. IIII. The emergency engine will also be subject to Minnesota Standards of Performance for Stationary Internal Combustion Engines at Minn. R. 7011.2300. The engine will be limited to less than or equal to 100 hours per year. This limitation will be a BACT limit to minimize emissions of NOX, CO, VOC, PM, PM10 and PM2.5. The facility has a bath heater (EQUI 19) that is being added to the permit as an EQUI. The emissions from EQUI 19 exceed the NOX threshold listed at Minn. R. 7007.1300, subp. 3(I). The bath heater is subject to state standards of performance for new indirect heating equipment and will perform daily visible emissions inspections during daylight hours. The facility also plans to add four additional cells to the existing cooling tower (FUGI 1) to accommodate the additional cooling capacity needed with the addition of the new CT/DB unit. This will bring the number of cells in the cooling tower to 12. New natural gas piping (FUGI 2) and electrical equipment (FUGI 3) insulated with sulfur hexafluoride (SF6) will also be added. An anhydrous ammonia tank, water tank, condensate tank and small diesel tank for the proposed diesel emergency generator will also be added.

3.3 Best Available Control Technology

This modification is subject to PSD for NOX, CO, VOC, PM, PM10, PM2.5 and GHG. The facility is required to complete a case-by-case best available control technology (BACT) analysis for each piece of equipment associated with the project. BACT is determined using U.S. EPA’s five step top-down approach. Following this approach, control technologies are analyzed until a level of control considered BACT is reached based on environmental, energy and economic impacts. The five steps included are: 1 Identify applicable options; 2 Eliminate technically infeasible options;


3 Rank remaining alternatives by control effectiveness; 4 Evaluate most effective controls; and 5 Select BACT In determining BACT, information from the following sources was evaluated: on-line EPA RACT/BACT/LAER Clearinghouse (RBLC) system and other state BACT control technology databases, EPA/state/local air quality permits and applications, control technology vendors, AP-42 Section 3.1 stationary gas turbines for electricity generation, and alternative control techniques document NOX emissions from stationary gas turbines EPA-453/R-93-007.

3.3.1 Control of NOX Emissions

The following technologies were identified as potentially able to control NOX emissions from stationary combined cycle combustion turbines: DLN burner technology; Wet controls (water and steam injection); Rich/Quench/Lean (RQL) combustion; Selective Catalytic Reduction (SCR); Selective Non-Catalytic Reduction (SNCR); EMx, formerly SCONOXTM catalytic oxidation/absorption; and Catalytic combustion XONONTM

The control alternatives listed above were reviewed for technical feasibility in controlling NOX emissions from EQUI 16/EQUI 17. Combustion control utilizing DLN burners based on lean premix combustion control and SCR is deemed the highest ranking control technology (i.e. BACT). NOX BACT for EQUI 16/EQUI17 is proposed as 3.0 ppmvd based on a 3-hr rolling average at 15% O2 for natural gas combustion using DLN burners and SCR technology. This limit does not apply during startup, shutdown, malfunction, tuning and combustion turbine shakedown.

3.3.2 Control of CO Emissions

Review of the RBLC resulted in two types of CO control technologies available for combined cycle applications. Those two technologies are: Combustion control; and Catalytic oxidizer Both available control alternatives will be applied to the CT/HRSG train. The most effective CO control will be from the catalytic oxidizer. Since catalytic oxidation for CO control is most effective, no further analysis is needed in a top down BACT analysis. The facility proposes installation of a catalytic oxidizer to decrease CO emissions. The proposed CO BACT limits are 4.0 ppmvd based on a 3-hr rolling average at 15% O2 (operating at normal base load capacity) and 4.7 ppmvd based on a 3-hr rolling average at 15% O2 (operating at conditions below base load capacity) for natural gas combustion with DLN burner technology, low NOX duct burners and catalytic oxidizer. This limit does not apply during startup, shutdown, malfunction, tuning and combustion turbine shakedown. Base load operation for the turbine is > 90% of capacity for ambient conditions. Less than base load is > 60% and < 90% of rated capacity for ambient conditions.

3.3.3 Control of VOC Emissions

Similar to CO control, a review of the RBLC resulted in two control technologies available for combined cycle applications of VOC control. Once again the two control technologies are combustion control and catalytic oxidizer. Again, both available control technologies will be applied to the CT/HRSG train. And again, since catalytic oxidation for VOC control is most effective, no further analysis is needed in a top down BACT analysis. The facility proposes installation of a catalytic oxidizer to decrease VOC emissions. The proposed VOC BACT limit is 3.4 ppmvd based on a 3-hr block average at 15% O2 for natural gas combustion with DLN burner technology, low NOX duct burners and catalytic oxidizer. This limit does not apply during startup, shutdown, malfunction, tuning and combustion turbine shakedown. The permit includes separate NOX, CO and VOC BACT limits that apply during startup and shutdown operation.


3.3.4 Control of PM/PM10/PM2.5 Emissions

A review of the RBLC for PM/PM10/PM2.5 resulted in the following control technologies available to control particulate emissions from combined cycle applications: Fuel specifications; clean burning fuel; Good combustion practices/combustion control; and Low-sulfur fuel MEC II proposes to burn pipeline-quality natural gas, maintain the turbine/HRSG in good working order and implement good combustion practices with DLN burner technology. The proposed BACT limits are based on vendor data and operating experience at MEC and other units in Calpine’s fleet. Add-on control for PM, PM10 and PM2.5 are technically and economically infeasible due to high flow rates and low particulate concentrations. The proposed BACT limit for PM, PM10 and PM2.5 is 11.9 lb/hr on a 3-hr block average for natural gas combustion. This limit will apply at all times including startup, shutdown and malfunction. The limit will not apply prior to combustion turbine shakedown. The existing turbine’s PM/PM10 BACT limits are written in units of lb/hr and lb/mmBtu. The PM/PM10/PM2.5 BACT limits for the proposed turbine will also include a lb/mmBtu component. Combustion turbine vendors do not provide emission guarantees in lb/mmBtu because particulate emissions do not vary proportionately with heat input. Vendors have little data for particulate emissions at reduced load (i.e. 50-60%) because particulate testing is rarely done below base load. Contributions to particulate emissions include combustion turbine combustion, duct burners and ammonium bisulfate formation downstream of the SCR. Duct burner and ammonium bisulfate particulate emissions increase proportionally with increased heat input. Combustion turbine particulate emissions however, do not increase with increased heat input. When the combined emissions from the turbine, duct burner and ammonium bisulfate are added together and converted to lb/mmBtu the highest emission rates correspond with the lowest heat input values. Calpine proposes a PM/PM10/PM2.5 lb/mmBtu emission rate limit of 0.0098 lb/mmBtu.

0.0098 lb/mmBtu = 11.9 lb/hr * 1/1218 mmBtu/hr

The lb/mmBtu emission rate limits on the existing turbine was calculated using the same methodology. 1218 mmBtu/hr is approximately 60% of the rated capacity of the proposed turbine at 92 degrees F.

3.3.5 Control of Greenhouse Gas (GHG) Emissions

MEC II proposes the following energy efficiency processes, practices and designs for the combined cycle turbine: Use of combined cycle power generation technology;

Combustion turbine energy efficiency processes, practices and designs: efficient turbine design, turbine inlet air cooling, periodic turbine burner tuning, reduction in heat loss and instrumentation and controls; HRSG energy efficiency processes, practices and designs: efficient heat exchanger design, insulation of HRSG, minimizing fouling of heat exchange surfaces, minimizing vented steam and repair of steam leaks; Plant-wide energy efficiency processes practices and designs: fuel gas preheating, drain operation, multiple combustion turbine/HRSG trains and boiler feed pump fluid drive design.

To determine an appropriate heat rate for EQUI 16 (CT #1) in combined cycle operation without duct burning, the following compliance margins were added to the base heat rate value. A design margin of 3.3% reflecting the possibility the constructed facility will not be able to achieve the design heat rate. A performance margin of 6% reflecting efficiency losses due to equipment degradation prior to maintenance overhauls. A degradation margin of 3% reflecting the variability in operation of auxiliary plant equipment due to use over time. The result of these adjustments leads MEC II to propose a BACT maximum net heat rate of 7979 btu/kWh (HHV)(at EQUI 16 level) based on the conditions of ambient dry bulb temperature of 6 degrees F, ambient relative humidity of 59%, barometric pressure of 14.28 psia, fuel LHV of 21,500 btu/lb and fuel HHV/LHV ratio of 1.109. A GHG BACT limit of < 1000 lb CO2e/MWh on gross power production basis is proposed based on 1X1 combined cycle operation. This limit is also applicable via NSPS subp. TTTT. The facility will performance test 180 days after the first fire to verify compliance with the heat rate limit.


3.3.6 BACT for Diesel Engine Emergency Generator (EQUI 18)

The diesel engine emergency generator will be used for emergency situations. It will, however, be operated for a minimal period on a bi-weekly basis for testing. The proposed BACT for EQUI 18 is to maintain the emergency engine in good working order, operation according to the manufacturer’s specifications and limiting non-emergency operation to < 100 hours per year. This limits the annual emissions in tons per year of the following pollutants to: 0.66 tpy NOX; 0.66 tpy CO; 0.04 tpy VOC; 0.26 tpy SO2; 0.01 tpy PM/PM10/PM2.5; 208 tpy CO2e.

3.3.7 BACT for Cooling Tower (FUGI 1)

Four new cells will accommodate the additional cooling requirements at the facility. Cooling towers associated with combined cycle power plants are equipped with high efficiency mist eliminators. The existing and new cells to the cooling tower will incorporate a mist eliminator with 0.0005% tower drift rate. This limit is established in the current permit but will be expanded in this permit action to include PM2.5 emissions.

3.3.8 BACT for Diesel Fuel Storage Tank (EQUI 23)

The diesel engine emergency generator (EQUI 18) will have its own diesel storage tank (EQUI 23). The storage capacity will be approximately 5000 gallons. Due to low volatility of diesel fuel, potential emissions of VOC are expected to be negligible. BACT is proposed as using a fixed roof tank and maintaining the tank in good working condition.

3.3.9 BACT for Condensate Tank (EQUI 24)

MEC II will install a 6615 gallon condensate tank that will emit a small amount of VOC. Its usage will be on a batch cycle and minimal. BACT is proposed as maintaining the tank in good working condition.

3.3.10 BACT for Natural Gas Piping (FUGI 2) for GHG Emissions

Natural gas is delivered to the facility via pipeline. Gas will be metered and piped to the new combustion turbine (EQUI 16) and duct burner (EQUI 17). GHG fugitive emissions from the piping components will include emissions of methane and carbon dioxide. The following technologies were identified as potential control options for piping fugitive emissions: implementation of leak detection and repair (LDAR) using a hand held analyzer; implementation of alternative monitoring using a remote sensing technology such as infrared cameras; and implementation of audio/visual/olfactory (AVO) leak detection. LDAR and remote sensing technologies are both technically feasible. Since pipeline natural gas is odorized with small amounts of mercaptan, an AVO leak detection program is technically feasible. Uncontrolled CO2e emissions from FUGI 2 from EQUI 16/EQUI 17 represent approximately 0.01% of the facility’s total CO2e emissions. Any control techniques applied to FUGI 2 will provide minimal CO2e emission reductions. BACT for FUGI 2 (EQUI 16/EQUI 17) is proposed as quarterly AVO inspections.

3.3.11 BACT for Electrical Equipment Insulated with SF6 (FUGI 3)

The generator circuit breakers will be electrically insulated using sulfur hexafluoride (SF6) gas. The gas is used for electrical insulation, arc quenching and current interruption in high voltage electrical equipment. It is only used in safe, sealed systems which under normal circumstances do not leak gas. Two new SF6 breakers (FUGI 3) as part of EQUI 16 equipment will be installed with this amendment. The circuit breaker for EQUI 16 will contain approximately 35 lbs of SF6. Another circuit breaker between the CT generator step-up transformer and 115 kV transmission line will hold approximately 72 lbs of SF6. One available control technology is the use of state-of-the-art SF6 technology with leak detection to limit fugitive emissions. One alternative considered in this BACT analysis is to substitute with another non-greenhouse gas


substance for SF6 as the dielectric material in the circuit breakers. Potential alternatives to SF6 were addressed in the National Institute of Standards and Technology (NIST) Technical Note 1425, Gases for Electrical Insulation and Arc Interruption: Possible Present and Future Alternatives to Pure SF6. NIST Technical Note 1425 describes SF6 as a superior dielectric gas for nearly all high voltage applications. Due to the level of superiority as a dielectric gas for SF6, there are no current technically feasible alternatives to SF6. MEC II concluded that using state-of-the-art enclosed-pressure SF6 circuit breakers with leak detection is considered BACT. The circuit breakers will be designed to meet the latest of the American National Standards Institute (ANSI) C37.013 standard for high voltage circuit breakers. The proposed circuit breakers will have low pressure alarms and low pressure lockouts.

3.4 Environmental Review

In Minnesota no person may construct a large electric power generating plant greater than 50 MW without a Site permit from the Public Utilities Commission (PUC). Calpine filed an application for a Site permit for the proposed 345 MW expansion of the existing Mankato Energy Center with the PUC on August 5, 2015. The application was deemed complete by the PUC at a Board meeting in September 2015. A public information and scoping meeting was held in Mankato in October 2015 to determine the scope of the environmental assessment (EA) for the proposed expansion project. The Department of Commerce (DOC) completed the scoping of the EA in October 2015 and began work on the EA. The EA document was available for public review and comment in February 2016. A public hearing administered by an administrative law judge was held in Mankato in March 2016 to allow public comment and discussion on the Site permit application and the EA. The Findings of Fact on the adequacy of the Site permit process and the EA was published in April 2016. In May 2016, briefing papers were prepared by PUC staff and presented to the PUC Board for review stating that the factors of the Site permit process had been completed appropriately by Calpine and the EA had addressed the project and environmental issued identified during the scoping process. The PUC Board approved the EA as complete and authorized the issuance of the Site permit for the expansion project to Calpine at a meeting on June 2, 2016.

3.5 Air Emissions Risk Analysis (AERA) As mentioned above, an AERA was conducted for this project because there is an increase in emissions of CO and VOC by more than 250 tons per year. The AERA was prepared in accordance with MPCA AERA Guidance, updated April 27, 2015. The guidance includes use of a Risk Assessment Screening Spreadsheet (RASS) for quantitative analysis. The most recent version of the RASS was used for the analysis. It quantitatively assesses the potential human health effects from the proposed CT/DB system (STRU 20), the existing CT/DB system (STRU 14), the auxiliary boiler (STRU 17) and the bath heater (STRU 22). The AERA assesses the short-term and acute inhalation hazard and long-term chronic acute inhalation cumulative excess cancer risk and hazard. The results of the acute inhalation hazard and chronic multipathway hazard analysis were both less than 1.0. The chronic lifetime excess cancer risk estimate was less than the Minnesota Department of Health threshold of 10E-05, or one in 100,000. Thus, the AERA and RASS results indicate the addition of a second combustion turbine system at the facility will not adversely affect human health or the environment. The RASS is Attachment 5 to this TSD.

3.6 Environmental Justice Environmental Justice (EJ) is the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation and enforcement of environmental laws, regulations and policies. EPA has this goal for all communities and persons across the country. It will be achieved when everyone enjoys the same degree of protection from environmental and health hazards and equal access to the decision-making process to have a healthy environment in which to live, learn and work. As part of the permitting process, the MPCA contacts U.S. EPA Region 5 staff to determine if there are any possible EJ issues for the facility location that need to be addressed in the permit action. For this project, MPCA staff contacted EPA Region 5 staff on February 17, 2016 and received no indication of concern for this facility’s location with regard to EJ.

3.7 BACT Limit Averaging Times


The Permittee asked the original permit author a question via phone call on July 18, 2006 about the averaging times for combined cycle BACT limits on the existing turbine. The question was whether the averaging time was a 3-hour rolling or block average. The concern by the Permittee was that permit no. 01300098-001 was silent on this issue. The answer given was for pollutants monitored by CEMS the average is 3-hr rolling (NOX and CO). For pollutants measured by a stack test, the averaging time is a 3-hr block. The proposed turbine for this permit action also has CEMS for NOX and CO. NOX was also modeled against National Ambient Air Quality Standards (NAAQS) for which there is a one-hour standard. For normal operation NOX BACT limits on the existing and proposed turbines and duct burners, the averaging time is 3-hr rolling. For CO BACT limits the averaging time is 3-hr rolling. For all other pollutants (except CO2e on the proposed turbine) the averaging time is a 3-hr block. Averaging times for the existing turbine/duct burner BACT limits will be updated in this permit action.

3.8 Combustion Turbine #2 PM2.5 Limits Permit no. 01300098-002 had performance test requirements for PM2.5 but no permit limit to test against. Limits for PM2.5 while burning natural gas and fuel oil will be added during this permit action and be the same numerical limits as those for PM and PM10. As PM2.5 was not a regulated pollutant during permit action -001, PM2.5 was not part of the original BACT analysis for combustion turbine #2 (EQUI 5). Therefore, the citation for these PM2.5 limits will be Minn. R. 7007.0800, subp. 2. These limits are placed at the STRU 14 level.

3.9 Calculations of potential to emit

Attachment 1 to this TSD contains PTE spreadsheets, which summarizes the PTE of the Facility, and provides detailed emissions analyses for the modification prepared by the MPCA and the Permittee. The spreadsheet includes the new Tempo nomenclature for equipment at the Facility as they are different from the previous Delta nomenclature. The old Delta names for equipment are also included for reference.

4. Dispersion modeling

The facility conducted modeling for the installation of a combined cycle combustion turbine and associated HRSG. The initial NOx modeling report resulted in non-attainment (189.69 ug/m3); however, Mankato Energy Center demonstrated compliance with the one-hour NO2 NAAQS (0.00014 ug/m3). From reviewing the modeling demonstration it was determined that the emissions from CHS-Mankato were the primary contributor to modeled non-attainment. Upon further review it was discovered that the CHS-Mankato emission rates were not current for that facility. The MPCA adjusted the relevant CHS-Mankato emissions and re-ran the model which resulted in modeled attainment with a maximum value of 158.53 ug/m3. MPCA reviewed the significant impact level (SIL) modeling evaluation for CO, PM10 and PM2.5. The modeled values based on MPCA verification runs agree with reported values and no further refined modeling for these pollutants was necessary. MPCA also reviewed the modeling files submitted for PM2.5 increment screening and agree that no further increment evaluation is needed for this project. With the final NO2 modeled concentration of 158.53 ug/m3 this is 84.3% of the 1-hr NO2 primary NAAQS standard (188 ug/m3). This result qualifies NO2 modeling for tier 2 remodeling requirements (75%-90% of the NAAQS standard). Mankato Energy Center had previously modeled NO2 during permit action -001 and the previous result was also tier 2. Updated PSD Tier 2 remodeling requirements are being placed in the permit with this amendment.

5. 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.

For CAM, the Permittee submitted a CAM proposal as required by 40 CFR § 64.3. It can be found in Attachment 4 to this TSD. Further discussion of decisions about CAM can be found in Table 8.

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 8. Monitoring

Subject item* Requirement (rule basis)

Monitoring Discussion

COMG 5 (HAPs Limits)

Formaldehyde ≤ 9.0 tons per year, on a 12 month rolling sum

Hexane < 9.0 tons per year, on a 12 month rolling sum

Total HAPs < 22.5 tons per year, on a 12 month rolling sum

(limit to avoid major source under 40 CFR 63.2 & Minn. R. 7011.7000)

Recordkeeping: For EQUI 5, 6 records of daily heat input during operation and hours of operation during NG & FO operation with monthly calculations of HAPs emissions at STRU 14. For EQUI 16, 17 the same records as above during NG operation with monthly calculations at STRU20. For EQUI 7, 11, 18, 19 records of monthly heat input with monthly calculations of HAPs emissions, 12-month rolling sum calculations done by the 15 of the month for the previous month located at COMG 5

HAP emissions monitoring for formaldehyde, hexane, other single HAPs and total HAPs can be determined by daily heat input records, daily operating hours and applicable emission factors as specified in the permit at STRU 14 for natural gas (NG) and fuel oil (FO) and at STRU 20 for NG. HAP emissions monitoring for EQUI 7, 11, 18 and 19 is located at COMG 5. Monthly calculations of HAP emissions are located at STRU 14 and STRU 20. The Hexane limit is revised to < 9.0 tpy, previously < 8.5 tpy. HAP emissions monitoring for EQUI 7, 11, 18, 19 located at COMG 5. Option to use monthly PTE for EQUI 7, 11, 18, 19 in lieu of monthly recordkeeping at COMG 5.


PM2.5: < 0.009 lb/ mmbtu not to exceed 22.0 lb/hr 3-hr block avg NG

PM2.5: < 0.057 lb/ mmbtu not to exceed 72.8 lb/hr FO

(Minn. R. 7007.0800, subp. 2)

Performance testing on a 60 month schedule

Permit contained PM2.5 performance testing but no limits. Limits are equivalent to existing limits for PM and PM10 while burning natural gas (NG) or fuel oil (FO). PM2.5 was not a regulated PSD pollutant during permit no. 01300098-001 and not part of the original BACT analysis. Thus, these limits are cited under Minn. R.





NOX: ≤ 3.0 ppm, on 3-hr rolling avg. by vol. dry

CO: < 4.0 ppm, on 3-hr rolling avg. by vol. dry at full load

CO: < 4.7 ppm, on 3-hr rolling avg. by vol. dry at less than full load

VOC: < 3.4 ppm, on 3-hr block avg. by vol. dry

PM/PM10/PM2.5: < 0.0098 lb/mmBtu not to exceed 11.9 lb/hr, on 3-hr block avg.

CO2e: < 1000 lb/MWh (gross)

(Title I Condition: 40 CFR § 52.21(j) (BACT) & Minn. R. 7007.3000)

NOX: < 15 ppm @ 15% O2 30 day rolling avg. by vol.

NOX: < 96 ppm @ 15% O2 30 day rolling avg. by vol.

SO2: < 0.060 lb/ mmBtu

(40 CFR 60.4320 (a) & 40 CFR 60.4330(a)(2))

CO2: < 1000 lb/MWh 12 mo. rolling avg. (gross)

(40 CFR 60.5520 (a))

Monitoring: NOX & CO CEMS to monitor NOX, CO and VOC (indirectly from CO CEMS) emissions

Initial performance tests and test frequency plans for PM, PM10, PM2.5, VOC, CO2e, formaldehyde & hexane

NOX, CO and VOC BACT limits do not apply during startup, shutdown, malfunction or tuning. (See SUSD BACT limits in next row.) PM, PM10, PM2.5 and CO2e BACT limits apply at all times. All normal operation BACT limits do not apply until after the shakedown period ends. NOX CEMS required by Acid Rain Program. CO CEMS for directly monitoring CO emissions and indirectly monitoring VOC emissions. NOX and SO2 limits from 40 CFR pt. 60, subp. KKKK apply to both the CT #1 (EQUI 16) and duct burners for CT #1 (EQUI 17). 15 ppm NOX limit applies when the turbine operates at or above 75 percent load and ambient temp is 0 deg F or above. 96 ppm NOX limit applies when the turbine operates below 75 percent load or ambient temp is less than 0 deg F.





SUSD BACT limits

NOX: < 41.9 tpy 12 mo. rolling sum & 414 lb/event cold SU, 220 lb/event warm SU, 27 lb/ event SD

CO: < 666.63 tpy 12 mo. rolling sum & 5919 lb/event cold SU, 3788 lb/event warm SU, 301 lb/ event SD

VOC: < 333.32 tpy 12 mo. rolling sum & 2959.5 lb/event cold SU, 1894.0 lb/event warm SU, 150.5 lb/event SD


Recordkeeping: monitoring of cold or warm startups & shutdowns in a calendar year, calculation of annual SUSD emissions

Startup (SU)/Shutdown (SD) BACT limits for times when CT/DB #1 is not in normal operating mode (see row above). Limits do not apply until after the shakedown period ends.

EQUI 7 (Auxiliary Boiler)

PM/PM10: < 0.008 lb/mmBtu

SO2: < 0.001 lb/mmBtu

CO: < 0.06 lb/mmBtu

VOC: < 0.007 lb/mmBtu


Initial Performance tests due 180 days after permit issuance, test frequency plan

Existing BACT limits on EQUI 7 that did not contain adequate monitoring or compliance. Initial performance tests and test frequency plan requirements are being added with this permit action.




EQUI 16 (CT #1)

SO2: ≤ 0.50 lb/mmBtu

Opacity: < 20 %

(Minn. R. 7011.2300, subps. 1-2)

Maximum net heat rate: 7979 btu/kWh (HHV)

Fuel type: natural gas only


Performance test to verify maximum net heat rate 180 days after first firing Recordkeeping: fuel type usage

EQUI 16 limited to burn natural gas as defined at 40 CFR 72.2 with total sulfur content not to exceed 0.8 gr/100 scf. Natural gas must be obtained from a supplier through a pipeline. Fuel restriction is a BACT limit. EQUI 16 must also demonstrate a net heat rate (HHV) of 7979 btu/kWh at base load without duct firing and will perform a heat rate test to demonstrate compliance with this value 180 days after first firing and again prior to obtaining a new permit.

EQUI 17 (Duct Burners CT #1)

Fuel type: natural gas only


None EQUI 17 limited to burn natural gas as defined at 40 CFR 72.2 with total sulfur content not to exceed 0.8 gr/100 scf. Natural gas must be obtained from a supplier through a pipeline. Fuel restriction is a BACT limit. No monitoring is needed, only fuel certifications kept to meet the sulfur content limit of natural gas.

EQUI 18 (Emergency Generator)

Operating Hours: < 100 hr/yr 12 mo. rolling sum


SO2: ≤ 0.50 lb/mmBtu

Opacity: < 20 %

(Minn. R. 7011.2300, subps. 1-2)

Recordkeeping: daily records of hours of operation, monthly calculation of hours

Daily records of hours of operation can be recorded based on hour meter. Monthly and 12 month rolling sums can be calculated using the daily hours of operation records.

EQUI 19 (Bath Heater)

PM: < 0.40 lb/mmBtu 3-hr avg.

Opacity: < 20 % with exceptions

(Minn. R. 7011.0515, subps. 1-2)

None None

EQUI 23 (Diesel Generator Tank) EQUI 24 (Natural Gas Condensate Tank - Plant)

Equip the tank with a permanent submerged fill pipe

(Minn. R. 7011.1505, subp. 3.B)

None Both storage vessels are greater than 2000 gal capacity and constructed after June 11, 1973. BACT requirement for EQUI 23 to be a fixed roof tank and maintain it in good working condition. BACT requirement for EQUI 24 to be maintained in good working condition.




FUGI 1 (Cooling Tower)

Drift Rate: < 0.0005%


PM: < 0.020 gr/dscf

Opacity: < 20%

(Minn. R. 7011.0715, subps. 1-2)

None Drift rate BACT limit already existed in permit 01300098-002 but will be expanded to include PM2.5. The drift rate is a design based requirement, therefore no ongoing monitoring is needed.

*Location of the requirement in the permit (e.g., EQUI 1, STRU 2,etc.). 6. Insignificant activities

Mankato Energy Center LLC has several operations which are classified as insignificant activities under the MPCA’s permitting rules. These are listed in Appendix A to the permit. The following insignificant activities are included in this modification: a fuel tank for the diesel fire pump, and two natural gas condensate tanks for CT #1 and CT #2.

The permit is required to include periodic monitoring for all emissions units, including insignificant activities, per EPA guidance. The insignificant activities at this Facility are only subject to general applicable requirements. Using the criteria outlined earlier in this TSD, the following table documents the justification why no additional periodic monitoring is necessary for the insignificant activities affected by this modification. As previously mentioned, the bath heater (EQUI 19) no longer qualifies as an insignificant activity under Minn. R. 7007.1300, subp. 4. See Attachment 1 of this TSD for PTE information for the insignificant activities.

Table 9. Insignificant activities

Insignificant activity General applicable emission limit Discussion

Storage tanks meeting the criteria in Minn. R. 7007.1300, subp. 3(E): Fire Pump Diesel Fuel Tank (360 gal); Natural Gas Condensate Tank - CT1 (45 gal); Natural Gas Condensate Tank CT2 (45 gal)

Minn. R. 7011.1505, subp. 3.A

Minn. R. 7011.1505, subp. 3.A contains tank design requirements for which no monitoring is applicable (< 2000 gal).

The facility’s No. 2 Distillate Oil Storage Tank with 350,000 gallon storage capacity originally qualified as an insignificant activity under Minn. R. 7007.1300, subp. 4.B. The PTE of this storage tank is 0.16 tpy VOC. This allows the storage tank to qualify as an insignificant activity under Minn. R. 7007.1300, subp. 3(I). The maximum vapor pressure as calculated during permit no 01300098-001 is 0.0047 psia which is below the pressure thresholds listed at Minn. R. 7011.1505, subp. 3.C (1) and (2). Minn. R. 7011.1505, subp. 3.C applies due to the storage capacity of the tank, but the facility is not required to comply with paragraphs (1) and (2) due to the vapor pressure. Also, monitoring from Minn. R. 7011.1510 subp. 1.A applies. Since the vapor pressure of the tank is low enough, Minn. R. 7011.1510, subp. 1.B does not apply. Subsequently, Minn. R. 7011.1510, subps. 2 and 3 also do not apply. 40 CFR pt. 60, subp. Kb also does not apply to this tank due to the vapor pressure being below the threshold.

7. 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 listing insignificant activities, parameters used in modeling, an Acid Rain Permit application and TR Trading Program Title V requirements.

8. Comments received

This section will be completed after the public notice and EPA review periods.

Public Notice Period: [start date] – [end date] EPA Review Period: [start date] – [end date]

Comments were [not] received from the public during the public notice period. [The comments received did [not] include adverse comments on any applicable requirements of the permit. Changes to the permit were [not] made as a result of the comments.

The revised permit was sent to EPA for their 45-day review on [date]. Comments were [not] received from EPA during their review period. Changes to the permit were [not] made as a result of the comments.

9. Permit fee assessment

Attachment 3 to this TSD contains the MPCA’s assessment of Application and Additional Points used to determine the permit application fee for this permit action as required by Minn. R. 7002.0019. The permit action includes a major amendment application received after the effective date of the rule (July 1, 2009). The action includes PSD modeling (15 points), BACT review for PM, PM10, PM2.5, CO, NOX, VOC and GHG (105 points), CSAPR (formerly CAIR) and Pt 75 CEM analysis (10 points), NSPS review of subparts IIII, KKKK and TTTT (30 points), NESHAP review of subpart ZZZZ for area sources (10 points), revised limit for hexane to avoid NESHAP major source (10 points), and an AERA review (15 points). There was an Environmental Assessment Worksheet (EAW) done for this project, but it followed Minn. R. 7850.1900, subp. 3 for a Site Permit. The RGU was the Public Utilities Commission and not the PCA so no additional points were charged for EAW review.

10. Conclusion Based on the information provided by Mankato Energy Center LLC the MPCA has reasonable assurance that the proposed operation of the emission facility, as described in the Air Emission Permit No. 01300098-101 and this TSD, will not cause or contribute to a violation of applicable federal regulations and Minnesota Rules. Staff members on permit team: Tarik Hanafy (permit engineer) Sarah Sevcik (peer reviewer) Curt Stock (compliance) Jenna Ness (enforcement) Karen Kromar (environmental review) Jim Sullivan (modeling) Monika Vadali (AERA) Anne Jackson (mercury)

Beckie Olson (permit writing assistant) Laurie O’Brien (administrative support)

TEMPO360 Activities: Major Amendment (IND20150001), Pre-Application (PRE20130001)


AI: 95792

Attachments: 1. Calculation Spreadsheets 2. Requirements Development Report 3. Subject Item Inventory/Details 4. CAM Plans 5. Risk Assessment Screening Spreadsheet 6. MPCA Mercury Risk Estimation Method Spreadsheet 7. ESA/NHPA Response Email from U.S. EPA Region 5 8. BACT Analysis 9. Points calculator

Attachment 1: Calculation Spreadsheets

Mankato Energy CenterFacility ID: 01300098Agency Interest No: 957922015 Air Permit ApplicationEmissions Summary

Description: Formaldehyde, n‐Hexane, and Total HAPs Description: Combined Cycle‐ Combustion Turbine #2 & Duct Burner Description: Combustion Turbine #2 Description: Duct Burners (Combustion Turbine #2)Delta ID No.: GP 004 Delta ID No.: SV 002 Delta ID No.: EU 002 Delta ID No.: EU 004

Tempo ID No.: COMG 5 Tempo ID No.: STRU 14 Tempo ID No.: EQUI 5 Tempo ID No.: EQUI 6Delta SV ID No: ‐ Delta SV ID No: 002 Delta SV ID No: 002 Delta SV ID No: 002

PollutantCAS #

(if applicable) Max rate (lb/hr)Uncontrolled

tpyLimited tpy

Actual tpy Max rate (lb/hr)

Uncontrolled tpy

Limited tpy


Uncontrolled tpy

Limited tpy


Uncontrolled tpy

Limited tpy

Actual tpy

PM ‐ ‐ ‐ ‐ ‐ 72.6 317.99 118.5 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐PM10 ‐ ‐ ‐ ‐ ‐ 72.6 317.99 118.5 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐PM2.5 ‐ ‐ ‐ ‐ ‐ 72.6 317.99 118.5 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐SO2 7446‐09‐5 ‐ ‐ ‐ ‐ 96.77 423.86 67.8 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐NOx ‐ ‐ ‐ ‐ ‐ 63.12 1,672.64 174.13 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐VOC ‐ ‐ ‐ ‐ ‐ 25.4 185.39 262.0 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐CO 630‐08‐0 ‐ ‐ ‐ ‐ 26.15 1,145.18 477.94 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐Pb 7439‐92‐1 ‐ ‐ ‐ ‐ 0.03 0.14 0.02 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

H2SO4 ‐ ‐ ‐ ‐ ‐ 14.69 64.34 10.29 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐CO2 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 365,726 1,601,880 1,066,724 ‐ 93,581 409,884 409,884 ‐CH4 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 14.83 64.98 20.1 ‐ 1.76 7.72 7.72 ‐N2O ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2.97 13.0 2.01 ‐ 0.18 0.77 0.77 ‐SF6 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐CO2e ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 366,981 1,607,377 1,067,825 ‐ 93,678 410,307 410,307 ‐

Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 8.33E‐02 3.65E‐01 3.65E‐01 ‐ ‐ ‐ ‐ ‐Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 1.33E‐02 5.84E‐02 5.84E‐02 ‐ ‐ ‐ ‐ ‐Arsenic 7440‐38‐2 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2.47E‐02 1.08E‐01 1.08E‐02 ‐ 1.57E‐04 6.87E‐04 6.87E‐04 ‐Benzene 71‐43‐2 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 1.23E‐01 5.40E‐01 1.52E‐01 ‐ 1.65E‐03 7.21E‐03 7.21E‐03 ‐

1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 3.59E‐02 1.57E‐01 1.92E‐02 ‐ ‐ ‐ ‐ ‐Beryllium 7440‐41‐7 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 6.95E‐04 3.05E‐03 3.04E‐04 ‐ 9.41E‐06 4.12E‐05 4.12E‐05 ‐Cadmium 7440‐43‐9 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 1.08E‐02 4.72E‐02 4.71E‐03 ‐ 8.63E‐04 3.78E‐03 3.78E‐03 ‐Chromium 7440‐47‐3 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2.47E‐02 1.08E‐01 1.08E‐02 ‐ 1.10E‐03 4.81E‐03 4.81E‐03 ‐

Cobalt 7440‐48‐4 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 6.59E‐05 2.89E‐04 2.89E‐04 ‐Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 9.41E‐04 4.12E‐03 4.12E‐03 ‐

Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 6.66E‐02 2.92E‐01 2.92E‐01 ‐ ‐ ‐ ‐ ‐Formaldehyde 50‐00‐0 see GP 004 units see GP 004 units 9.0 ‐ 8.04 35.22 see GP 004 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

Hexane 110‐54‐3 see GP 004 units see GP 004 units 9.0 ‐ 0.98 4.29 see GP 004 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐Manganese 7439‐96‐5 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 1.77 7.76 0.78 ‐ 2.98E‐04 1.31E‐03 1.31E‐03 ‐

Mercury 7439‐97‐6 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2.69E‐03 1.18E‐02 1.18E‐03 ‐ 2.04E‐04 8.93E‐04 8.93E‐04 ‐Naphthalene 91‐20‐3 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 7.85E‐02 3.44E‐01 4.50E‐02 ‐ 4.78E‐04 2.10E‐03 2.10E‐03 ‐

Nickel 7440‐02‐0 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 1.03E‐02 4.52E‐02 4.51E‐03 ‐ 1.65E‐03 7.21E‐03 7.21E‐03 ‐PAH ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 8.97E‐02 3.93E‐01 5.73E‐02 ‐ ‐ ‐ ‐ ‐POM ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 5.48E‐04 2.40E‐03 2.40E‐03 ‐

Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 6.04E‐02 2.64E‐01 2.64E‐01 ‐ ‐ ‐ ‐ ‐Selenium 7782‐49‐2 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 5.61E‐02 2.46E‐01 2.45E‐02 ‐ 1.88E‐05 8.24E‐05 8.24E‐05 ‐Toluene 108‐88‐3 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 0.27 1.19 1.19 ‐ 2.67E‐03 1.17E‐02 1.17E‐02 ‐Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 0.13 0.58 0.58 ‐ ‐ ‐ ‐ ‐

Total HAPs ‐ ‐ ‐ 22.5 ‐ 9.05 39.65 see GP 004 ‐ 2.78 12.17 see GP 004 ‐ 0.01 0.04 see GP 004 ‐Highest Facility Single HAP: ‐

Formaldehyde 50‐00‐0

Highest Single HAP Emissions ‐ see GP 004 units see GP 004 units 9.0 ‐ 8.04 35.22 see GP 004 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Emissions Summary]


PollutantCAS #

(if applicable)

PM ‐PM10 ‐PM2.5 ‐SO2 7446‐09‐5NOx ‐VOC ‐CO 630‐08‐0Pb 7439‐92‐1

H2SO4 ‐CO2 ‐CH4 ‐N2O ‐SF6 ‐CO2e ‐

Acetaldehyde 75‐07‐0Acrolein 107‐02‐8Arsenic 7440‐38‐2Benzene 71‐43‐2

1,3‐Butadiene 106‐99‐0Beryllium 7440‐41‐7Cadmium 7440‐43‐9Chromium 7440‐47‐3

Cobalt 7440‐48‐4Dichlorobenzene 25321‐22‐6

Ethylbenzene 100‐41‐4Formaldehyde 50‐00‐0

Hexane 110‐54‐3Manganese 7439‐96‐5

Mercury 7439‐97‐6Naphthalene 91‐20‐3

Nickel 7440‐02‐0PAH ‐POM ‐

Propylene Oxide 75‐56‐9Selenium 7782‐49‐2Toluene 108‐88‐3Xylenes 1330‐20‐7

Total HAPs ‐Highest Facility Single HAP: ‐


Highest Single HAP Emissions ‐

Description: Combined Cycle‐ Combustion Turbine #1 & Duct Burner Description: Combustion Turbine #1 Description: Duct Burners (Combustion Turbine #1)Delta ID No.: SV 007 Delta ID No.: EU 008 Delta ID No.: EU 009

Tempo ID No.: STRU 20 Tempo ID No.: EQUI 16 Tempo ID No.: EQUI 17Delta SV ID No: 007 Delta SV ID No: 007 Delta SV ID No: 007

Max rate (lb/hr)Uncontrolled

tpyLimited tpy


Uncontrolled tpy

Limited tpy


Uncontrolled tpy

Limited tpy

Actual tpy

11.9 52.12 52.12 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐11.9 52.12 52.12 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐11.9 52.12 52.12 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐6.9 30.2 30.2 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

34.05 1,045.67 166.78 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐13.42 425.54 382.54 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐27.64 1,288.13 767.98 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

1.51E‐03 6.61E‐03 6.61E‐03 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐1.05 4.58 4.58 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

‐ ‐ ‐ ‐ 263,582 1,154,490 1,154,490 ‐ 96,353 422,027 422,027 ‐‐ ‐ ‐ ‐ 4.97 21.76 21.76 ‐ 1.82 7.95 7.95 ‐‐ ‐ ‐ ‐ 0.5 2.18 2.18 ‐ 0.18 0.8 0.8 ‐

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ 263,854 1,155,682 1,155,682 ‐ 96,453 422,463 422,463 ‐‐ ‐ ‐ ‐ 9.01E‐02 3.95E‐01 3.95E‐01 ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ 1.44E‐02 6.32E‐02 6.32E‐02 ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 1.62E‐04 7.07E‐04 7.07E‐04 ‐‐ ‐ ‐ ‐ 2.70E‐02 1.18E‐01 1.18E‐01 ‐ 1.70E‐03 7.43E‐03 7.43E‐03 ‐‐ ‐ ‐ ‐ 9.67E‐04 4.23E‐03 4.23E‐03 ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 9.69E‐06 4.24E‐05 4.24E‐05 ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 8.88E‐04 3.89E‐03 3.89E‐03 ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 1.13E‐03 4.95E‐03 4.95E‐03 ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 6.78E‐05 2.97E‐04 2.97E‐04 ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 9.69E‐04 4.24E‐03 4.24E‐03 ‐‐ ‐ ‐ ‐ 7.21E‐02 3.16E‐01 3.16E‐01 ‐ ‐ ‐ ‐ ‐

8.58 37.6 see GP 004 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐1.05 4.58 see GP 004 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 3.07E‐04 1.34E‐03 1.34E‐03 ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2.10E‐04 9.20E‐04 9.20E‐04 ‐‐ ‐ ‐ ‐ 2.93E‐03 1.28E‐02 1.28E‐02 ‐ 4.93E‐04 2.16E‐03 2.16E‐03 ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 1.70E‐03 7.43E‐03 7.43E‐03 ‐‐ ‐ ‐ ‐ 4.96E‐03 2.17E‐02 2.17E‐02 ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 5.64E‐04 2.47E‐03 2.47E‐03 ‐‐ ‐ ‐ ‐ 6.53E‐02 2.86E‐01 2.86E‐01 ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 1.94E‐05 8.49E‐05 8.49E‐05 ‐‐ ‐ ‐ ‐ 0.29 1.28 1.28 ‐ 2.75E‐03 1.20E‐02 1.20E‐02 ‐‐ ‐ ‐ ‐ 0.14 0.63 0.63 ‐ ‐ ‐ ‐ ‐

9.63 42.19 see GP 004 ‐ 0.71 3.12 see GP 004 ‐ 0.01 0.05 see GP 004 ‐

8.58 37.6 see GP 004 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐



PollutantCAS #

(if applicable)














Description: Auxiliary Boiler Description: Fire Pump Engine Description: Diesel Fired Emergency Generator Description: Bath HeaterDelta ID No.: EU 005 Delta ID No.: EU 007 Delta ID No.: EU 010 Delta ID No.: EU 011

Tempo ID No.: EQUI 7 Tempo ID No.: EQUI 11 Tempo ID No.: EQUI 18 Tempo ID No.: EQUI 19Delta SV ID No: 003 Delta SV ID No: 005 Delta SV ID No: 008 Delta SV ID No: 009


tpyLimited tpy


Uncontrolled tpy

Limited tpy


Uncontrolled tpy

Limited tpy


Uncontrolled tpy

Limited tpy

Actual tpy

0.56 2.45 2.45 ‐ 0.08 0.004 0.004 ‐ 0.15 0.04 0.01 ‐ 0.02 0.09 0.09 ‐0.56 2.45 2.45 ‐ 0.08 0.004 0.004 ‐ 0.15 0.04 0.01 ‐ 0.02 0.09 0.09 ‐0.56 2.45 2.45 ‐ 0.08 0.004 0.004 ‐ 0.15 0.04 0.01 ‐ 0.02 0.09 0.09 ‐0.07 0.31 0.31 ‐ 0.12 0.006 0.006 ‐ 5.13 1.28 0.26 ‐ 0.002 0.01 0.01 ‐2.52 11.04 11.04 ‐ 3.37 0.169 0.169 ‐ 13.27 3.32 0.66 ‐ 0.28 1.23 1.23 ‐0.49 2.15 2.15 ‐ 0.15 0.008 0.008 ‐ 0.72 0.18 0.04 ‐ 0.02 0.07 0.07 ‐4.2 18.4 18.4 ‐ 0.48 0.024 0.024 ‐ 13.27 3.32 0.66 ‐ 0.24 1.04 1.04 ‐

3.43E‐05 1.50E‐04 1.50E‐04 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 1.41E‐06 6.16E‐06 6.16E‐06 ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

8,188 35,865 35,865 ‐ 399 20 20 ‐ 4,148 1,037 207 ‐ 336 1,470 1,470 ‐0.15 0.68 0.68 ‐ 1.62E‐02 8.10E‐04 8.10E‐04 ‐ 1.68E‐01 4.21E‐02 8.41E‐03 ‐ 6.33E‐03 2.77E‐02 2.77E‐02 ‐0.02 0.07 0.07 ‐ 3.24E‐03 1.62E‐04 1.62E‐04 ‐ 3.36E‐02 8.41E‐03 1.68E‐03 ‐ 6.33E‐04 2.77E‐03 2.77E‐03 ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

8,197 35,902 35,902 ‐ 401 20 20 ‐ 4,162 1,040 208 ‐ 336 1,472 1,472 ‐‐ ‐ ‐ ‐ 1.88E‐03 9.40E‐05 9.40E‐05 ‐ 6.41E‐04 1.60E‐04 3.21E‐05 ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ 2.27E‐04 1.13E‐05 1.13E‐05 ‐ 2.00E‐04 5.01E‐05 1.00E‐05 ‐ ‐ ‐ ‐ ‐

1.37E‐05 6.01E‐05 6.01E‐05 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 5.63E‐07 2.46E‐06 2.46E‐06 ‐1.44E‐04 6.31E‐04 6.31E‐04 ‐ 2.29E‐03 1.14E‐04 1.14E‐04 ‐ 1.97E‐02 4.93E‐03 9.87E‐04 ‐ 5.91E‐06 2.59E‐05 2.59E‐05 ‐

‐ ‐ ‐ ‐ 9.58E‐05 4.79E‐06 4.79E‐06 ‐ 9.95E‐04 2.49E‐04 4.97E‐05 ‐ ‐ ‐ ‐ ‐8.24E‐07 3.61E‐06 3.61E‐06 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 3.38E‐08 1.48E‐07 1.48E‐07 ‐7.55E‐05 3.31E‐04 3.31E‐04 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 3.10E‐06 1.36E‐05 1.36E‐05 ‐9.61E‐05 4.21E‐04 4.21E‐04 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 3.94E‐06 1.73E‐05 1.73E‐05 ‐5.76E‐06 2.52E‐05 2.52E‐05 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2.36E‐07 1.04E‐06 1.04E‐06 ‐8.24E‐05 3.61E‐04 3.61E‐04 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 3.38E‐06 1.48E‐05 1.48E‐05 ‐

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐5.15E‐03 2.25E‐02 see GP 004 ‐ 2.89E‐03 1.45E‐04 see GP 004 ‐ 2.01E‐03 5.02E‐04 see GP 004 ‐ 2.11E‐04 9.24E‐04 see GP 004 ‐0.12 0.54 see GP 004 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 5.06E‐03 2.22E‐02 see GP 004 ‐

2.61E‐05 1.14E‐04 1.14E‐04 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 1.07E‐06 4.68E‐06 4.68E‐06 ‐1.78E‐05 7.82E‐05 7.82E‐05 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 7.32E‐07 3.20E‐06 3.20E‐06 ‐4.19E‐05 1.83E‐04 1.83E‐04 ‐ 2.08E‐04 1.04E‐05 1.04E‐05 ‐ 3.31E‐03 8.27E‐04 1.65E‐04 ‐ 1.72E‐06 7.52E‐06 7.52E‐06 ‐1.44E‐04 6.31E‐04 6.31E‐04 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 5.91E‐06 2.59E‐05 2.59E‐05 ‐

‐ ‐ ‐ ‐ 4.12E‐04 2.06E‐05 2.06E‐05 ‐ 5.39E‐03 1.35E‐03 2.70E‐04 ‐ ‐ ‐ ‐ ‐4.79E‐05 2.10E‐04 2.10E‐04 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 1.96E‐06 8.60E‐06 8.60E‐06 ‐

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐1.65E‐06 7.21E‐06 7.21E‐06 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 6.75E‐08 2.96E‐07 2.96E‐07 ‐2.33E‐04 1.02E‐03 1.02E‐03 ‐ 1.00E‐03 5.01E‐05 5.01E‐05 ‐ 7.15E‐03 1.79E‐03 3.57E‐04 ‐ 9.57E‐06 4.19E‐05 4.19E‐05 ‐

‐ ‐ ‐ ‐ 6.98E‐04 3.49E‐05 3.49E‐05 ‐ 4.91E‐03 1.23E‐03 2.45E‐04 ‐ ‐ ‐ ‐ ‐1.30E‐01 5.68E‐01 see GP 004 ‐ 9.49E‐03 4.75E‐04 see GP 004 ‐ 4.10E‐02 1.03E‐02 see GP 004 ‐ 5.31E‐03 2.33E‐02 see GP 004 ‐

0.01 0.02 see GP 004 ‐ 2.89E‐03 1.45E‐04 see GP 004 ‐ 2.01E‐03 5.02E‐04 see GP 004 ‐ 2.11E‐04 9.24E‐04 see GP 004 ‐



PollutantCAS #

(if applicable)














Description: Cooling Tower Description: Natural Gas Fugitives Description: Breaker FugitivesDelta ID No.: FS 001 Delta ID No.: FS 002 Delta ID No.: FS 003

Tempo ID No.: FUGI 1 Tempo ID No.: FUGI 2 Tempo ID No.: FUGI 3Delta SV ID No: NA Delta SV ID No: NA Delta SV ID No: NA


tpyLimited tpy


Uncontrolled tpy

Limited tpy


Uncontrolled tpy

Limited tpy

Actual tpy

3.62 15.87 15.87 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐0.62 2.7 2.7 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

0.004836 0.02 0.02 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

‐ ‐ ‐ ‐ 6.39E‐01 2.80E+00 2.80E+00 ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ 60.88 266.65 266.65 ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 3.27E‐04 1.43E‐03 1.43E‐03 ‐‐ ‐ ‐ ‐ 1,522.63 6,669 6,669 ‐ 7.46 32.66 32.66 ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐



PollutantCAS #

(if applicable)














Description: Fuel Oil Storage Tank Description: Fire Pump Fuel Tank Description: Emergency Generator Diesel Fuel Tank Description: Natural Gas Condensate Tank ‐ PlantDelta ID No.: TK 001 Delta ID No.: TK NA, Insignificant Activity Delta ID No.: TK NA, Insignificant Activity Delta ID No.: TK NA, Insignificant Activity

Tempo ID No.: NA, Insignificant Activity Tempo ID No.: NA, Insignificant Activity Tempo ID No.: EQUI 23 Tempo ID No.: EQUI 24Delta SV ID No: NA Delta SV ID No: NA Delta SV ID No: NA Delta SV ID No: NA


tpyLimited tpy


Uncontrolled tpy

Limited tpy


Uncontrolled tpy

Limited tpy


Uncontrolled tpy

Limited tpy

Actual tpy

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

0.04 0.16 0.16 ‐ 5.71E‐06 2.50E‐05 2.50E‐05 ‐ 6.28E‐05 2.75E‐04 2.75E‐04 ‐ 0.01 0.05 0.05 ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐



PollutantCAS #

(if applicable)














Description: Natural Gas Condensate Tank ‐ CT1 Description: Natural Gas Condensate Tank ‐ CT2Delta ID No.: TK NA, Insignificant Activity Delta ID No.: TK NA, Insignificant Activity

Tempo ID No.: NA, Insignificant Activity Tempo ID No.: NA, Insignificant Activity

Delta SV ID No: NA Delta SV ID No: NA


tpyLimited tpy


Uncontrolled tpy

Limited tpy

Actual tpy

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

3.76E‐04 1.65E‐03 1.65E‐03 ‐ 3.76E‐04 1.65E‐03 1.65E‐03 ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐



PollutantCAS #

(if applicable)














Facility Total EmissionsUncontrolled

tpyLimited tpy

Actual tpy

388.57 189.05 ‐375.40 175.88 ‐372.72 173.20 ‐455.66 98.58 ‐

2,734.06 354.01 ‐613.54 647.01 ‐

2,456.09 1,266.03 ‐0.15 0.026 ‐

68.92 14.88 ‐

3,626,677 3,090,690 ‐369.81 324.91 ‐16.82 5.83 ‐

1.43E‐03 1.43E‐03 ‐3,640,966 3,100,582 ‐7.60E‐01 7.60E‐01 ‐1.22E‐01 1.22E‐01 ‐1.10E‐01 1.23E‐02 ‐6.79E‐01 2.87E‐01 ‐1.62E‐01 2.35E‐02 ‐3.13E‐03 3.92E‐04 ‐5.52E‐02 1.27E‐02 ‐1.18E‐01 2.10E‐02 ‐6.12E‐04 6.12E‐04 ‐8.74E‐03 8.74E‐03 ‐6.08E‐01 6.08E‐01 ‐

72.84 9.00 ‐9.44 9.00 ‐7.76 0.78 ‐

1.37E‐02 3.07E‐03 ‐3.62E‐01 6.25E‐02 ‐6.05E‐02 1.98E‐02 ‐4.16E‐01 7.93E‐02 ‐5.09E‐03 5.09E‐03 ‐5.51E‐01 5.51E‐01 ‐2.46E‐01 2.47E‐02 ‐

2.50 2.49 ‐1.22 1.22 ‐

97.82 22.50 ‐

72.84 9.00 ‐


Alternate Format GI-07 SpreadsheetFacility Emissions Summary

Air Quality Permit ProgramDoc Type: Permit Application

01300098 1b) Agency Interest ID No.: 957922) Facility Name: Mankato Energy Center

Emissions by Source Table If multiple copies of these tables are used, indicate which number this page is over the total number of pages of these tables (e.g., 1/3): 1/6

3a) Delta ID No.: GP 004 3a) Delta ID No.: SV 002 3a) Delta ID No.: EU 002

3b) Tempo SI ID No.: COMG 5 3b) Tempo SI ID No.: STRU 14 3b) Tempo SI ID No.: EQUI 53c) 3d) 3f) 3c) 3d) 3f) 3c) 3d) 3f)

Pollutant Name CAS #Lbs per

HrUnc tpy

Limited tpy

Actual tpy Pollutant Name CAS #

Lbs per Hr

Unc tpy

Limited tpy


Lbs per Hr

Unc tpy

Limited tpy

Actual tpy

PM ‐ ‐ ‐ ‐ ‐ PM ‐ 72.6 317.99 118.5 ‐ PM ‐ ‐ ‐ ‐ ‐PM10 ‐ ‐ ‐ ‐ ‐ PM10 ‐ 72.6 317.99 118.5 ‐ PM10 ‐ ‐ ‐ ‐ ‐PM2.5 ‐ ‐ ‐ ‐ ‐ PM2.5 ‐ 72.6 317.99 118.5 ‐ PM2.5 ‐ ‐ ‐ ‐ ‐SO2 7446‐09‐5 ‐ ‐ ‐ ‐ SO2 7446‐09‐5 96.77 423.86 67.8 ‐ SO2 7446‐09‐5 ‐ ‐ ‐ ‐NOx ‐ ‐ ‐ ‐ ‐ NOx ‐ 63.12 1,672.64 174.13 ‐ NOx ‐ ‐ ‐ ‐ ‐VOC ‐ ‐ ‐ ‐ ‐ VOC ‐ 25.4 185.39 262.0 ‐ VOC ‐ ‐ ‐ ‐ ‐CO 630‐08‐0 ‐ ‐ ‐ ‐ CO 630‐08‐0 26.15 1,145.18 477.94 ‐ CO 630‐08‐0 ‐ ‐ ‐ ‐Pb 7439‐92‐1 ‐ ‐ ‐ ‐ Pb 7439‐92‐1 3.18E‐02 1.39E‐01 1.95E‐02 ‐ Pb 7439‐92‐1 ‐ ‐ ‐ ‐H2SO4 ‐ ‐ ‐ ‐ ‐ H2SO4 ‐ 14.69 64.34 10.29 ‐ H2SO4 ‐ ‐ ‐ ‐ ‐CO2 ‐ ‐ ‐ ‐ ‐ CO2 ‐ ‐ ‐ ‐ ‐ CO2 ‐ 365,726 1,601,880 1,066,724 ‐CH4 ‐ ‐ ‐ ‐ ‐ CH4 ‐ ‐ ‐ ‐ ‐ CH4 ‐ 14.83 64.98 20.1 ‐N2O ‐ ‐ ‐ ‐ ‐ N2O ‐ ‐ ‐ ‐ ‐ N2O ‐ 2.97 13.0 2.01 ‐SF6 ‐ ‐ ‐ ‐ ‐ SF6 ‐ ‐ ‐ ‐ ‐ SF6 ‐ ‐ ‐ ‐ ‐CO2e ‐ ‐ ‐ ‐ ‐ CO2e ‐ ‐ ‐ ‐ ‐ CO2e ‐ 366,981 1,607,377 1,067,825 ‐

Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ Acetaldehyde 75‐07‐0 8.33E‐02 3.65E‐01 3.65E‐01 ‐Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ Acrolein 107‐02‐8 1.33E‐02 5.84E‐02 5.84E‐02 ‐Arsenic 7440‐38‐2 ‐ ‐ ‐ ‐ Arsenic 7440‐38‐2 ‐ ‐ ‐ ‐ Arsenic 7440‐38‐2 2.47E‐02 1.08E‐01 1.08E‐02 ‐Benzene 71‐43‐2 ‐ ‐ ‐ ‐ Benzene 71‐43‐2 ‐ ‐ ‐ ‐ Benzene 71‐43‐2 1.23E‐01 5.40E‐01 1.52E‐01 ‐

1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐ 1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐ 1,3‐Butadiene 106‐99‐0 3.59E‐02 1.57E‐01 1.92E‐02 ‐Beryllium 7440‐41‐7 ‐ ‐ ‐ ‐ Beryllium 7440‐41‐7 ‐ ‐ ‐ ‐ Beryllium 7440‐41‐7 6.95E‐04 3.05E‐03 3.04E‐04 ‐Cadmium 7440‐43‐9 ‐ ‐ ‐ ‐ Cadmium 7440‐43‐9 ‐ ‐ ‐ ‐ Cadmium 7440‐43‐9 1.08E‐02 4.72E‐02 4.71E‐03 ‐Chromium 7440‐47‐3 ‐ ‐ ‐ ‐ Chromium 7440‐47‐3 ‐ ‐ ‐ ‐ Chromium 7440‐47‐3 2.47E‐02 1.08E‐01 1.08E‐02 ‐

Cobalt 7440‐48‐4 ‐ ‐ ‐ ‐ Cobalt 7440‐48‐4 ‐ ‐ ‐ ‐ Cobalt 7440‐48‐4 ‐ ‐ ‐ ‐Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐ Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐ Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐

Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ Ethylbenzene 100‐41‐4 6.66E‐02 2.92E‐01 2.92E‐01 ‐Formaldehyde 50‐00‐0 see GP 004 units see GP 004 units 9.00E+00 ‐ Formaldehyde 50‐00‐0 8.04E+00 3.52E+01 see GP 004 ‐ Formaldehyde 50‐00‐0 ‐ ‐ ‐ ‐

Hexane 110‐54‐3 see GP 004 units see GP 004 units 9.00E+00 ‐ Hexane 110‐54‐3 9.80E‐01 4.29E+00 see GP 004 ‐ Hexane 110‐54‐3 ‐ ‐ ‐ ‐Manganese 7439‐96‐5 ‐ ‐ ‐ ‐ Manganese 7439‐96‐5 ‐ ‐ ‐ ‐ Manganese 7439‐96‐5 1.77E+00 7.76E+00 7.75E‐01 ‐

Mercury 7439‐97‐6 ‐ ‐ ‐ ‐ Mercury 7439‐97‐6 ‐ ‐ ‐ ‐ Mercury 7439‐97‐6 2.69E‐03 1.18E‐02 1.18E‐03 ‐Naphthalene 91‐20‐3 ‐ ‐ ‐ ‐ Naphthalene 91‐20‐3 ‐ ‐ ‐ ‐ Naphthalene 91‐20‐3 7.85E‐02 3.44E‐01 4.50E‐02 ‐

Nickel 7440‐02‐0 ‐ ‐ ‐ ‐ Nickel 7440‐02‐0 ‐ ‐ ‐ ‐ Nickel 7440‐02‐0 1.03E‐02 4.52E‐02 4.51E‐03 ‐PAH ‐ ‐ ‐ ‐ ‐ PAH ‐ ‐ ‐ ‐ ‐ PAH ‐ 8.97E‐02 3.93E‐01 5.73E‐02 ‐POM ‐ ‐ ‐ ‐ ‐ POM ‐ ‐ ‐ ‐ ‐ POM ‐ ‐ ‐ ‐ ‐

Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ Propylene Oxide 75‐56‐9 6.04E‐02 2.64E‐01 2.64E‐01 ‐Selenium 7782‐49‐2 ‐ ‐ ‐ ‐ Selenium 7782‐49‐2 ‐ ‐ ‐ ‐ Selenium 7782‐49‐2 5.61E‐02 2.46E‐01 2.45E‐02 ‐Toluene 108‐88‐3 ‐ ‐ ‐ ‐ Toluene 108‐88‐3 ‐ ‐ ‐ ‐ Toluene 108‐88‐3 2.71E‐01 1.19E+00 1.19E+00 ‐Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ Xylenes 1330‐20‐7 1.33E‐01 5.84E‐01 5.84E‐01 ‐

Total HAPs ‐ ‐ ‐ 2.25E+01 ‐ Total HAPs ‐ 9.05E+00 3.96E+01 see GP 004 ‐ Total HAPs ‐ 2.78E+00 1.22E+01 see GP 004 ‐

5)

1a) AQ Facility ID No.:

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.





3a) Delta ID No.: EU 004 3a) Delta ID No.: SV 007 3a) Delta ID No.: EU 008

3b) Tempo SI ID No.: EQUI 6 3b) Tempo SI ID No.: STRU 20 3b) Tempo SI ID No.: EQUI 163c) 3d) 3f) 3c) 3d) 3f) 3c) 3d) 3f)


HrUnc tpy

Limited tpy


Lbs per Hr

Unc tpy

Limited tpy


Lbs per Hr

Unc tpy

Limited tpy

Actual tpy

PM ‐ ‐ ‐ ‐ ‐ PM ‐ 11.9 52.12 52.12 ‐ PM ‐ ‐ ‐ ‐ ‐PM10 ‐ ‐ ‐ ‐ ‐ PM10 ‐ 11.9 52.12 52.12 ‐ PM10 ‐ ‐ ‐ ‐ ‐PM2.5 ‐ ‐ ‐ ‐ ‐ PM2.5 ‐ 11.9 52.12 52.12 ‐ PM2.5 ‐ ‐ ‐ ‐ ‐SO2 7446‐09‐5 ‐ ‐ ‐ ‐ SO2 7446‐09‐5 6.9 30.2 30.2 ‐ SO2 7446‐09‐5 ‐ ‐ ‐ ‐NOx ‐ ‐ ‐ ‐ ‐ NOx ‐ 34.05 1,045.67 166.78 ‐ NOx ‐ ‐ ‐ ‐ ‐VOC ‐ ‐ ‐ ‐ ‐ VOC ‐ 13.42 425.54 382.54 ‐ VOC ‐ ‐ ‐ ‐ ‐CO 630‐08‐0 ‐ ‐ ‐ ‐ CO 630‐08‐0 27.635 1,288.13 767.98 ‐ CO 630‐08‐0 ‐ ‐ ‐ ‐Pb 7439‐92‐1 ‐ ‐ ‐ ‐ Pb 7439‐92‐1 1.51E‐03 6.61E‐03 6.61E‐03 ‐ Pb 7439‐92‐1 ‐ ‐ ‐ ‐H2SO4 ‐ ‐ ‐ ‐ ‐ H2SO4 ‐ 1.05 4.58 4.58 ‐ H2SO4 ‐ ‐ ‐ ‐ ‐CO2 ‐ 93,581 409,884 409,884 ‐ CO2 ‐ ‐ ‐ ‐ ‐ CO2 ‐ 263,582 1,154,490 1,154,490 ‐CH4 ‐ 1.76 7.72 7.72 ‐ CH4 ‐ ‐ ‐ ‐ ‐ CH4 ‐ 4.97 21.76 21.76 ‐N2O ‐ 0.18 0.77 0.77 ‐ N2O ‐ ‐ ‐ ‐ ‐ N2O ‐ 0.5 2.18 2.18 ‐SF6 ‐ ‐ ‐ ‐ ‐ SF6 ‐ ‐ ‐ ‐ ‐ SF6 ‐ ‐ ‐ ‐ ‐CO2e ‐ 93,678 410,307 410,307 ‐ CO2e ‐ ‐ ‐ ‐ ‐ CO2e ‐ 263,854 1,155,682 1,155,682 ‐

Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ Acetaldehyde 75‐07‐0 9.01E‐02 3.95E‐01 3.95E‐01 ‐Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ Acrolein 107‐02‐8 1.44E‐02 6.32E‐02 6.32E‐02 ‐Arsenic 7440‐38‐2 1.57E‐04 6.87E‐04 6.87E‐04 ‐ Arsenic 7440‐38‐2 ‐ ‐ ‐ ‐ Arsenic 7440‐38‐2 ‐ ‐ ‐ ‐Benzene 71‐43‐2 1.65E‐03 7.21E‐03 7.21E‐03 ‐ Benzene 71‐43‐2 ‐ ‐ ‐ ‐ Benzene 71‐43‐2 2.70E‐02 1.18E‐01 1.18E‐01 ‐

1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐ 1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐ 1,3‐Butadiene 106‐99‐0 9.67E‐04 4.23E‐03 4.23E‐03 ‐Beryllium 7440‐41‐7 9.41E‐06 4.12E‐05 4.12E‐05 ‐ Beryllium 7440‐41‐7 ‐ ‐ ‐ ‐ Beryllium 7440‐41‐7 ‐ ‐ ‐ ‐Cadmium 7440‐43‐9 8.63E‐04 3.78E‐03 3.78E‐03 ‐ Cadmium 7440‐43‐9 ‐ ‐ ‐ ‐ Cadmium 7440‐43‐9 ‐ ‐ ‐ ‐Chromium 7440‐47‐3 1.10E‐03 4.81E‐03 4.81E‐03 ‐ Chromium 7440‐47‐3 ‐ ‐ ‐ ‐ Chromium 7440‐47‐3 ‐ ‐ ‐ ‐

Cobalt 7440‐48‐4 6.59E‐05 2.89E‐04 2.89E‐04 ‐ Cobalt 7440‐48‐4 ‐ ‐ ‐ ‐ Cobalt 7440‐48‐4 ‐ ‐ ‐ ‐Dichlorobenzene 25321‐22‐6 9.41E‐04 4.12E‐03 4.12E‐03 ‐ Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐ Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐

Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ Ethylbenzene 100‐41‐4 7.21E‐02 3.16E‐01 3.16E‐01 ‐Formaldehyde 50‐00‐0 ‐ ‐ ‐ ‐ Formaldehyde 50‐00‐0 8.58E+00 3.76E+01 see GP 004 ‐ Formaldehyde 50‐00‐0 ‐ ‐ ‐ ‐

Hexane 110‐54‐3 ‐ ‐ ‐ ‐ Hexane 110‐54‐3 1.05E+00 4.58E+00 see GP 004 ‐ Hexane 110‐54‐3 ‐ ‐ ‐ ‐Manganese 7439‐96‐5 2.98E‐04 1.31E‐03 1.31E‐03 ‐ Manganese 7439‐96‐5 ‐ ‐ ‐ ‐ Manganese 7439‐96‐5 ‐ ‐ ‐ ‐

Mercury 7439‐97‐6 2.04E‐04 8.93E‐04 8.93E‐04 ‐ Mercury 7439‐97‐6 ‐ ‐ ‐ ‐ Mercury 7439‐97‐6 ‐ ‐ ‐ ‐Naphthalene 91‐20‐3 4.78E‐04 2.10E‐03 2.10E‐03 ‐ Naphthalene 91‐20‐3 ‐ ‐ ‐ ‐ Naphthalene 91‐20‐3 2.93E‐03 1.28E‐02 1.28E‐02 ‐

Nickel 7440‐02‐0 1.65E‐03 7.21E‐03 7.21E‐03 ‐ Nickel 7440‐02‐0 ‐ ‐ ‐ ‐ Nickel 7440‐02‐0 ‐ ‐ ‐ ‐PAH ‐ ‐ ‐ ‐ ‐ PAH ‐ ‐ ‐ ‐ ‐ PAH ‐ 4.96E‐03 2.17E‐02 2.17E‐02 ‐POM ‐ 5.48E‐04 2.40E‐03 2.40E‐03 ‐ POM ‐ ‐ ‐ ‐ ‐ POM ‐ ‐ ‐ ‐ ‐

Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ Propylene Oxide 75‐56‐9 6.53E‐02 2.86E‐01 2.86E‐01 ‐Selenium 7782‐49‐2 1.88E‐05 8.24E‐05 8.24E‐05 ‐ Selenium 7782‐49‐2 ‐ ‐ ‐ ‐ Selenium 7782‐49‐2 ‐ ‐ ‐ ‐Toluene 108‐88‐3 2.67E‐03 1.17E‐02 1.17E‐02 ‐ Toluene 108‐88‐3 ‐ ‐ ‐ ‐ Toluene 108‐88‐3 2.93E‐01 1.28E+00 1.28E+00 ‐Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ Xylenes 1330‐20‐7 1.44E‐01 6.32E‐01 6.32E‐01 ‐

Total HAPs ‐ 1.02E‐02 4.45E‐02 see GP 004 ‐ Total HAPs ‐ 9.63E+00 4.22E+01 see GP 004 ‐ Total HAPs ‐ 7.12E‐01 3.12E+00 see GP 004 ‐







3a) Delta ID No.: EU 009 3a) Delta ID No.: EU 005 3a) Delta ID No.: EU 007

3b) Tempo SI ID No.: EQUI 17 3b) Tempo SI ID No.: EQUI 7 3b) Tempo SI ID No.: EQUI 113c) 3d) 3f) 3c) 3d) 3f) 3c) 3d) 3f)


HrUnc tpy

Limited tpy


Lbs per Hr

Unc tpy

Limited tpy


Lbs per Hr

Unc tpy

Limited tpy

Actual tpy

PM ‐ ‐ ‐ ‐ ‐ PM ‐ 0.56 2.45 2.45 ‐ PM ‐ 8.49E‐02 4.24E‐03 4.24E‐03 ‐PM10 ‐ ‐ ‐ ‐ ‐ PM10 ‐ 0.56 2.45 2.45 ‐ PM10 ‐ 8.49E‐02 4.24E‐03 4.24E‐03 ‐PM2.5 ‐ ‐ ‐ ‐ ‐ PM2.5 ‐ 0.56 2.45 2.45 ‐ PM2.5 ‐ 8.49E‐02 4.24E‐03 4.24E‐03 ‐SO2 7446‐09‐5 ‐ ‐ ‐ ‐ SO2 7446‐09‐5 0.07 0.31 0.31 ‐ SO2 7446‐09‐5 1.16E‐01 5.79E‐03 5.79E‐03 ‐NOx ‐ ‐ ‐ ‐ ‐ NOx ‐ 2.52 11.04 11.04 ‐ NOx ‐ 3.37 0.17 0.17 ‐VOC ‐ ‐ ‐ ‐ ‐ VOC ‐ 0.49 2.15 2.15 ‐ VOC ‐ 1.54E‐01 7.72E‐03 7.72E‐03 ‐CO 630‐08‐0 ‐ ‐ ‐ ‐ CO 630‐08‐0 4.2 18.4 18.4 ‐ CO 630‐08‐0 0.478 0.02 0.02 ‐Pb 7439‐92‐1 ‐ ‐ ‐ ‐ Pb 7439‐92‐1 3.43E‐05 1.50E‐04 1.50E‐04 ‐ Pb 7439‐92‐1 ‐ ‐ ‐ ‐H2SO4 ‐ ‐ ‐ ‐ ‐ H2SO4 ‐ ‐ ‐ ‐ ‐ H2SO4 ‐ ‐ ‐ ‐ ‐CO2 ‐ 96,353 422,027 422,027 ‐ CO2 ‐ 8,188 35,865 35,865 ‐ CO2 ‐ 399 20 20 ‐CH4 ‐ 1.82 7.95 7.95 ‐ CH4 ‐ 0.15 0.68 0.68 ‐ CH4 ‐ 1.62E‐02 8.10E‐04 8.10E‐04 ‐N2O ‐ 0.18 0.8 0.8 ‐ N2O ‐ 0.02 0.07 0.07 ‐ N2O ‐ 3.24E‐03 1.62E‐04 1.62E‐04 ‐SF6 ‐ ‐ ‐ ‐ ‐ SF6 ‐ ‐ ‐ ‐ ‐ SF6 ‐ ‐ ‐ ‐ ‐CO2e ‐ 96,453 422,463 422,463 ‐ CO2e ‐ 8,197 35,902 35,902 ‐ CO2e ‐ 401 20 20 ‐

Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ Acetaldehyde 75‐07‐0 1.88E‐03 9.40E‐05 9.40E‐05 ‐Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ Acrolein 107‐02‐8 2.27E‐04 1.13E‐05 1.13E‐05 ‐Arsenic 7440‐38‐2 1.62E‐04 7.07E‐04 7.07E‐04 ‐ Arsenic 7440‐38‐2 1.37E‐05 6.01E‐05 6.01E‐05 ‐ Arsenic 7440‐38‐2 ‐ ‐ ‐ ‐Benzene 71‐43‐2 1.70E‐03 7.43E‐03 7.43E‐03 ‐ Benzene 71‐43‐2 1.44E‐04 6.31E‐04 6.31E‐04 ‐ Benzene 71‐43‐2 2.29E‐03 1.14E‐04 1.14E‐04 ‐

1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐ 1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐ 1,3‐Butadiene 106‐99‐0 9.58E‐05 4.79E‐06 4.79E‐06 ‐Beryllium 7440‐41‐7 9.69E‐06 4.24E‐05 4.24E‐05 ‐ Beryllium 7440‐41‐7 8.24E‐07 3.61E‐06 3.61E‐06 ‐ Beryllium 7440‐41‐7 ‐ ‐ ‐ ‐Cadmium 7440‐43‐9 8.88E‐04 3.89E‐03 3.89E‐03 ‐ Cadmium 7440‐43‐9 7.55E‐05 3.31E‐04 3.31E‐04 ‐ Cadmium 7440‐43‐9 ‐ ‐ ‐ ‐Chromium 7440‐47‐3 1.13E‐03 4.95E‐03 4.95E‐03 ‐ Chromium 7440‐47‐3 9.61E‐05 4.21E‐04 4.21E‐04 ‐ Chromium 7440‐47‐3 ‐ ‐ ‐ ‐

Cobalt 7440‐48‐4 6.78E‐05 2.97E‐04 2.97E‐04 ‐ Cobalt 7440‐48‐4 5.76E‐06 2.52E‐05 2.52E‐05 ‐ Cobalt 7440‐48‐4 ‐ ‐ ‐ ‐Dichlorobenzene 25321‐22‐6 9.69E‐04 4.24E‐03 4.24E‐03 ‐ Dichlorobenzene 25321‐22‐6 8.24E‐05 3.61E‐04 3.61E‐04 ‐ Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐

Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐Formaldehyde 50‐00‐0 ‐ ‐ ‐ ‐ Formaldehyde 50‐00‐0 5.15E‐03 2.25E‐02 see GP 004 ‐ Formaldehyde 50‐00‐0 2.89E‐03 1.45E‐04 see GP 004 ‐

Hexane 110‐54‐3 ‐ ‐ ‐ ‐ Hexane 110‐54‐3 1.24E‐01 5.41E‐01 see GP 004 ‐ Hexane 110‐54‐3 ‐ ‐ ‐ ‐Manganese 7439‐96‐5 3.07E‐04 1.34E‐03 1.34E‐03 ‐ Manganese 7439‐96‐5 2.61E‐05 1.14E‐04 1.14E‐04 ‐ Manganese 7439‐96‐5 ‐ ‐ ‐ ‐

Mercury 7439‐97‐6 2.10E‐04 9.20E‐04 9.20E‐04 ‐ Mercury 7439‐97‐6 1.78E‐05 7.82E‐05 7.82E‐05 ‐ Mercury 7439‐97‐6 ‐ ‐ ‐ ‐Naphthalene 91‐20‐3 4.93E‐04 2.16E‐03 2.16E‐03 ‐ Naphthalene 91‐20‐3 4.19E‐05 1.83E‐04 1.83E‐04 ‐ Naphthalene 91‐20‐3 2.08E‐04 1.04E‐05 1.04E‐05 ‐

Nickel 7440‐02‐0 1.70E‐03 7.43E‐03 7.43E‐03 ‐ Nickel 7440‐02‐0 1.44E‐04 6.31E‐04 6.31E‐04 ‐ Nickel 7440‐02‐0 ‐ ‐ ‐ ‐PAH ‐ ‐ ‐ ‐ ‐ PAH ‐ ‐ ‐ ‐ ‐ PAH ‐ 4.12E‐04 2.06E‐05 2.06E‐05 ‐POM ‐ 5.64E‐04 2.47E‐03 2.47E‐03 ‐ POM ‐ 4.79E‐05 2.10E‐04 2.10E‐04 ‐ POM ‐ ‐ ‐ ‐ ‐

Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐Selenium 7782‐49‐2 1.94E‐05 8.49E‐05 8.49E‐05 ‐ Selenium 7782‐49‐2 1.65E‐06 7.21E‐06 7.21E‐06 ‐ Selenium 7782‐49‐2 ‐ ‐ ‐ ‐Toluene 108‐88‐3 2.75E‐03 1.20E‐02 1.20E‐02 ‐ Toluene 108‐88‐3 2.33E‐04 1.02E‐03 1.02E‐03 ‐ Toluene 108‐88‐3 1.00E‐03 5.01E‐05 5.01E‐05 ‐Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ Xylenes 1330‐20‐7 6.98E‐04 3.49E‐05 3.49E‐05 ‐

Total HAPs ‐ 1.05E‐02 4.58E‐02 see GP 004 ‐ Total HAPs ‐ 1.30E‐01 5.68E‐01 see GP 004 ‐ Total HAPs ‐ 9.49E‐03 4.75E‐04 see GP 004 ‐







3a) Delta ID No.: EU 010 3a) Delta ID No.: EU 011 3a) Delta ID No.: FS 001

3b) Tempo SI ID No.: EQUI 18 3b) Tempo SI ID No.: EQUI 19 3b) Tempo SI ID No.: FUGI 13c) 3d) 3f) 3c) 3d) 3f) 3c) 3d) 3f)


HrUnc tpy

Limited tpy


Lbs per Hr

Unc tpy

Limited tpy


Lbs per Hr

Unc tpy

Limited tpy

Actual tpy

PM ‐ 0.15 0.04 0.01 ‐ PM ‐ 0.02 0.09 0.09 ‐ PM ‐ 3.62 15.87 15.87 ‐PM10 ‐ 0.15 0.04 0.01 ‐ PM10 ‐ 0.02 0.09 0.09 ‐ PM10 ‐ 0.62 2.7 2.7 ‐PM2.5 ‐ 0.15 0.04 0.01 ‐ PM2.5 ‐ 0.02 0.09 0.09 ‐ PM2.5 ‐ 4.84E‐03 2.12E‐02 2.12E‐02 ‐SO2 7446‐09‐5 5.13 1.28 0.26 ‐ SO2 7446‐09‐5 1.69E‐03 7.39E‐03 7.39E‐03 ‐ SO2 7446‐09‐5 ‐ ‐ ‐ ‐NOx ‐ 13.27 3.32 0.66 ‐ NOx ‐ 0.28 1.23 1.23 ‐ NOx ‐ ‐ ‐ ‐ ‐VOC ‐ 0.72 0.18 0.04 ‐ VOC ‐ 0.02 0.07 0.07 ‐ VOC ‐ ‐ ‐ ‐ ‐CO 630‐08‐0 13.27 3.32 0.66 ‐ CO 630‐08‐0 0.24 1.04 1.04 ‐ CO 630‐08‐0 ‐ ‐ ‐ ‐Pb 7439‐92‐1 ‐ ‐ ‐ ‐ Pb 7439‐92‐1 1.41E‐06 6.16E‐06 6.16E‐06 ‐ Pb 7439‐92‐1 ‐ ‐ ‐ ‐H2SO4 ‐ ‐ ‐ ‐ ‐ H2SO4 ‐ ‐ ‐ ‐ ‐ H2SO4 ‐ ‐ ‐ ‐ ‐CO2 ‐ 4,148 1,037 207 ‐ CO2 ‐ 336 1,470 1,470 ‐ CO2 ‐ ‐ ‐ ‐ ‐CH4 ‐ 1.68E‐01 4.21E‐02 8.41E‐03 ‐ CH4 ‐ 6.33E‐03 2.77E‐02 2.77E‐02 ‐ CH4 ‐ ‐ ‐ ‐ ‐N2O ‐ 3.36E‐02 8.41E‐03 1.68E‐03 ‐ N2O ‐ 6.33E‐04 2.77E‐03 2.77E‐03 ‐ N2O ‐ ‐ ‐ ‐ ‐SF6 ‐ ‐ ‐ ‐ ‐ SF6 ‐ ‐ ‐ ‐ ‐ SF6 ‐ ‐ ‐ ‐ ‐CO2e ‐ 4,162 1,040 208 ‐ CO2e ‐ 336 1,472 1,472 ‐ CO2e ‐ ‐ ‐ ‐ ‐

Acetaldehyde 75‐07‐0 6.41E‐04 1.60E‐04 3.21E‐05 ‐ Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐Acrolein 107‐02‐8 2.00E‐04 5.01E‐05 1.00E‐05 ‐ Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ Acrolein 107‐02‐8 ‐ ‐ ‐ ‐Arsenic 7440‐38‐2 ‐ ‐ ‐ ‐ Arsenic 7440‐38‐2 5.63E‐07 2.46E‐06 2.46E‐06 ‐ Arsenic 7440‐38‐2 ‐ ‐ ‐ ‐Benzene 71‐43‐2 1.97E‐02 4.93E‐03 9.87E‐04 ‐ Benzene 71‐43‐2 5.91E‐06 2.59E‐05 2.59E‐05 ‐ Benzene 71‐43‐2 ‐ ‐ ‐ ‐

1,3‐Butadiene 106‐99‐0 9.95E‐04 2.49E‐04 4.97E‐05 ‐ 1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐ 1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐Beryllium 7440‐41‐7 ‐ ‐ ‐ ‐ Beryllium 7440‐41‐7 3.38E‐08 1.48E‐07 1.48E‐07 ‐ Beryllium 7440‐41‐7 ‐ ‐ ‐ ‐Cadmium 7440‐43‐9 ‐ ‐ ‐ ‐ Cadmium 7440‐43‐9 3.10E‐06 1.36E‐05 1.36E‐05 ‐ Cadmium 7440‐43‐9 ‐ ‐ ‐ ‐Chromium 7440‐47‐3 ‐ ‐ ‐ ‐ Chromium 7440‐47‐3 3.94E‐06 1.73E‐05 1.73E‐05 ‐ Chromium 7440‐47‐3 ‐ ‐ ‐ ‐

Cobalt 7440‐48‐4 ‐ ‐ ‐ ‐ Cobalt 7440‐48‐4 2.36E‐07 1.04E‐06 1.04E‐06 ‐ Cobalt 7440‐48‐4 ‐ ‐ ‐ ‐Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐ Dichlorobenzene 25321‐22‐6 3.38E‐06 1.48E‐05 1.48E‐05 ‐ Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐

Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐Formaldehyde 50‐00‐0 2.01E‐03 5.02E‐04 see GP 004 ‐ Formaldehyde 50‐00‐0 2.11E‐04 9.24E‐04 see GP 004 ‐ Formaldehyde 50‐00‐0 ‐ ‐ ‐ ‐

Hexane 110‐54‐3 ‐ ‐ ‐ ‐ Hexane 110‐54‐3 5.06E‐03 2.22E‐02 see GP 004 ‐ Hexane 110‐54‐3 ‐ ‐ ‐ ‐Manganese 7439‐96‐5 ‐ ‐ ‐ ‐ Manganese 7439‐96‐5 1.07E‐06 4.68E‐06 4.68E‐06 ‐ Manganese 7439‐96‐5 ‐ ‐ ‐ ‐

Mercury 7439‐97‐6 ‐ ‐ ‐ ‐ Mercury 7439‐97‐6 7.32E‐07 3.20E‐06 3.20E‐06 ‐ Mercury 7439‐97‐6 ‐ ‐ ‐ ‐Naphthalene 91‐20‐3 3.31E‐03 8.27E‐04 1.65E‐04 ‐ Naphthalene 91‐20‐3 1.72E‐06 7.52E‐06 7.52E‐06 ‐ Naphthalene 91‐20‐3 ‐ ‐ ‐ ‐

Nickel 7440‐02‐0 ‐ ‐ ‐ ‐ Nickel 7440‐02‐0 5.91E‐06 2.59E‐05 2.59E‐05 ‐ Nickel 7440‐02‐0 ‐ ‐ ‐ ‐PAH ‐ 5.39E‐03 1.35E‐03 2.70E‐04 ‐ PAH ‐ ‐ ‐ ‐ ‐ PAH ‐ ‐ ‐ ‐ ‐POM ‐ ‐ ‐ ‐ ‐ POM ‐ 1.96E‐06 8.60E‐06 8.60E‐06 ‐ POM ‐ ‐ ‐ ‐ ‐

Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐Selenium 7782‐49‐2 ‐ ‐ ‐ ‐ Selenium 7782‐49‐2 6.75E‐08 2.96E‐07 2.96E‐07 ‐ Selenium 7782‐49‐2 ‐ ‐ ‐ ‐Toluene 108‐88‐3 7.15E‐03 1.79E‐03 3.57E‐04 ‐ Toluene 108‐88‐3 9.57E‐06 4.19E‐05 4.19E‐05 ‐ Toluene 108‐88‐3 ‐ ‐ ‐ ‐Xylenes 1330‐20‐7 4.91E‐03 1.23E‐03 2.45E‐04 ‐ Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐

Total HAPs ‐ 4.10E‐02 1.03E‐02 see GP 004 ‐ Total HAPs ‐ 5.31E‐03 2.33E‐02 see GP 004 ‐ Total HAPs ‐ ‐ ‐ ‐ ‐







3a) Delta ID No.: FS 002 3a) Delta ID No.: FS 003 3a) Delta ID No.: TK 001

3b) Tempo SI ID No.: FUGI 2 3b) Tempo SI ID No.: FUGI 3 3b) Tempo SI ID No.: NA, Insignificant Activity3c) 3d) 3f) 3c) 3d) 3f) 3c) 3d) 3f)


HrUnc tpy

Limited tpy


Lbs per Hr

Unc tpy

Limited tpy


Lbs per Hr

Unc tpy

Limited tpy

Actual tpy

PM ‐ ‐ ‐ ‐ ‐ PM ‐ ‐ ‐ ‐ ‐ PM ‐ ‐ ‐ ‐ ‐PM10 ‐ ‐ ‐ ‐ ‐ PM10 ‐ ‐ ‐ ‐ ‐ PM10 ‐ ‐ ‐ ‐ ‐PM2.5 ‐ ‐ ‐ ‐ ‐ PM2.5 ‐ ‐ ‐ ‐ ‐ PM2.5 ‐ ‐ ‐ ‐ ‐SO2 7446‐09‐5 ‐ ‐ ‐ ‐ SO2 7446‐09‐5 ‐ ‐ ‐ ‐ SO2 7446‐09‐5 ‐ ‐ ‐ ‐NOx ‐ ‐ ‐ ‐ ‐ NOx ‐ ‐ ‐ ‐ ‐ NOx ‐ ‐ ‐ ‐ ‐VOC ‐ ‐ ‐ ‐ ‐ VOC ‐ ‐ ‐ ‐ ‐ VOC ‐ 0.04 0.16 0.16 ‐CO 630‐08‐0 ‐ ‐ ‐ ‐ CO 630‐08‐0 ‐ ‐ ‐ ‐ CO 630‐08‐0 ‐ ‐ ‐ ‐Pb 7439‐92‐1 ‐ ‐ ‐ ‐ Pb 7439‐92‐1 ‐ ‐ ‐ ‐ Pb 7439‐92‐1 ‐ ‐ ‐ ‐H2SO4 ‐ ‐ ‐ ‐ ‐ H2SO4 ‐ ‐ ‐ ‐ ‐ H2SO4 ‐ ‐ ‐ ‐ ‐CO2 ‐ 0.6 2.8 2.8 ‐ CO2 ‐ ‐ ‐ ‐ ‐ CO2 ‐ ‐ ‐ ‐ ‐CH4 ‐ 60.9 266.7 266.7 ‐ CH4 ‐ ‐ ‐ ‐ ‐ CH4 ‐ ‐ ‐ ‐ ‐N2O ‐ ‐ ‐ ‐ ‐ N2O ‐ ‐ ‐ ‐ ‐ N2O ‐ ‐ ‐ ‐ ‐SF6 ‐ ‐ ‐ ‐ ‐ SF6 ‐ 3.27E‐04 1.43E‐03 1.43E‐03 ‐ SF6 ‐ ‐ ‐ ‐ ‐CO2e ‐ 1,523 6,669 6,669 ‐ CO2e ‐ 7 33 33 ‐ CO2e ‐ ‐ ‐ ‐ ‐

Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ Acrolein 107‐02‐8 ‐ ‐ ‐ ‐Arsenic 7440‐38‐2 ‐ ‐ ‐ ‐ Arsenic 7440‐38‐2 ‐ ‐ ‐ ‐ Arsenic 7440‐38‐2 ‐ ‐ ‐ ‐Benzene 71‐43‐2 ‐ ‐ ‐ ‐ Benzene 71‐43‐2 ‐ ‐ ‐ ‐ Benzene 71‐43‐2 ‐ ‐ ‐ ‐

1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐ 1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐ 1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐Beryllium 7440‐41‐7 ‐ ‐ ‐ ‐ Beryllium 7440‐41‐7 ‐ ‐ ‐ ‐ Beryllium 7440‐41‐7 ‐ ‐ ‐ ‐Cadmium 7440‐43‐9 ‐ ‐ ‐ ‐ Cadmium 7440‐43‐9 ‐ ‐ ‐ ‐ Cadmium 7440‐43‐9 ‐ ‐ ‐ ‐Chromium 7440‐47‐3 ‐ ‐ ‐ ‐ Chromium 7440‐47‐3 ‐ ‐ ‐ ‐ Chromium 7440‐47‐3 ‐ ‐ ‐ ‐

Cobalt 7440‐48‐4 ‐ ‐ ‐ ‐ Cobalt 7440‐48‐4 ‐ ‐ ‐ ‐ Cobalt 7440‐48‐4 ‐ ‐ ‐ ‐Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐ Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐ Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐

Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐Formaldehyde 50‐00‐0 ‐ ‐ ‐ ‐ Formaldehyde 50‐00‐0 ‐ ‐ ‐ ‐ Formaldehyde 50‐00‐0 ‐ ‐ ‐ ‐

Hexane 110‐54‐3 ‐ ‐ ‐ ‐ Hexane 110‐54‐3 ‐ ‐ ‐ ‐ Hexane 110‐54‐3 ‐ ‐ ‐ ‐Manganese 7439‐96‐5 ‐ ‐ ‐ ‐ Manganese 7439‐96‐5 ‐ ‐ ‐ ‐ Manganese 7439‐96‐5 ‐ ‐ ‐ ‐

Mercury 7439‐97‐6 ‐ ‐ ‐ ‐ Mercury 7439‐97‐6 ‐ ‐ ‐ ‐ Mercury 7439‐97‐6 ‐ ‐ ‐ ‐Naphthalene 91‐20‐3 ‐ ‐ ‐ ‐ Naphthalene 91‐20‐3 ‐ ‐ ‐ ‐ Naphthalene 91‐20‐3 ‐ ‐ ‐ ‐

Nickel 7440‐02‐0 ‐ ‐ ‐ ‐ Nickel 7440‐02‐0 ‐ ‐ ‐ ‐ Nickel 7440‐02‐0 ‐ ‐ ‐ ‐PAH ‐ ‐ ‐ ‐ ‐ PAH ‐ ‐ ‐ ‐ ‐ PAH ‐ ‐ ‐ ‐ ‐POM ‐ ‐ ‐ ‐ ‐ POM ‐ ‐ ‐ ‐ ‐ POM ‐ ‐ ‐ ‐ ‐

Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐Selenium 7782‐49‐2 ‐ ‐ ‐ ‐ Selenium 7782‐49‐2 ‐ ‐ ‐ ‐ Selenium 7782‐49‐2 ‐ ‐ ‐ ‐Toluene 108‐88‐3 ‐ ‐ ‐ ‐ Toluene 108‐88‐3 ‐ ‐ ‐ ‐ Toluene 108‐88‐3 ‐ ‐ ‐ ‐Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐

Total HAPs ‐ ‐ ‐ ‐ ‐ Total HAPs ‐ ‐ ‐ ‐ ‐ Total HAPs ‐ ‐ ‐ ‐ ‐







3a) Delta ID No.: Emissions Summary Table3b) Tempo SI ID No.:

3c) 3d) 3f) 3c) 3d) 3f) 4a) 4c) Actual


HrUnc tpy

Limited tpy


Lbs per Hr

Unc tpy

Limited tpy

Actual tpy Pollutant Name Unrestricted Limited tons/year

PM 388.57 189.05 ‐PM10 375.40 175.88 ‐PM2.5 372.72 173.20 ‐SO2 455.66 98.58 ‐NOx 2,734.06 354.01 ‐VOC 613.49 646.96 ‐CO 2,456.09 1,266.03 ‐Pb 0.15 0.026 ‐H2SO4 68.92 14.88 ‐CO2 3,626,677 3,090,690 ‐CH4 369.81 324.91 ‐N2O 16.82 5.83 ‐SF6 1.43E‐03 1.43E‐03 ‐CO2e 3,640,966 3,100,582 ‐

Acetaldehyde 7.60E‐01 7.60E‐01 ‐Acrolein 1.22E‐01 1.22E‐01 ‐Arsenic 1.10E‐01 1.23E‐02 ‐Benzene 6.79E‐01 2.87E‐01 ‐

1,3‐Butadiene 1.62E‐01 2.35E‐02 ‐Beryllium 3.13E‐03 3.92E‐04 ‐Cadmium 5.52E‐02 1.27E‐02 ‐Chromium 1.18E‐01 2.10E‐02 ‐

Cobalt 6.12E‐04 6.12E‐04 ‐Dichlorobenzene 8.74E‐03 8.74E‐03 ‐

Ethylbenzene 6.08E‐01 6.08E‐01 ‐Formaldehyde 72.84 9.00 ‐

Hexane 9.44 9.00 ‐Manganese 7.76 0.78 ‐

Mercury 1.37E‐02 3.07E‐03 ‐Naphthalene 3.62E‐01 6.25E‐02 ‐

Nickel 6.05E‐02 1.98E‐02 ‐PAH 4.16E‐01 7.93E‐02 ‐POM 5.09E‐03 5.09E‐03 ‐

Propylene Oxide 5.51E‐01 5.51E‐01 ‐Selenium 2.46E‐01 2.47E‐02 ‐Toluene 2.50 2.49 ‐Xylenes 1.22 1.22 ‐

Total HAPs 97.82 22.50 ‐


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

3b) Tempo SI ID No.:

3a) Delta ID No.:

3e) Potential

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationHG‐01 Form Calculations

Increase from previous Permit amountUncontrolled

tpyUncontrolled

lb/yrLimitedtpy

Limitedlb/yr

Mercury 9.20E‐04 1.84 9.20E‐04 1.84

New amount Previous Amount Difference

Emission Source Description Stack/Vent IDEmission Unit

IDUncontrolled

tpyUncontrolled

lb/yrUncontrolled

tpyUncontrolled

lb/yrUncontrolled

tpyUncontrolled

lb/yrCombined Cycle System #2 002 ‐ ‐ 0.00E+00 0.00 ‐ ‐Combustion Turbine #2 002 002 1.18E‐02 23.58 1.18E‐02 23.58 0.00E+00 0.00

Duct Burners (Combustion Turbine #2) 002 004 8.93E‐04 1.79 8.93E‐04 1.79 0.00E+00 0.00

Auxiliary Boiler 003 005 7.82E‐05 0.16 7.82E‐05 0.16 0.00E+00 0.00

Combined Cycle System #1 007 ‐ ‐ ‐ ‐ ‐ ‐Combustion Turbine #1 007 008 0.00E+00 0.00 0.00E+00 0.00 0.00E+00 0.00

Duct Burners (Combustion Turbine #1) 007 009 9.20E‐04 1.84 0.00E+00 0.00 9.20E‐04 1.84

Diesel Fired Emergency Generator 008 010 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00

Fire Pump Engine 005 007 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00

Bath Heater 009 011 3.20E‐06 6.41E‐03 3.20E‐06 6.41E‐03 0.00E+00 0.00E+00

Cooling Tower NA 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00

Natural Gas Fugitives NA 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00

Breaker Fugitives NA 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00

Fuel Oil Storage Tank NA 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[HG‐01]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationCH‐04a Form Calculations

Modified

Emissions Source Pollutant

"Baseline"Uncontrolled Emissions

(tpy)

"Future Potential"

Uncontrolled Emissions

(tpy)Increase(tpy)

FS 001 PM 0.00 15.87 15.87

FS 001 PM10 0.00 2.70 2.70

FS 001 PM2.5 0.000 0.021 0.021

Note: Baseline emissions are set at zero to indicate not taking credit for past actual emissions.

New

EU 008 EU 009 EU 010 FS 002 FS 003 IA

Emergency Generator

Diesel Fuel Tank

IANatural Gas Condensate Tank - CT1

(New) (New + Modified)

Total Total Significant

Thresholds for major sources

Above Threshold?

(tpy) (tpy) (tpy)

PM 52.13 68.00 25 YesPM10 52.13 54.83 15 YesPM2.5 52.13 52.15 10 YesNOx 167.44 167.44 40 YesSO2 30.46 30.46 40 No

CO 768.64 768.64 100 YesOzone (VOC) 382.58 382.58 40 YesLead 6.61E-03 6.61E-03 0.6 No

Fluorides NA NA 3 NA

Sulfuric acid mist 4.58 4.58 7 No

Hydrogen Sulfide (H2S) NA NA 10 NA

Total Reduced Sulfur including H2S NA NA 10 NA

Total Reduced Sulfur Compounds including H2S

NA NA 10 NA

MWC Organics NA NA 0.0000035 NA

MWC Acid Gas NA NA 40 NA

MWC Metals NA NA 15 NA

MSW Landfill Gas NA NA 50 NA

CO2e 1,585,055 1,585,055 75,000 Yes

52.12 see EU 008 0.01 NA52.12 see EU 008 0.01 NA

Pollutant PTE (tpy) (PTE) (tpy) (PTE) (tpy) PTE (tpy)

52.12 see EU 008 0.01 NA

768.0 see EU 008 0.66 NA382.5 see EU 008 0.036 NA

166.8 see EU 008 0.66 NA30.2 see EU 008 0.26 NA

NA NA NA

6.61E-03 see EU 008 0.00E+00 NA

NA

NA NA NA NA

NA NA NA NA4.58 see EU 008 NA NANA NA

NA

NA NA NA NA

NANA

NA

1,155,682 422,463 208 6,669

NA NA NA NANA NA NA NANA NA NA NA

NA

NA1.65E-03

NANANANA

PTE (tpy)

NANANANANA

PTE (tpy)

NANANANANANANANA

32.66

NA

NA

NANA

NANANA

NA

NA

NANANANA

NANANA

NA

NA

NANANANANA

PTE (tpy)

NANANANANANA

2.75E-04NA

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[CH‐04a]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationCH‐04c Form Calculations

Table 1: Facility PTE before proposed changeEU 002 EU 004 EU 005 EU 007 EU 011

Total PTE (tpy)

CO2 1,513,963CH4 28.5N2O 2.9SF6 0.00E+00

CO2e 1,515,527

Mass Sum of GHGs (tpy): 1,513,994

Table 4: N/A, no modified equipment

Table 6: PTE of new units

EU 008 EU 009 EU 010 FS 002 FS 003 (New) (New + Modified)

Total Increase Total

Significant Thresholds for major sources

Above Threshold?

(tpy) (tpy) (tpy)

CO2 1,576,727 1,576,727 0 NA

CH4 296.4 296.4 0 NA

N2O 3.0 3.0 0 NA

SF6 1.43E-03 1.43E-03 0 NA

CO2e 1,585,055 1,585,055 75,000 Yes

PTE (tpy)Pollutant PTE (tpy) (PTE) (tpy) (PTE) (tpy) PTE (tpy)

1,154,490 422,027 207 2.80 0.00E+0021.76 7.95 8.41E-03 266.65 0.00E+002.18 0.8 1.68E-03 0.00E+00 0.00E+00

0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.43E-031,155,682 422,463 208 6,669 32.66

Pollutant PTE (tpy) (PTE) (tpy) (PTE) (tpy) PTE (tpy) PTE (tpy)

1,066,724 409,884 35,865 20 1,47020.10 8 1 0 02.01 1 0 0 0

0.00E+00 0 0 0 0

1,067,825 410,307 35,902 20 1,472

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[CH‐04c]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationGP 004: Formaldehyde, n‐Hexane, and Total HAPs

Group Information

Inidividual Units of GP 004Emission Source Description Stack/Vent ID EU CE CE CE CE

Combined Cycle System #2 002 ‐ see units see units see units see units Combustion Turbine #2 002 002 002 004 006 008

Combustion Turbine #2 Duct Burners 002 004 ‐ ‐ 006 008

Combined Cycle System #1 007 ‐ see units see units see units ‐ Combustion Turbine #1 007 008 010 011 012 ‐ Combustion Turbine #1 Duct Burners 007 009 ‐ 011 012 ‐Auxiliary Boiler 003 005 ‐ ‐ ‐ ‐Fire Pump Engine 005 007 ‐ ‐ ‐ ‐Diesel Fired Emergency Generator 008 010 ‐ ‐ ‐ ‐Bath Heater 009 011 ‐ ‐ ‐ ‐

HAPs

Unit Pollutant CAS #Emission Rate

(lb/hr)Uncontrolled Emissions

(tpy)Limited Emissions

(tpy)GP 004 Formaldehyde 50‐00‐0 * * 9.0

GP 004 Hexane 110‐54‐3 * * 9.0

GP 004 Total HAPs * * 22.5Notes:* See individual units of GP 004Limited emissions to be based on permit limits as described in the permit application forms.

The purpose of the proposed GP 004 is to establish limits on hexane (CAS# 110‐54‐3), formaldehyde (CAS# 50‐00‐0), and Total HAPs for the existing combustion turbine stack (SV 002), the proposed combustion turbine stack (SV 007), and other units that emit formaldehyde or hexane. The limits will be based on emissions from all units. Compliance with the limits will be met through recordkeeping as described in the permit application forms.

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[GP 004]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationCombined Cycle System #1: (Combustion Turbine #1 + Combustion Turbine #1 Duct Burners)

Unit Information

Combustion Turbine Duct BurnersDescription: Combustion Turbine #1 Description: Duct Burners (Combustion Turbine #1)Unit Delta ID: EU 008 Unit Delta ID: EU 009Stack Delta ID: SV 007 Stack Delta ID: SV 007Primary Fuel Natural Gas Primary Fuel Natural GasBackup Fuel ‐ Backup Fuel ‐

Primary Fuel Heat Input Capacity 2253.3 MMBtu/hr

Primary Fuel Heat Input Capacity 823.7 MMBtu/hr

Primary Fuel Heat Value 1020 Btu/scf Primary Fuel Heat Value 1020 Btu/scf

Primary Fuel Consumption Rate 2.21 MMscf/hr


Hours Uncontrolled 8760 Hours Uncontrolled 8760

Hours Limited 8760 Hours Limited 8760

Unit Tempo ID: EQUI 16 Unit Tempo ID: EQUI 17Stack Tempo ID: STRU 20 Stack Tempo ID: STRU 20

Combustion Turbine & Duct BurnersCombined Heat Input: 3077.0 MMBtu/hr

SUSD Emissions

Pollutant FuelCold SU

(lb/event)Warm SU(lb/event)

SD(lb/event)

NOx Natural Gas 414 220 27

VOC Natural Gas 2959.5 1894.0 150.5

CO Natural Gas 5919 3788 301

SUSD lb/event values based on historical facility data and updated to reflect the worst case proposed combustion turbine.

SUSD Durations

Event Type Fuel Cold SU Warm SU SD Total SUSD HoursCalculated

Non‐SUSD HoursNumber of events per year Natural Gas 50 250 300

Hours per event Natural Gas 5.0 3.5 1.0

Total Event Hours Natural Gas 250 875 300 1425 7335SUSD events per year and hours per event estimated based on facility data and knowledge of proposed contract.These values are used to calculate annual SUSD emissions and are not operating limits. Facility is proposing an annual SUSD emission limit for NOx, CO and VOC for Combustion Turbine #1 and Combustion Turbine #2.

Annual SUSD Emissions

Pollutant Fuel typeCold SU (tpy)

Warm SU (tpy)

SD (tpy)

Total (tpy)

NOx Natural Gas 10.35 27.50 4.05 41.9VOC Natural Gas 73.99 236.75 22.58 333.3CO Natural Gas 147.98 473.50 45.15 666.6Calculated from lb/event values and number of events per year.

The maximum hourly natural gas heat input capacity is based on the combustion turbine's highest hourly operating scenario (combinations of load, ambient temperature) which is based on vendor data.

The duct burners have a maximum rated heat input capcity of 823.7 MMBtu/hr and fire natural gas only.

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[CT1]


Criteria Pollutants Includes SUSD Excludes SUSD Includes SUSD

PollutantCombustion Turbine Fuel

Emission Factor(lb/MMscf)

Emission Factor(lb/MMBtu)

Emission Rate(lb/hr)b

Uncontrolled Emissions(tpy)c

Uncontrolled Emissions(tpy)f

Control

Efficiencyd

Controlled Emissions(tpy)e

Limited Emissions(tpy) Reference

PM Natural Gas NA NAa 11.9 52.1 52.1 0.0% 52.1 52.1 CTDB1_1

PM10 Natural Gas NA NAa 11.9 52.1 52.1 0.0% 52.1 52.1 CTDB1_1

PM2.5 Natural Gas NA NAa 11.9 52.1 52.1 0.0% 52.1 52.1 CTDB1_2

SOx Natural Gas NA 2.2409E‐03 6.9 30.2 30.2 0.0% 30.2 30.2 CTDB1_3

NOx Natural Gas NA NAa 273.7 1198.8 1045.7 80.0% 149.1 166.8 CTDB1_1

VOC Natural Gas NA NAa 25.1 110.1 425.5 40.0% 58.8 382.5 CTDB1_1

CO Natural Gas NA NAa 169.5 742.2 1288.1 90.0% 121.0 768.0 CTDB1_1

Lead Natural Gas 0.0005 4.9E‐07 1.51E‐03 6.61E‐03 6.61E‐03 0.0% 6.61E‐03 6.61E‐03 CTDB1_4

H2SO4 Natural Gas NA NAa 1.05 4.58 4.58 0.0% 4.58 4.58 CTDB1_5

References:CTDB1_1

CTDB1_2

CTDB1_3

CTDB1_4

CTDB1_5

GHG

UnitCombustion Turbine Fuel

Duct Burner Fuel Pollutant GWP

Emission Factor (lb/MMBtu)

Emission Rate(lb/hr)


(tpy)Control Efficiency

Controlled Emissions(tpy)

Limited Emissions

(tpy)

Duct Burner ‐ Natural Gas CO2 1 116.98 96,353 422,027 0.00% 422,027 422,027

Duct Burner ‐ Natural Gas CH4 25 2.2E‐03 1.82 7.95 0.00% 7.95 7.95

Duct Burner ‐ Natural Gas N2O 298 2.2E‐04 0.18 0.80 0.00% 0.80 0.80

Duct Burner ‐ Natural Gas CO2e ‐ 117.10 96,453 422,463 0.00% 422,463 422,463

Combustion Turbine Natural Gas ‐ CO2 1 116.98 263,582 1,154,490 0.00% 1,154,490 1,154,490

Combustion Turbine Natural Gas ‐ CH4 25 2.2E‐03 4.97 21.76 0.00% 21.76 21.76

Combustion Turbine Natural Gas ‐ N2O 298 2.2E‐04 0.50 2.18 0.00% 2.18 2.18

Combustion Turbine Natural Gas ‐ CO2e ‐ 117.10 263,854 1,155,682 0.00% 1,155,682 1,155,682

References:GHG Table

cAnnual maximum uncontrolled emissions are conservatively estimated based on the maximum hourly emission rate and do not incorporate BACT limits.dThe NOx, CO, and VOC control efficiencies only represent a nominal control efficiency and are not used to calculate Controlled Emissions.

eThe turbine and the ductburners will both vent to a common stack. Therefore, the maximum controlled emissions represent the calculated maximum controlled emissions at ambient conditions for the combined cycle system, which includes both the combustion turbine & ductburners. Natural gas‐fired controlled emissions based on the following BACT limits: 3.0 ppmvd NOx @ 15% O2; 4.0 ppmvd CO @15% O2; 3.4 ppmvd VOC @15% O2.

See GHG Table, Natural Gas emission factors

fAfter discussion, MPCA on 4‐11‐16 requested a revision of the CO and VOC uncontrolled tpy emissions. All pollutants with separate SUSD emissions (CO, NOx, and VOC) required updates.

aThe hourly emission rates provided for the lb/hr Emission Rate are a worst‐case projected emissions for the combined cycle system, based on several different operating scenarios at varying heat input capacities for the combustion turbine. The emission rate also includes the duct burner natural gas combustion emissions. These lb/hr Emission Rates do not correlate directly to the maximum heat input capacity provided above. Therefore, a specific lb/MMBtu emission factor is not relevant to the combined cycle system emission rates provided on this form.

bThe combined cycle system maximum hourly emission rate is a worst case composite emission scenario that is based on the combustion turbine'shighest hourly emission operating scenario (combinations of load, ambient temperature) for each pollutant, which is based on combustion turbine vendor data. The emission rate also incorporates the maximum hourly duct burner emissions.

Potential PM, PM10, and PM2.5 emissions were based on vendor data, operating experience and stack tests from other similar Calpine facilities.PM2.5 emission factor assumed equal to PM emisison factor.Based on Permit 01300098‐002 emission limit.

No data for lead available in AP‐42 Section 3.1 "Stationary Gas Turbines" (rev 04/00) Table 3.1‐4; used natural gas lead emission factor from AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Table 1.4‐2.H2SO4 calculated as percentage of SO2 emission factor.



HAPs


Duct Burner Fuel Pollutant CAS #

Emission Factor (lb/MMscf)




(tpy) Control Efficiency

Controlled Emissions

(tpy)

Limited Emissions

(tpy) ReferenceDuct Burner ‐ Natural Gas Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_10

Duct Burner ‐ Natural Gas Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_10

Duct Burner ‐ Natural Gas Arsenic 7440‐38‐2 2.00E‐04 1.96E‐07 1.62E‐04 7.07E‐04 0.00% 7.07E‐04 7.07E‐04 CTDB1_10

Duct Burner ‐ Natural Gas Benzene 71‐43‐2 2.10E‐03 2.06E‐06 1.70E‐03 7.43E‐03 0.00% 7.43E‐03 7.43E‐03 CTDB1_10

Duct Burner ‐ Natural Gas 1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_10

Duct Burner ‐ Natural Gas Beryllium 7440‐41‐7 1.20E‐05 1.18E‐08 9.69E‐06 4.24E‐05 0.00% 4.24E‐05 4.24E‐05 CTDB1_10

Duct Burner ‐ Natural Gas Cadmium 7440‐43‐9 1.10E‐03 1.08E‐06 8.88E‐04 3.89E‐03 0.00% 3.89E‐03 3.89E‐03 CTDB1_10

Duct Burner ‐ Natural Gas Chromium 7440‐47‐3 1.40E‐03 1.37E‐06 1.13E‐03 4.95E‐03 0.00% 4.95E‐03 4.95E‐03 CTDB1_10

Duct Burner ‐ Natural Gas Cobalt 744‐48‐4 8.40E‐05 8.24E‐08 6.78E‐05 2.97E‐04 0.00% 2.97E‐04 2.97E‐04 CTDB1_10

Duct Burner ‐ Natural Gas Dichlorobenzene 25321‐22‐6 1.20E‐03 1.18E‐06 9.69E‐04 4.24E‐03 0.00% 4.24E‐03 4.24E‐03 CTDB1_10

Duct Burner ‐ Natural Gas Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_10

Duct Burner ‐ Natural Gas Formaldehyde 50‐00‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_9

Duct Burner ‐ Natural Gas Hexane 110‐54‐3 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_9

Duct Burner ‐ Natural Gas Manganese 7439‐96‐5 3.80E‐04 3.73E‐07 3.07E‐04 1.34E‐03 0.00% 1.34E‐03 1.34E‐03 CTDB1_10

Duct Burner ‐ Natural Gas Mercury 7439‐97‐6 2.60E‐04 2.55E‐07 2.10E‐04 9.20E‐04 0.00% 9.20E‐04 9.20E‐04 CTDB1_10

Duct Burner ‐ Natural Gas Naphthalene 91‐20‐3 6.10E‐04 5.98E‐07 4.93E‐04 2.16E‐03 0.00% 2.16E‐03 2.16E‐03 CTDB1_10

Duct Burner ‐ Natural Gas Nickel 7440‐02‐0 2.10E‐03 2.06E‐06 1.70E‐03 7.43E‐03 0.00% 7.43E‐03 7.43E‐03 CTDB1_10

Duct Burner ‐ Natural Gas PAH ‐ ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_10

Duct Burner ‐ Natural Gas POM ‐ 6.98E‐04 6.85E‐07 5.64E‐04 2.47E‐03 0.00% 2.47E‐03 2.47E‐03 CTDB1_10

Duct Burner ‐ Natural Gas Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_10

Duct Burner ‐ Natural Gas Selenium 7782‐49‐2 2.40E‐05 2.35E‐08 1.94E‐05 8.49E‐05 0.00% 8.49E‐05 8.49E‐05 CTDB1_10

Duct Burner ‐ Natural Gas Toluene 108‐88‐3 3.40E‐03 3.33E‐06 2.75E‐03 1.20E‐02 0.00% 1.20E‐02 1.20E‐02 CTDB1_10

Duct Burner ‐ Natural Gas Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_10Reference

Combustion Turbine Natural Gas ‐ Acetaldehyde 75‐07‐0 ‐ 4.00E‐05 9.01E‐02 3.95E‐01 0.00% 3.95E‐01 3.95E‐01 CTDB1_6

Combustion Turbine Natural Gas ‐ Acrolein 107‐02‐8 ‐ 6.40E‐06 1.44E‐02 6.32E‐02 0.00% 6.32E‐02 6.32E‐02 CTDB1_6

Combustion Turbine Natural Gas ‐ Arsenic 7440‐38‐2 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_6

Combustion Turbine Natural Gas ‐ Benzene 71‐43‐2 ‐ 1.20E‐05 2.70E‐02 1.18E‐01 0.00% 1.18E‐01 1.18E‐01 CTDB1_6

Combustion Turbine Natural Gas ‐ 1,3‐Butadiene 106‐99‐0 ‐ 4.29E‐07 9.67E‐04 4.23E‐03 0.00% 4.23E‐03 4.23E‐03 CTDB1_6

Combustion Turbine Natural Gas ‐ Beryllium 7440‐41‐7 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_6

Combustion Turbine Natural Gas ‐ Cadmium 7440‐43‐9 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_6

Combustion Turbine Natural Gas ‐ Chromium 7440‐47‐3 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_6

Combustion Turbine Natural Gas ‐ Cobalt 744‐48‐4 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_6

Combustion Turbine Natural Gas ‐ Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_6

Combustion Turbine Natural Gas ‐ Ethylbenzene 100‐41‐4 ‐ 3.20E‐05 7.21E‐02 3.16E‐01 0.00% 3.16E‐01 3.16E‐01 CTDB1_6

Combustion Turbine Natural Gas ‐ Formaldehyde 50‐00‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_9

Combustion Turbine Natural Gas ‐ Hexane 110‐54‐3 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_9

Combustion Turbine Natural Gas ‐ Manganese 7439‐96‐5 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_6

Combustion Turbine Natural Gas ‐ Mercury 7439‐97‐6 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_6

Combustion Turbine Natural Gas ‐ Naphthalene 91‐20‐3 ‐ 1.30E‐06 2.93E‐03 1.28E‐02 0.00% 1.28E‐02 1.28E‐02 CTDB1_6

Combustion Turbine Natural Gas ‐ Nickel 7440‐02‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_6

Combustion Turbine Natural Gas ‐ PAH ‐ ‐ 2.20E‐06 4.96E‐03 2.17E‐02 0.00% 2.17E‐02 2.17E‐02 CTDB1_6

Combustion Turbine Natural Gas ‐ POM ‐ ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_6

Combustion Turbine Natural Gas ‐ Propylene Oxide 75‐56‐9 ‐ 2.90E‐05 6.53E‐02 2.86E‐01 0.00% 2.86E‐01 2.86E‐01 CTDB1_6

Combustion Turbine Natural Gas ‐ Selenium 7782‐49‐2 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB1_6

Combustion Turbine Natural Gas ‐ Toluene 108‐88‐3 ‐ 1.30E‐04 2.93E‐01 1.28E+00 0.00% 1.28E+00 1.28E+00 CTDB1_6

Combustion Turbine Natural Gas ‐ Xylenes 1330‐20‐7 ‐ 6.40E‐05 1.44E‐01 6.32E‐01 0.00% 6.32E‐01 6.32E‐01 CTDB1_6Reference

Combined Turbine & DB Natural Gas Natural Gas Acetaldehyde 75‐07‐0 ‐ ‐ 9.01E‐02 3.95E‐01 0.00% 3.95E‐01 3.95E‐01 ‐Combined Turbine & DB Natural Gas Natural Gas Acrolein 107‐02‐8 ‐ ‐ 1.44E‐02 6.32E‐02 0.00% 6.32E‐02 6.32E‐02 ‐Combined Turbine & DB Natural Gas Natural Gas Arsenic 7440‐38‐2 ‐ ‐ 1.62E‐04 7.07E‐04 0.00% 7.07E‐04 7.07E‐04 ‐Combined Turbine & DB Natural Gas Natural Gas Benzene 71‐43‐2 ‐ ‐ 2.87E‐02 1.26E‐01 0.00% 1.26E‐01 1.26E‐01 ‐Combined Turbine & DB Natural Gas Natural Gas 1,3‐Butadiene 106‐99‐0 ‐ ‐ 9.67E‐04 4.23E‐03 0.00% 4.23E‐03 4.23E‐03 ‐Combined Turbine & DB Natural Gas Natural Gas Beryllium 7440‐41‐7 ‐ ‐ 9.69E‐06 4.24E‐05 0.00% 4.24E‐05 4.24E‐05 ‐Combined Turbine & DB Natural Gas Natural Gas Cadmium 7440‐43‐9 ‐ ‐ 8.88E‐04 3.89E‐03 0.00% 3.89E‐03 3.89E‐03 ‐Combined Turbine & DB Natural Gas Natural Gas Chromium 7440‐47‐3 ‐ ‐ 1.13E‐03 4.95E‐03 0.00% 4.95E‐03 4.95E‐03 ‐Combined Turbine & DB Natural Gas Natural Gas Cobalt 744‐48‐4 ‐ ‐ 6.78E‐05 2.97E‐04 0.00% 2.97E‐04 2.97E‐04 ‐Combined Turbine & DB Natural Gas Natural Gas Dichlorobenzene 25321‐22‐6 ‐ ‐ 9.69E‐04 4.24E‐03 0.00% 4.24E‐03 4.24E‐03 ‐Combined Turbine & DB Natural Gas Natural Gas Ethylbenzene 100‐41‐4 ‐ ‐ 7.21E‐02 3.16E‐01 0.00% 3.16E‐01 3.16E‐01 ‐Combined Turbine & DB Natural Gas Natural Gas Formaldehyde 50‐00‐0 ‐ ‐ ‐ 37.60 0.00% 37.60 see GP 004 see belowCombined Turbine & DB Natural Gas Natural Gas Hexane 110‐54‐3 ‐ ‐ ‐ 4.58 0.00% 4.58 see GP 004 see belowCombined Turbine & DB Natural Gas Natural Gas Manganese 7439‐96‐5 ‐ ‐ 3.07E‐04 1.34E‐03 0.00% 1.34E‐03 1.34E‐03 ‐Combined Turbine & DB Natural Gas Natural Gas Mercury 7439‐97‐6 ‐ ‐ 2.10E‐04 9.20E‐04 0.00% 9.20E‐04 9.20E‐04 ‐Combined Turbine & DB Natural Gas Natural Gas Naphthalene 91‐20‐3 ‐ ‐ 3.42E‐03 1.50E‐02 0.00% 1.50E‐02 1.50E‐02 ‐Combined Turbine & DB Natural Gas Natural Gas Nickel 7440‐02‐0 ‐ ‐ 1.70E‐03 7.43E‐03 0.00% 7.43E‐03 7.43E‐03 ‐Combined Turbine & DB Natural Gas Natural Gas PAH ‐ ‐ ‐ 4.96E‐03 2.17E‐02 0.00% 2.17E‐02 2.17E‐02 ‐Combined Turbine & DB Natural Gas Natural Gas POM ‐ ‐ ‐ 5.64E‐04 2.47E‐03 0.00% 2.47E‐03 2.47E‐03 ‐Combined Turbine & DB Natural Gas Natural Gas Propylene Oxide 75‐56‐9 ‐ ‐ 6.53E‐02 2.86E‐01 0.00% 2.86E‐01 2.86E‐01 ‐Combined Turbine & DB Natural Gas Natural Gas Selenium 7782‐49‐2 ‐ ‐ 1.94E‐05 8.49E‐05 0.00% 8.49E‐05 8.49E‐05 ‐Combined Turbine & DB Natural Gas Natural Gas Toluene 108‐88‐3 ‐ ‐ 2.96E‐01 1.30E+00 0.00% 1.30E+00 1.30E+00 ‐Combined Turbine & DB Natural Gas Natural Gas Xylenes 1330‐20‐7 ‐ ‐ 1.44E‐01 6.32E‐01 0.00% 6.32E‐01 6.32E‐01 ‐Combined Turbine & DB Natural Gas Natural Gas Total HAPs ‐ ‐ ‐ 7.23E‐01 4.53E+01 ‐ 4.53E+01 3.16E+00

CTDB1_9

CTDB1_10

These pollutants are entirely accounted for in the combined CT and DB data.DB ‐ Emission factors from AP‐42, Section 1.4 "Natural Gas Combustion" (Rev 7/98); Tables 1.4‐3 and 1.4‐4. Total POM emission factor is equal to the sum of the individual emissions of POM compounds (including Naphthalene).




Non‐SUSD HoursTotal Event Hours Natural Gas 250 875 300 1425 7335



Heat Input (MMBtu/hr)


Emission Rate(lb/hr) Limited Hours

Uncontrolled Emissions(tpy)

Control Efficiency


(tpy)

Limited Emissions

(tpy) ReferenceCombined Turbine & DB Natural Gas Natural Gas Formaldehyde (< 60% Load) 50‐00‐0 3077.0 0.00279 8.58 1425 37.60 0.00% 37.60 see GP 004 CTDB1_7

Combined Turbine & DB Natural Gas Natural Gas Formaldehyde (60 ‐ < 90% Load) 50‐00‐0 3077.0 0.00151 4.65 7335 20.35 0.00% 20.35 see GP 004 CTDB1_7

Combined Turbine & DB Natural Gas Natural Gas Formaldehyde (>= 90% Load) 50‐00‐0 3077.0 0.00105 3.23 0 14.15 0.00% 14.15 see GP 004 CTDB1_7

Combined Turbine & DB Natural Gas Natural Gas Hexane (Any Load) 110‐54‐3 3077.0 0.00034 1.05 8760 4.58 0.00% 4.58 see GP 004 CTDB1_8

References:CTDB1_7

CTDB1_8

Note: 0‐60% Load assumed to correspond to all SUSD Time; Conservatively assumed remaining time "Calculated Non‐SUSD Hours" is at 60‐90% load.

Formaldehyde and Hexane Totals:






Uncontrolled Emissions(tpy)

Control Efficiency


(tpy)

Limited Emissions

(tpy)Combined Turbine & DB Natural Gas Natural Gas Formaldehyde total 50‐00‐0 Natural Gas ‐ ‐ 8760 37.60 0.00% 37.60 see GP 004Combined Turbine & DB Natural Gas Natural Gas Hexane Total 110‐54‐3 Natural Gas ‐ ‐ 8760 4.58 0.00% 4.58 see GP 004

Formaldehyde emission factors based on most recent stack test (Report No: 183284.CTG2.AB.COMP; September 2011); Maximum of 3 runsHexane emission factor based on most recent stack test at SV002 (Report No: 183284.CTG2.AB.COMP; September 2011); Maximum of 3 runs



Worst‐Case Emissions Summary

Combined Cycle (EU 008 and EU 009)Criteria Pollutants

Excludes SUSD Includes SUSD

Unit Pollutant


(tpy)

Controlled Emissions Before Operating Limits

(tpy)aLimited Emissions

(tpy)b

Emission Rate Based on Limited Emissions(lb/hr)

Combined Turbine & DB PM 52.1 52.1 52.12 11.9

Combined Turbine & DB PM10 52.1 52.1 52.12 11.9

Combined Turbine & DB PM2.5 52.1 52.1 52.12 11.9

Combined Turbine & DB SOx 30.2 30.2 30.20 6.9

Combined Turbine & DB NOx 1045.7 149.1 166.78 34.1

Combined Turbine & DB VOC 425.5 58.8 382.5 13.4

Combined Turbine & DB CO 1288.1 121.0 768.0 27.6

Combined Turbine & DB Lead 6.61E‐03 6.61E‐03 6.61E‐03 1.51E‐03Combined Turbine & DB H2SO4 4.6 4.6 4.58 1.0

EU 008 Combustion Turbine onlyGHG Pollutants

Unit PollutantEmission Rate



(tpy)

Combustion Turbine CO2 263,582 1,154,490 1,154,490

Combustion Turbine CH4 4.97 21.76 21.76

Combustion Turbine N2O 0.50 2.18 2.18

Combustion Turbine CO2e 263,854 1,155,682 1,155,682

EU 008 Combustion Turbine only, SV 007 for Formaldehyde and HexaneHAPs

Unit Pollutant CAS #Emission Rate



(tpy)Combustion Turbine Acetaldehyde 75‐07‐0 9.01E‐02 3.95E‐01 3.95E‐01Combustion Turbine Acrolein 107‐02‐8 1.44E‐02 6.32E‐02 6.32E‐02Combustion Turbine Arsenic 7440‐38‐2 ‐ ‐ ‐Combustion Turbine Benzene 71‐43‐2 2.70E‐02 1.18E‐01 1.18E‐01Combustion Turbine 1,3‐Butadiene 106‐99‐0 9.67E‐04 4.23E‐03 4.23E‐03Combustion Turbine Beryllium 7440‐41‐7 ‐ ‐ ‐Combustion Turbine Cadmium 7440‐43‐9 ‐ ‐ ‐Combustion Turbine Chromium 7440‐47‐3 ‐ ‐ ‐Combustion Turbine Cobalt 744‐48‐4 ‐ ‐ ‐Combustion Turbine Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐Combustion Turbine Ethylbenzene 100‐41‐4 7.21E‐02 3.16E‐01 3.16E‐01Combined Turbine & DB Formaldehyde 50‐00‐0 8.58 37.60 see GP 004Combined Turbine & DB Hexane 110‐54‐3 1.05 4.58 see GP 004Combustion Turbine Manganese 7439‐96‐5 ‐ ‐ ‐Combustion Turbine Mercury 7439‐97‐6 ‐ ‐ ‐Combustion Turbine Naphthalene 91‐20‐3 2.93E‐03 1.28E‐02 1.28E‐02Combustion Turbine Nickel 7440‐02‐0 ‐ ‐ ‐Combustion Turbine PAH ‐ 4.96E‐03 2.17E‐02 2.17E‐02Combustion Turbine POM ‐ ‐ ‐ ‐Combustion Turbine Propylene Oxide 75‐56‐9 6.53E‐02 2.86E‐01 2.86E‐01Combustion Turbine Selenium 7782‐49‐2 ‐ ‐ ‐Combustion Turbine Toluene 108‐88‐3 2.93E‐01 1.28E+00 1.28E+00

Combustion Turbine Xylenes 1330‐20‐7 1.44E‐01 6.32E‐01 6.32E‐01Combustion Turbine Total HAPs NA NA NANotes: Due to Formaldehyde and Hexane emissions being calculated at the stack level, Total HAPs for combustion turbine alone are not able to be meaningfully calculated.

b Limited emissions assume a worst‐case emission scenario for PM, PM10, SOx, NOx, VOC, CO, Lead, and H2SO4, where the turbine operates natural gas the entire year and includes the startup and shutdown emissions for NOx, VOC, and CO.

aRepresents the worst‐case annual controlled criteria pollutant emissions, which incorporated the proposed natural gas BACT limits.



Unit Information

Combustion Turbine Duct BurnersDescription: Combustion Turbine #2 Description: Duct Burners (Combustion Turbine #2)Unit Delta ID: EU 002 Unit Delta ID: EU 004Stack Delta ID: SV 002 Stack Delta ID: SV 002Primary Fuel Natural Gas Primary Fuel Natural GasBackup Fuel Fuel Oil Backup Fuel ‐

Primary Fuel Heat Input Capacity 2082 MMBtu/hr

Primary Fuel Heat Input Capacity 800 MMBtu/hr

Secondary Fuel Heat Input Capacity 2243 MMBtu/hr

Primary Fuel Heat Value 1020 Btu/scf Primary Fuel Heat Value 1020 Btu/scf

Secondary Fuel Heat Value 140,000 Btu/gal



Hours Uncontrolled 8760 Hours Uncontrolled 8760

Hours Limited 8760 Hours Limited 8760

Unit Tempo ID: EQUI 5 Unit Tempo ID: EQUI 6Stack Tempo ID: STRU 14 Stack Tempo ID: STRU 14

Operating LimitsFuel Oil use 875 hr maximum

Combustion Turbine & Duct BurnersCombined Heat Input (CT Natural Gas): 2882 MMBtu/hr

Combined Heat Input (CT Fuel Oil): 3043 MMBtu/hr

SUSD Emissions

Pollutant FuelCold SU

(lb/event)Warm SU(lb/event)

SD(lb/event)

NOx Natural Gas 323.5 148.3 4.4

VOC Natural Gas 2693.8 1534.3 23.4

CO Natural Gas 5387.6 3068.6 46.8

NOx Fuel Oil 459.3 140.7 16.8

VOC Fuel Oil 749.1 272.9 154.7

CO Fuel Oil 1498.2 545.9 309.3

SUSD Durations


Non‐SUSD Hours

Calculated Non‐SUSD Hours with FO Limit

Total Hours with SUSD Excluded

Number of events per year Natural Gas 46 184 230

Hours per event Natural Gas 5.0 3.5 1.0

Total Event Hours Natural Gas 230 644 230 1104 7656 6781 7885Number of events per year Fuel Oil 6 24 30

Hours per event Fuel Oil 5.0 3.5 1.0

Total Event Hours Fuel Oil 30 84 30 144 731 731 875

Annual SUSD Emissions

Pollutant Fuel typeCold SU (tpy)

Warm SU (tpy)

SD (tpy)

Total (tpy)

NOx Natural Gas 7.44 13.64 0.51 21.6VOC Natural Gas 61.96 141.16 2.69 205.8CO Natural Gas 123.91 282.31 5.38 411.6NOx Fuel Oil 1.38 1.69 0.25 3.3VOC Fuel Oil 2.25 3.27 2.32 7.8CO Fuel Oil 4.49 6.55 4.64 15.7

Calculated from "SUSD Emissions" section lb/event values and "SUSD Durations" section number of events per year.

The maximum hourly natural gas heat input capacity is based on the combustion turbine's highest hourly operating scenario (combinations of load, ambient temperature) which is based on vendor data.

The ductburners have a maximum rated heat input capcity of 800 MMBtu/hr and fire natural gas only.

The maximum hourly fuel oil heat input capacity is based on the combustion turbine's highest hourly operating scenario (combinations of load, ambient temperature, and power/steam augmentation) which is based on vendor data.



Criteria Pollutants Excludes SUSD Includes SUSD

PollutantCombustion Turbine Fuel

Emission Factor(lb/MMscf)

Emission Factor(lb/MMBtu)

Emission Rate(lb/hr)b

Uncontrolled Emissions(tpy)c Control Efficiencyd

Controlled Emissions(tpy)e

Limited Emissions(tpy)f Reference

PM Natural Gas NA NAa 22.00 96.4 0.0% 96.4 96.4 CTDB2_1

PM10 Natural Gas NA NAa 22.00 96.4 0.0% 96.4 96.4 CTDB2_1

PM2.5 Natural Gas NA NAa 22.00 96.4 0.0% 96.4 96.4 CTDB2_2

SOx Natural Gas NA 2.2409E‐03 6.458 28.3 0.0% 28.3 28.3 CTDB2_3

NOx Natural Gas NA NAa 255.98 1121.2 80.0% 163.0 164.0 CTDB2_1

VOC Natural Gas NA NAa 19.21 84.1 40.0% 50.5 249.9 CTDB2_1

CO Natural Gas NA NAa 119.12 521.7 90.0% 53.1 458.0 CTDB2_1

Lead Natural Gas 0.0005 4.9E‐07 0.001 6.19E‐03 0.0% 6.19E‐03 6.19E‐03 CTDB2_4

H2SO4 Natural Gas NA NAa0.98 4.29 0.0% 4.29 4.29 CTDB2_5

PM Fuel Oil NA NAc 72.6 318.0 0.0% 318.0 31.8 CTDB2_1

PM10 Fuel Oil NA NAa 72.6 318.0 0.0% 318.0 31.8 CTDB2_1

PM2.5 Fuel Oil NA NAa 72.6 318.0 0.0% 318.0 31.8 CTDB2_2

SOx Fuel Oil NA NAa 96.8 423.9 0.0% 423.9 42.3 CTDB2_1

NOx Fuel Oil NA NAa 381.9 1672.6 80.0% 276.5 26.4 CTDB2_1

VOC Fuel Oil NA NAa 42.3 185.4 40.0% 111.2 17.1 CTDB2_1

CO Fuel Oil NA NAa 261.5 1145.2 90.0% 114.5 25.2 CTDB2_1

Lead Fuel Oil NA 1.4E‐05 0.032 0.139 0.0% 0.139 0.014 CTDB2_9

H2SO4 Fuel Oil NA NAa14.69 64.34 0.0% 64.34 6.4 CTDB2_5

References:CTDB2_1

CTDB2_2

CTDB2_3

CTDB2_4

CTDB2_5

CTDB2_9

Notes:

GHG

UnitCombustion Turbine Fuel Duct Burner Fuel Pollutant GWP






(tpy)

Limited Emissions

(tpy)

Duct Burner ‐ Natural Gas CO2 1 116.98 93,581 409,884 0.00% 409,884 409,884

Duct Burner ‐ Natural Gas CH4 25 2.2E‐03 1.76 7.72 0.00% 7.72 7.72

Duct Burner ‐ Natural Gas N2O 298 2.2E‐04 0.18 0.77 0.00% 0.77 0.77

Duct Burner ‐ Natural Gas CO2e ‐ 117.10 93,678 410,307 0.00% 410,307 410,307

Combustion Turbine Natural Gas ‐ CO2 1 116.98 243,544 1,066,724 0.00% 1,066,724 1,066,724

Combustion Turbine Natural Gas ‐ CH4 25 2.2E‐03 4.59 20.10 0.00% 20.10 20.10

Combustion Turbine Natural Gas ‐ N2O 298 2.2E‐04 0.46 2.01 0.00% 2.01 2.01

Combustion Turbine Natural Gas ‐ CO2e ‐ 117.10 243,796 1,067,825 0.00% 1,067,825 1,067,825

Combustion Turbine Fuel Oil ‐ CO2 1 163.05 365,726 1,601,880 0.00% 1,601,880 160,005

Combustion Turbine Fuel Oil ‐ CH4 25 6.6E‐03 14.83 64.98 0.00% 64.98 6.49

Combustion Turbine Fuel Oil ‐ N2O 298 1.3E‐03 2.97 13.00 0.00% 13.00 1.30

Combustion Turbine Fuel Oil ‐ CO2e ‐ 163.61 366,981 1,607,377 0.00% 1,607,377 160,554

Limited Emissions for Combustion Turbine:

Combustion Turbine Mix ‐ CO2 ‐ ‐ ‐ ‐ ‐ ‐ 1,120,178

Combustion Turbine Mix ‐ CH4 ‐ ‐ ‐ ‐ ‐ ‐ 24.59

Combustion Turbine Mix ‐ N2O ‐ ‐ ‐ ‐ ‐ ‐ 3.11

Combustion Turbine Mix ‐ CO2e ‐ ‐ ‐ ‐ ‐ ‐ 1,121,719


Notes:Limited emissions for Fuel Oil calculations based on fuel oil operating hours limit as described previously.

aThe hourly emission rates provided for the lb/hr Emission Rate are worst‐case projected emissions for the combined cycle system, based on several different operating scenarios at varying heat input capacities for the combustion turbine. The emission rate also includes the duct burner natural gas combustion emissions. These lb/hr Emission Rates do not correlate directly to the maximum heat input capacity provided above. Therefore, a specific lb/MMBtu emission factor is not relevant to the combined cycle system emission rates provided on this form.bThe combined cycle system maximum hourly emission rate is a worst‐case composite emission scenario that is based on the combustion turbine's highest hourly emission operating scenario (combinations of load, ambient temperature) for each pollutant, which is based on vendor data. The emission rate also incorporates the maximum hourly duct burner emissions.cAnnual maximum uncontrolled emissions are conservatively estimated based on the maximum hourly emission rate and do not incorporate the proposed combustion turbine fuel oil operating usage limit or BACT limits.

PM2.5 emission factor assumed equal to PM emisison factorBased on Permit 01300098‐002 emission limit

No data for lead available in AP‐42 Section 3.1 "Stationary Gas Turbines" (rev 04/00) Table 3.1‐4; used natural gas lead emission factor from AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Table 1.4‐2H2SO4 calculated as percentage of SO2 emission factor.Lead emission factor for Fuel oil from from AP‐42 Section 3.1 "Stationary Gas Turbines" (rev 04/00); Table 3.1‐5

See "Worst Case Emissions CT1 CT2" sheet for emission factor selection and/or calculation, based on fuel type.

fThe combustion turbine will be limited to firing low sulfur distillate fuel oil (no greater than 0.05% sulfur by weight) and will meet the fuel oil operating hours limit as described previously.

dThe NOx, CO, and VOC control efficiencies only represent a nominal control efficiency and are not used to calculate Controlled Emissions.

eThe combustion turbine and the duct burners vent to a common stack. Therefore, the maximum controlled emissions represent the calculated maximum controlled emissions at ambient conditions for the combined cycle system, which includes both the combustion turbine and duct burners. Natural gas‐fired controlled emissions based on the following BACT limits: 3.0 ppmvd NOx @ 15% O2; 4.0 ppmvd CO @15% O2; 3.4 ppmvd VOC @15% O2. Fuel oil‐fired controlled emissions based on the following BACT limits: 5.5 ppmvd NOx @ 15% O2; 4.8 ppmvd CO @15% O2; 7.1 ppmvd VOC @15% O2.

See GHG Table, Natural Gas emission factors, Fuel Oil emission factors



HAPs

UnitCombustion Turbine Fuel Duct Burner Fuel Pollutant CAS #







(tpy)

Limited Emissions

(tpy) ReferenceDuct Burner ‐ Natural Gas Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_13

Duct Burner ‐ Natural Gas Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_13

Duct Burner ‐ Natural Gas Arsenic 7440‐38‐2 2.00E‐04 1.96E‐07 1.57E‐04 6.87E‐04 0.00% 6.87E‐04 6.87E‐04 CTDB2_13

Duct Burner ‐ Natural Gas Benzene 71‐43‐2 2.10E‐03 2.06E‐06 1.65E‐03 7.21E‐03 0.00% 7.21E‐03 7.21E‐03 CTDB2_13

Duct Burner ‐ Natural Gas 1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_13

Duct Burner ‐ Natural Gas Beryllium 7440‐41‐7 1.20E‐05 1.18E‐08 9.41E‐06 4.12E‐05 0.00% 4.12E‐05 4.12E‐05 CTDB2_13

Duct Burner ‐ Natural Gas Cadmium 7440‐43‐9 1.10E‐03 1.08E‐06 8.63E‐04 3.78E‐03 0.00% 3.78E‐03 3.78E‐03 CTDB2_13

Duct Burner ‐ Natural Gas Chromium 7440‐47‐3 1.40E‐03 1.37E‐06 1.10E‐03 4.81E‐03 0.00% 4.81E‐03 4.81E‐03 CTDB2_13

Duct Burner ‐ Natural Gas Cobalt 744‐48‐4 8.40E‐05 8.24E‐08 6.59E‐05 2.89E‐04 0.00% 2.89E‐04 2.89E‐04 CTDB2_13

Duct Burner ‐ Natural Gas Dichlorobenzene 25321‐22‐6 1.20E‐03 1.18E‐06 9.41E‐04 4.12E‐03 0.00% 4.12E‐03 4.12E‐03 CTDB2_13

Duct Burner ‐ Natural Gas Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_13

Duct Burner ‐ Natural Gas Formaldehyde 50‐00‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_12

Duct Burner ‐ Natural Gas Hexane 110‐54‐3 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_12

Duct Burner ‐ Natural Gas Manganese 7439‐96‐5 3.80E‐04 3.73E‐07 2.98E‐04 1.31E‐03 0.00% 1.31E‐03 1.31E‐03 CTDB2_13

Duct Burner ‐ Natural Gas Mercury 7439‐97‐6 2.60E‐04 2.55E‐07 2.04E‐04 8.93E‐04 0.00% 8.93E‐04 8.93E‐04 CTDB2_13

Duct Burner ‐ Natural Gas Naphthalene 91‐20‐3 6.10E‐04 5.98E‐07 4.78E‐04 2.10E‐03 0.00% 2.10E‐03 2.10E‐03 CTDB2_13

Duct Burner ‐ Natural Gas Nickel 7440‐02‐0 2.10E‐03 2.06E‐06 1.65E‐03 7.21E‐03 0.00% 7.21E‐03 7.21E‐03 CTDB2_13

Duct Burner ‐ Natural Gas PAH ‐ ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_13

Duct Burner ‐ Natural Gas POM ‐ 6.98E‐04 6.85E‐07 5.48E‐04 2.40E‐03 0.00% 2.40E‐03 2.40E‐03 CTDB2_13

Duct Burner ‐ Natural Gas Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_13

Duct Burner ‐ Natural Gas Selenium 7782‐49‐2 2.40E‐05 2.35E‐08 1.88E‐05 8.24E‐05 0.00% 8.24E‐05 8.24E‐05 CTDB2_13

Duct Burner ‐ Natural Gas Toluene 108‐88‐3 3.40E‐03 3.33E‐06 2.67E‐03 1.17E‐02 0.00% 1.17E‐02 1.17E‐02 CTDB2_13

Duct Burner ‐ Natural Gas Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_13Reference

Combustion Turbine Natural Gas ‐ Acetaldehyde 75‐07‐0 ‐ 4.00E‐05 8.33E‐02 3.65E‐01 0.00% 3.65E‐01 3.65E‐01 CTDB2_6

Combustion Turbine Natural Gas ‐ Acrolein 107‐02‐8 ‐ 6.40E‐06 1.33E‐02 5.84E‐02 0.00% 5.84E‐02 5.84E‐02 CTDB2_6

Combustion Turbine Natural Gas ‐ Arsenic 7440‐38‐2 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_6

Combustion Turbine Natural Gas ‐ Benzene 71‐43‐2 ‐ 1.20E‐05 2.50E‐02 1.09E‐01 0.00% 1.09E‐01 1.09E‐01 CTDB2_6

Combustion Turbine Natural Gas ‐ 1,3‐Butadiene 106‐99‐0 ‐ 4.29E‐07 8.93E‐04 3.91E‐03 0.00% 3.91E‐03 3.91E‐03 CTDB2_6

Combustion Turbine Natural Gas ‐ Beryllium 7440‐41‐7 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_6

Combustion Turbine Natural Gas ‐ Cadmium 7440‐43‐9 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_6

Combustion Turbine Natural Gas ‐ Chromium 7440‐47‐3 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_6

Combustion Turbine Natural Gas ‐ Cobalt 744‐48‐4 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_6

Combustion Turbine Natural Gas ‐ Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_6

Combustion Turbine Natural Gas ‐ Ethylbenzene 100‐41‐4 ‐ 3.20E‐05 6.66E‐02 2.92E‐01 0.00% 2.92E‐01 2.92E‐01 CTDB2_6

Combustion Turbine Natural Gas ‐ Formaldehyde 50‐00‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_12

Combustion Turbine Natural Gas ‐ Hexane 110‐54‐3 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_12

Combustion Turbine Natural Gas ‐ Manganese 7439‐96‐5 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_6

Combustion Turbine Natural Gas ‐ Mercury 7439‐97‐6 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_6

Combustion Turbine Natural Gas ‐ Naphthalene 91‐20‐3 ‐ 1.30E‐06 2.71E‐03 1.19E‐02 0.00% 1.19E‐02 1.19E‐02 CTDB2_6

Combustion Turbine Natural Gas ‐ Nickel 7440‐02‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_6

Combustion Turbine Natural Gas ‐ PAH ‐ ‐ 2.20E‐06 4.58E‐03 2.01E‐02 0.00% 2.01E‐02 2.01E‐02 CTDB2_6

Combustion Turbine Natural Gas ‐ POM ‐ ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_6

Combustion Turbine Natural Gas ‐ Propylene Oxide 75‐56‐9 ‐ 2.90E‐05 6.04E‐02 2.64E‐01 0.00% 2.64E‐01 2.64E‐01 CTDB2_6

Combustion Turbine Natural Gas ‐ Selenium 7782‐49‐2 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_6

Combustion Turbine Natural Gas ‐ Toluene 108‐88‐3 ‐ 1.30E‐04 2.71E‐01 1.19E+00 0.00% 1.19E+00 1.19E+00 CTDB2_6

Combustion Turbine Natural Gas ‐ Xylenes 1330‐20‐7 ‐ 6.40E‐05 1.33E‐01 5.84E‐01 0.00% 5.84E‐01 5.84E‐01 CTDB2_6Reference

Combustion Turbine Fuel Oil ‐ Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_11

Combustion Turbine Fuel Oil ‐ Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_11

Combustion Turbine Fuel Oil ‐ Arsenic 7440‐38‐2 ‐ 1.10E‐05 2.47E‐02 1.08E‐01 0.00% 1.08E‐01 1.08E‐02 CTDB2_10

Combustion Turbine Fuel Oil ‐ Benzene 71‐43‐2 ‐ 5.50E‐05 1.23E‐01 5.40E‐01 0.00% 5.40E‐01 5.40E‐02 CTDB2_11

Combustion Turbine Fuel Oil ‐ 1,3‐Butadiene 106‐99‐0 ‐ 1.60E‐05 3.59E‐02 1.57E‐01 0.00% 1.57E‐01 1.57E‐02 CTDB2_11

Combustion Turbine Fuel Oil ‐ Beryllium 7440‐41‐7 ‐ 3.10E‐07 6.95E‐04 3.05E‐03 0.00% 3.05E‐03 3.04E‐04 CTDB2_10

Combustion Turbine Fuel Oil ‐ Cadmium 7440‐43‐9 ‐ 4.80E‐06 1.08E‐02 4.72E‐02 0.00% 4.72E‐02 4.71E‐03 CTDB2_10

Combustion Turbine Fuel Oil ‐ Chromium 7440‐47‐3 ‐ 1.10E‐05 2.47E‐02 1.08E‐01 0.00% 1.08E‐01 1.08E‐02 CTDB2_10

Combustion Turbine Fuel Oil ‐ Cobalt 744‐48‐4 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_10

Combustion Turbine Fuel Oil ‐ Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_11

Combustion Turbine Fuel Oil ‐ Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_11

Combustion Turbine Fuel Oil ‐ Formaldehyde 50‐00‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_12

Combustion Turbine Fuel Oil ‐ Hexane 110‐54‐3 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_12

Combustion Turbine Fuel Oil ‐ Manganese 7439‐96‐5 ‐ 7.90E‐04 1.77E+00 7.76E+00 0.00% 7.76E+00 7.75E‐01 CTDB2_10

Combustion Turbine Fuel Oil ‐ Mercury 7439‐97‐6 ‐ 1.20E‐06 2.69E‐03 1.18E‐02 0.00% 1.18E‐02 1.18E‐03 CTDB2_10

Combustion Turbine Fuel Oil ‐ Naphthalene 91‐20‐3 ‐ 3.50E‐05 7.85E‐02 3.44E‐01 0.00% 3.44E‐01 3.43E‐02 CTDB2_11

Combustion Turbine Fuel Oil ‐ Nickel 7440‐02‐0 ‐ 4.60E‐06 1.03E‐02 4.52E‐02 0.00% 4.52E‐02 4.51E‐03 CTDB2_10

Combustion Turbine Fuel Oil ‐ PAH ‐ ‐ 4.00E‐05 8.97E‐02 3.93E‐01 0.00% 3.93E‐01 3.93E‐02 CTDB2_11

Combustion Turbine Fuel Oil ‐ POM ‐ ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_11

Combustion Turbine Fuel Oil ‐ Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_11

Combustion Turbine Fuel Oil ‐ Selenium 7782‐49‐2 ‐ 2.50E‐05 5.61E‐02 2.46E‐01 0.00% 2.46E‐01 2.45E‐02 CTDB2_10

Combustion Turbine Fuel Oil ‐ Toluene 108‐88‐3 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_11

Combustion Turbine Fuel Oil ‐ Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ CTDB2_11

References:CTDB2_6

CTDB2_10

CTDB2_11

CTDB2_12

CTDB2_13

AP‐42 Section 3.1 "Stationary Gas Turbines" (rev 04/00); Table 3.1‐4

AP‐42 Section 3.1 "Stationary Gas Turbines" (rev 04/00)AP‐42 Section 3.1 "Stationary Gas Turbines" (rev 04/00); Table 3.1‐5

These pollutants are accounted for at the stack level in the combined CT and DB data.DB: AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Tables 1.4‐3 and 1.4‐4, sum of all pollutants listed as POM (including Naphthalene)



Limited Emissions for Combustion Turbine:








(tpy)

Limited Emissions

(tpy) ReferenceCombustion Turbine Mix ‐ Acetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ ‐ ‐ 3.28E‐01 ‐Combustion Turbine Mix ‐ Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ ‐ ‐ 5.25E‐02 ‐Combustion Turbine Mix ‐ Arsenic 7440‐38‐2 ‐ ‐ ‐ ‐ ‐ ‐ 1.08E‐02 ‐Combustion Turbine Mix ‐ Benzene 71‐43‐2 ‐ ‐ ‐ ‐ ‐ ‐ 1.52E‐01 ‐Combustion Turbine Mix ‐ 1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐ ‐ ‐ 1.92E‐02 ‐Combustion Turbine Mix ‐ Beryllium 7440‐41‐7 ‐ ‐ ‐ ‐ ‐ ‐ 3.04E‐04 ‐Combustion Turbine Mix ‐ Cadmium 7440‐43‐9 ‐ ‐ ‐ ‐ ‐ ‐ 4.71E‐03 ‐Combustion Turbine Mix ‐ Chromium 7440‐47‐3 ‐ ‐ ‐ ‐ ‐ ‐ 1.08E‐02 ‐Combustion Turbine Mix ‐ Cobalt 744‐48‐4 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐Combustion Turbine Mix ‐ Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐Combustion Turbine Mix ‐ Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ ‐ ‐ 2.63E‐01 ‐Combustion Turbine Mix ‐ Formaldehyde 50‐00‐0 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐Combustion Turbine Mix ‐ Hexane 110‐54‐3 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐Combustion Turbine Mix ‐ Manganese 7439‐96‐5 ‐ ‐ ‐ ‐ ‐ ‐ 7.75E‐01 ‐Combustion Turbine Mix ‐ Mercury 7439‐97‐6 ‐ ‐ ‐ ‐ ‐ ‐ 1.18E‐03 ‐Combustion Turbine Mix ‐ Naphthalene 91‐20‐3 ‐ ‐ ‐ ‐ ‐ ‐ 4.50E‐02 ‐Combustion Turbine Mix ‐ Nickel 7440‐02‐0 ‐ ‐ ‐ ‐ ‐ ‐ 4.51E‐03 ‐Combustion Turbine Mix ‐ PAH ‐ ‐ ‐ ‐ ‐ ‐ ‐ 5.73E‐02 ‐Combustion Turbine Mix ‐ POM ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐Combustion Turbine Mix ‐ Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ ‐ ‐ 2.38E‐01 ‐Combustion Turbine Mix ‐ Selenium 7782‐49‐2 ‐ ‐ ‐ ‐ ‐ ‐ 2.45E‐02 ‐Combustion Turbine Mix ‐ Toluene 108‐88‐3 ‐ ‐ ‐ ‐ ‐ ‐ 1.07E+00 ‐Combustion Turbine Mix ‐ Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ ‐ ‐ 5.25E‐01 ‐References:

CTDB2_6

Notes:Limited emissions for Fuel Oil calculations based on current fuel oil limit of 875 hours per year.




Formaldehyde and Hexane Emissions


Non‐SUSD Hours

Calculated Non‐SUSD Hours with FO Limit

Total Hours with SUSD Excluded

Total Event Hours Natural Gas 230 644 230 1104 7656 6781 7885Total Event Hours Fuel Oil 30 84 30 144 731 731 875








(tpy)

Limited Emissions

(tpy) ReferenceCombined Turbine & DB Natural Gas Natural Gas Formaldehyde (< 60% Load) 50‐00‐0 2882 0.00279 8.04 1104 35.22 0.00% 35.22 see GP 004 CTDB1_7

Combined Turbine & DB Natural Gas Natural Gas Formaldehyde (60 ‐ < 90% Load) 50‐00‐0 2882 0.00151 4.35 7656 19.06 0.00% 19.06 see GP 004 CTDB1_7

Combined Turbine & DB Natural Gas Natural Gas Formaldehyde (>= 90% Load) 50‐00‐0 2882 0.00105 3.03 0 13.25 0.00% 13.25 see GP 004 CTDB1_7

Combined Turbine & DB Natural Gas Natural Gas Hexane (Any Load) 110‐54‐3 2882 0.00034 0.98 8760 4.29 0.00% 4.29 see GP 004 CTDB1_8

Note: 0‐60% Load assumed to correspond to all SUSD Time; Conservatively assumed remaining time "Calculated Non‐SUSD Hours" is at 60‐90% load.Combined Turbine & DB Mix NG Natural Gas Formaldehyde (>= 90% Load) 50‐00‐0 2882 0.00105 3.03 6781 ‐ 0.00% ‐ see GP 004 CTDB1_7

Combined Turbine & DB Mix NG Natural Gas Hexane (Any Load) 110‐54‐3 2882 0.00034 0.98 7885 ‐ 0.00% ‐ see GP 004 CTDB1_8

Combustion Turbine Fuel Oil ‐ Formaldehyde (Any Load) 50‐00‐0 ‐ ‐ 2.28 875 9.99 0.00% 9.99 see GP 004 CTDB1_7

Combustion Turbine Fuel Oil ‐ Hexane (Any Load) 110‐54‐3 ‐ ‐ 0.04 875 0.18 0.00% 0.18 see GP 004 CTDB1_8

References:CTDB2_7

CTDB2_8

Formaldehyde and Hexane Totals:








(tpy)

Limited Emissions

(tpy)Combined Turbine & DB Natural Gas Natural Gas Formaldehyde total 50‐00‐0 2882 ‐ ‐ 8760 35.22 0.00% 35.22 see GP 004Combined Turbine & DB Natural Gas Natural Gas Hexane Total 110‐54‐3 2882 ‐ ‐ 8760 4.29 0.00% 4.29 see GP 004Combined Turbine & DB Mix Natural Gas Formaldehyde total 50‐00‐0 ‐ ‐ ‐ 8760 ‐ ‐ ‐ see GP 004Combined Turbine & DB Mix Natural Gas Hexane Total 110‐54‐3 ‐ ‐ ‐ 8760 ‐ ‐ ‐ see GP 004




Worst‐Case Emissions SummaryCombined Cycle (EU 002 and EU 004)Worst‐Case Criteria Pollutants Excludes SUSD Includes SUSD

Unit Pollutant


(tpy)

Controlled Emissions Before Operating Limits

(tpy)aWorst‐Case Combustion

Turbine FuelLimited Emissions

(tpy)b

Worst‐Case Combustion Turbine

Fuel

Emission Rate Based on Limited

Emissions(lb/hr)

Combined Turbine & DB PM 318.0 318.0 Fuel Oil 118.50 Fuel Oil 72.6

Combined Turbine & DB PM10 318.0 318.0 Fuel Oil 118.50 Fuel Oil 72.6

Combined Turbine & DB PM2.5 318.0 318.0 Fuel Oil 118.50 Fuel Oil 72.6

Combined Turbine & DB SOx 423.9 423.9 Fuel Oil 67.80 Fuel Oil 96.8

Combined Turbine & DB NOx 1672.6 276.5 Fuel Oil 174.13 Fuel Oil 63.1

Combined Turbine & DB VOC 185.4 111.2 Fuel Oil 262.00 Fuel Oil 25.4

Combined Turbine & DB CO 1145.2 114.5 Fuel Oil 477.94 Fuel Oil 26.1

Combined Turbine & DB Lead 0.139 0.139 Fuel Oil 1.95E‐02 Fuel Oil 0.03

Combined Turbine & DB H2SO4 64.3 64.3 Fuel Oil 10.29 Fuel Oil 14.7

EU 002 Combustion Turbine onlyWorst‐Case GHG Pollutants

Unit Pollutant Combustion Turbine FuelEmission Rate

(lb/hr)Combustion Turbine Fuel


(tpy)Combustion Turbine Fuel

Limited Emissions

(tpy)

Combustion Turbine CO2 Fuel Oil 365,726 Fuel Oil 1,601,880 Natural Gas 1,066,724

Combustion Turbine CH4 Fuel Oil 14.83 Fuel Oil 64.98 Natural Gas 20.10

Combustion Turbine N2O Fuel Oil 2.97 Fuel Oil 13.00 Natural Gas 2.01

Combustion Turbine CO2e Fuel Oil 366,981 Fuel Oil 1,607,377 Natural Gas 1,067,825

EU 002 Combustion Turbine only, SV 002 for Formaldehyde and HexaneWorst‐Case HAPs

Unit Pollutant CAS # Combustion Turbine FuelEmission Rate

(lb/hr)Combustion Turbine Fuel


(tpy)Combustion Turbine Fuel

Limited Emissions

(tpy)Combustion Turbine Acetaldehyde 75‐07‐0 Natural Gas 8.33E‐02 Natural Gas 3.65E‐01 Natural Gas 3.65E‐01Combustion Turbine Acrolein 107‐02‐8 Natural Gas 1.33E‐02 Natural Gas 5.84E‐02 Natural Gas 5.84E‐02Combustion Turbine Arsenic 7440‐38‐2 Fuel Oil 2.47E‐02 Fuel Oil 1.08E‐01 Fuel Oil 1.08E‐02Combustion Turbine Benzene 71‐43‐2 Fuel Oil 1.23E‐01 Fuel Oil 5.40E‐01 Mix 1.52E‐01Combustion Turbine 1,3‐Butadiene 106‐99‐0 Fuel Oil 3.59E‐02 Fuel Oil 1.57E‐01 Mix 1.92E‐02Combustion Turbine Beryllium 7440‐41‐7 Fuel Oil 6.95E‐04 Fuel Oil 3.05E‐03 Fuel Oil 3.04E‐04Combustion Turbine Cadmium 7440‐43‐9 Fuel Oil 1.08E‐02 Fuel Oil 4.72E‐02 Fuel Oil 4.71E‐03Combustion Turbine Chromium 7440‐47‐3 Fuel Oil 2.47E‐02 Fuel Oil 1.08E‐01 Fuel Oil 1.08E‐02Combustion Turbine Cobalt 744‐48‐4 ‐ ‐ ‐ ‐ ‐ ‐Combustion Turbine Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ ‐ ‐ ‐Combustion Turbine Ethylbenzene 100‐41‐4 Natural Gas 6.66E‐02 Natural Gas 2.92E‐01 Natural Gas 2.92E‐01Combined Turbine & DB Formaldehyde 50‐00‐0 Natural Gas 8.04 Natural Gas 35.22 Natural Gas see GP 004Combined Turbine & DB Hexane 110‐54‐3 Natural Gas 0.98 Natural Gas 4.29 Natural Gas see GP 004Combustion Turbine Manganese 7439‐96‐5 Fuel Oil 1.77E+00 Fuel Oil 7.76E+00 Fuel Oil 7.75E‐01Combustion Turbine Mercury 7439‐97‐6 Fuel Oil 2.69E‐03 Fuel Oil 1.18E‐02 Fuel Oil 1.18E‐03Combustion Turbine Naphthalene 91‐20‐3 Fuel Oil 7.85E‐02 Fuel Oil 3.44E‐01 Mix 4.50E‐02Combustion Turbine Nickel 7440‐02‐0 Fuel Oil 1.03E‐02 Fuel Oil 4.52E‐02 Fuel Oil 4.51E‐03Combustion Turbine PAH ‐ Fuel Oil 8.97E‐02 Fuel Oil 3.93E‐01 Mix 5.73E‐02Combustion Turbine POM ‐ ‐ ‐ ‐ ‐ ‐ ‐Combustion Turbine Propylene Oxide 75‐56‐9 Natural Gas 6.04E‐02 Natural Gas 2.64E‐01 Natural Gas 2.64E‐01Combustion Turbine Selenium 7782‐49‐2 Fuel Oil 5.61E‐02 Fuel Oil 2.46E‐01 Fuel Oil 2.45E‐02Combustion Turbine Toluene 108‐88‐3 Natural Gas 2.71E‐01 Natural Gas 1.19E+00 Natural Gas 1.19E+00

Combustion Turbine Xylenes 1330‐20‐7 Natural Gas 1.33E‐01 Natural Gas 5.84E‐01 Natural Gas 5.84E‐01Combustion Turbine Total HAPs ‐ NA ‐ NA ‐ NANotes:For Limited Emissions, "Mix" refers to the combustion turbine firing fuel oil up to the operating hour limit, and firing natural gas for the remainder of the hours in the year.Due to Formaldehyde and Hexane emissions being calculated at the stack level, Total HAPs for combustion turbine alone are not able to be meaningfully calculated.

aRepresents the worst case annual conctrolled criteria pollutant emissions, which incorporated the proposed natural gas and fuel oil BACT limits.b Limited emissions assume a worst‐case emission scenario for PM, PM10, SOx, NOx, VOC, CO, Lead, and H2SO4, where the turbine operates on fuel oil for 875 hours per year and the remainder of the year (7,885 hours) the turbine fires natural gas and includes the startup and shutdown emissions for NOx and CO.


Mankato Energy CenterFacility ID: 013000982015 Air Permit Application Auxiliary Boiler

Unit InformationDescription: Auxiliary BoilerUnit Delta ID: EU 005 Unit Tempo ID: EQUI 7Stack Delta ID: SV 003 Stack Tempo ID: STRU 17Fuel Natural GasHeat Input Capacity 70 MMBtu/hr

Fuel Heat Value 1020 Btu/scf

Fuel Consumption Rate 68,627.5 scf/hr

Hours Uncontrolled 8760

Hours Limited 8760

Criteria Pollutants

PollutantEmission Factor (lb/106 scf)

Emission Factor

(lb/MMBtu)





(tpy)

Limited Emissions

(tpy) Reference

PM ‐ 8.0E‐03 0.56 2.45 0.00% 2.45 2.45 AB1

PM10 ‐ 8.0E‐03 0.56 2.45 0.00% 2.45 2.45 AB1

PM2.5 ‐ 8.0E‐03 0.56 2.45 0.00% 2.45 2.45 AB3

SOx ‐ 1.0E‐03 0.070 0.31 0.00% 0.31 0.31 AB1

NOx ‐ 3.6E‐02 2.52 11.04 0.00% 11.04 11.04 AB1

VOC ‐ 7.0E‐03 0.49 2.15 0.00% 2.15 2.15 AB1

CO ‐ 6.0E‐02 4.20 18.40 0.00% 18.40 18.40 AB1

Lead 5.00E‐04 4.9E‐07 3.43E‐05 1.5E‐04 0.00% 1.5E‐04 1.5E‐04 AB2

References:AB1

AB2

AB3

GHG

Pollutant GWP

Emission Factor

(lb/MMBtu)





(tpy)

Limited Emissions

(tpy)CO2 1 116.98 8,188.3 35,864.9 0.00% 35,864.9 35,864.9

CH4 25 2.2E‐03 0.15 0.68 0.00% 0.68 0.68

N2O 298 2.2E‐04 0.015 0.07 0.00% 0.07 0.07

CO2e ‐ 117.10 8,196.8 35,901.9 0.00% 35,901.9 35,901.9


Based on Auxiliary Boiler emission limits in Permit 01300098‐002AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Table 1.4‐2PM2.5 emission rate assumed equal to total PM rate


C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Aux Boiler]

Mankato Energy CenterFacility ID: 013000982015 Air Permit Application Auxiliary Boiler

HAPs

Pollutant CAS #

Emission Factor

(lb/106 scf)

Emission Factor

(lb/MMBtu)Emission Rate

(lb/hr)




(tpy)

Limited Emissions

(tpy) ReferenceAcetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ AB4

Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ AB4

Arsenic 7440‐38‐2 2.00E‐04 1.96E‐07 1.37E‐05 6.01E‐05 0.00% 6.01E‐05 6.01E‐05 AB4

Benzene 71‐43‐2 2.10E‐03 2.06E‐06 1.44E‐04 6.31E‐04 0.00% 6.31E‐04 6.31E‐04 AB4

1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ AB4

Beryllium 7440‐41‐7 1.20E‐05 1.18E‐08 8.24E‐07 3.61E‐06 0.00% 3.61E‐06 3.61E‐06 AB4

Cadmium 7440‐43‐9 1.10E‐03 1.08E‐06 7.55E‐05 3.31E‐04 0.00% 3.31E‐04 3.31E‐04 AB4

Chromium 7440‐47‐3 1.40E‐03 1.37E‐06 9.61E‐05 4.21E‐04 0.00% 4.21E‐04 4.21E‐04 AB4

Cobalt 744‐48‐4 8.40E‐05 8.24E‐08 5.76E‐06 2.52E‐05 0.00% 2.52E‐05 2.52E‐05 AB4

Dichlorobenzene 25321‐22‐6 1.20E‐03 1.18E‐06 8.24E‐05 3.61E‐04 0.00% 3.61E‐04 3.61E‐04 AB4

Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ AB4

Formaldehyde 50‐00‐0 7.50E‐02 7.35E‐05 5.15E‐03 2.25E‐02 0.00% 2.25E‐02 2.25E‐02 AB4

Hexane 110‐54‐3 1.80E+00 1.76E‐03 1.24E‐01 5.41E‐01 0.00% 5.41E‐01 5.41E‐01 AB4

Manganese 7439‐96‐5 3.80E‐04 3.73E‐07 2.61E‐05 1.14E‐04 0.00% 1.14E‐04 1.14E‐04 AB4

Mercury 7439‐97‐6 2.60E‐04 2.55E‐07 1.78E‐05 7.82E‐05 0.00% 7.82E‐05 7.82E‐05 AB4

Naphthalene 91‐20‐3 6.10E‐04 5.98E‐07 4.19E‐05 1.83E‐04 0.00% 1.83E‐04 1.83E‐04 AB4

Nickel 7440‐02‐0 2.10E‐03 2.06E‐06 1.44E‐04 6.31E‐04 0.00% 6.31E‐04 6.31E‐04 AB4

PAH ‐ ‐ ‐ ‐ ‐ 0.00% ‐ ‐ AB4

POM ‐ 6.98E‐04 6.85E‐07 4.79E‐05 2.10E‐04 0.00% 2.10E‐04 2.10E‐04 AB5

Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ AB4

Selenium 7782‐49‐2 2.40E‐05 2.35E‐08 1.65E‐06 7.21E‐06 0.00% 7.21E‐06 7.21E‐06 AB4

Toluene 108‐88‐3 3.40E‐03 3.33E‐06 2.33E‐04 1.02E‐03 0.00% 1.02E‐03 1.02E‐03 AB4

Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ AB4

Total HAPs 1.30E‐01 5.67E‐01 5.67E‐01 5.67E‐01References:

AB4

AB5

AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Tables 1.4‐3 and 1.4‐4AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Tables 1.4‐3 and 1.4‐4, sum of all pollutants listed as POM (including Naphthalene)

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Aux Boiler]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationFire Pump

Unit InformationDescription: Fire Pump EngineUnit Delta ID: EU 007 Unit Tempo ID: EQUI 11Stack Delta ID: SV 005 Stack Tempo ID: STRU 18Fuel Diesel 0.05% SulfurHeat Input Capacity 350 HP Conversion SourceHeat Input Capacity 2.45 MMBtu/hr 0.007 MMBtu/hp‐hr AP‐42 Section 3.3 footnote

Fuel Heat Value 140,000 Btu/gal

Fuel Consumption Rate 17.5 gal/hr (maximum)


Hours Limited 100

Note: This generator unit is only intended to be used for emergency purposes. The facility will limit the non‐emergency operation of this unit to 100 hours per year.

Criteria Pollutants

PollutantEmission Factor

(lb/hp‐hr)Emission Rate

(lb/hr)




(tpy)

Limited Emissions

(tpy) Reference

PM 2.4E‐04 0.08 0.004 0.00% 0.004 0.004 FP1

PM10 2.4E‐04 0.08 0.004 0.00% 0.004 0.004 FP1

PM2.5 2.4E‐04 0.08 0.004 0.00% 0.004 0.004 FP1

SOx 3.3E‐04 0.116 0.006 0.00% 0.006 0.006 FP1

NOx ‐ 3.37 0.169 0.00% 0.169 0.169 FP2

VOC 4.4E‐04 0.15 0.008 0.00% 0.008 0.008 FP1

CO 1.4E‐03 0.48 0.024 0.00% 0.024 0.024 FP1

Lead 0.0E+00 0.00E+00 0.0E+00 0.00% 0.0E+00 0.0E+00 FP3

References:FP1

FP2

FP3

GHG

Pollutant GWPEmission Factor (lb/MMBtu)





(tpy)

Limited Emissions

(tpy)CO2 1 163.05 399.5 20.0 0.00% 20.0 20.0

CH4 25 6.6E‐03 1.62E‐02 8.10E‐04 0.00% 8.10E‐04 8.10E‐04N2O 298 1.3E‐03 3.24E‐03 1.62E‐04 0.00% 1.62E‐04 1.62E‐04CO2e ‐ 163.61 400.8 20.0 0.00% 20.0 20.0


Based on Vendor Data, at 350 braking hp (See Fire Pump data sheet)Based on Vendor Data, at 300 braking hp (See Fire Pump data sheet)

See GHG Table, Fuel Oil emission factors

No data for lead in AP‐42 Section 3.3 "Gasoline and Diesel Industrial Engines" (Rev 10/96); or in vendor data

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Fire Pump]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationFire Pump

HAPs

Pollutant CAS #Emission Factor (lb/MMBtu)





(tpy)

Limited Emissions

(tpy) ReferenceAcetaldehyde 75‐07‐0 7.67E‐04 1.88E‐03 9.40E‐05 0.00% 9.40E‐05 9.40E‐05 FP4

Acrolein 107‐02‐8 9.25E‐05 2.27E‐04 1.13E‐05 0.00% 1.13E‐05 1.13E‐05 FP4

Arsenic 7440‐38‐2 ‐ ‐ ‐ 0.00% ‐ ‐ FP4

Benzene 71‐43‐2 9.33E‐04 2.29E‐03 1.14E‐04 0.00% 1.14E‐04 1.14E‐04 FP4

1,3‐Butadiene 106‐99‐0 3.91E‐05 9.58E‐05 4.79E‐06 0.00% 4.79E‐06 4.79E‐06 FP4

Beryllium 7440‐41‐7 ‐ ‐ ‐ 0.00% ‐ ‐ FP4

Cadmium 7440‐43‐9 ‐ ‐ ‐ 0.00% ‐ ‐ FP4

Chromium 7440‐47‐3 ‐ ‐ ‐ 0.00% ‐ ‐ FP4

Cobalt 744‐48‐4 ‐ ‐ ‐ 0.00% ‐ ‐ FP4

Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ 0.00% ‐ ‐ FP4

Ethylbenzene 100‐41‐4 ‐ ‐ ‐ 0.00% ‐ ‐ FP4

Formaldehyde 50‐00‐0 1.18E‐03 2.89E‐03 1.45E‐04 0.00% 1.45E‐04 1.45E‐04 FP4

Hexane 110‐54‐3 ‐ ‐ ‐ 0.00% ‐ ‐ FP4

Manganese 7439‐96‐5 ‐ ‐ ‐ 0.00% ‐ ‐ FP4

Mercury 7439‐97‐6 ‐ ‐ ‐ 0.00% ‐ ‐ FP4

Naphthalene 91‐20‐3 8.48E‐05 2.08E‐04 1.04E‐05 0.00% 1.04E‐05 1.04E‐05 FP4

Nickel 7440‐02‐0 ‐ ‐ ‐ 0.00% ‐ ‐ FP4

PAH ‐ 1.68E‐04 4.12E‐04 2.06E‐05 0.00% 2.06E‐05 2.06E‐05 FP5

POM ‐ ‐ ‐ ‐ 0.00% ‐ ‐ FP4

Propylene Oxide 75‐56‐9 ‐ ‐ ‐ 0.00% ‐ ‐ FP4

Selenium 7782‐49‐2 ‐ ‐ ‐ 0.00% ‐ ‐ FP4

Toluene 108‐88‐3 4.09E‐04 1.00E‐03 5.01E‐05 0.00% 5.01E‐05 5.01E‐05 FP4

Xylenes 1330‐20‐7 2.85E‐04 6.98E‐04 3.49E‐05 0.00% 3.49E‐05 3.49E‐05 FP4


FP4

FP5

AP‐42 Section 3.3 "Gasoline and Diesel Industrial Engines" (Rev 10/96); Table 3.3‐2 AP‐42 Section 3.3 "Gasoline and Diesel Industrial Engines" (Rev 10/96); Table 3.3‐2; Total PAH includes Naphthalene which is also separately counted

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Fire Pump]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationDiesel Fired Emergency Generator

Unit InformationDescription: Diesel Fired Emergency GeneratorUnit Delta ID: EU 010 Unit Tempo ID: EQUI 18Stack Delta ID: SV 008 Stack Tempo ID: STRU 21Fuel Diesel 0.05% SulfurHeat Input Capacity 2500 kW Conversion SourceHeat Input Capacity 3634 bHP 0.007 MMBtu/hp‐hr AP‐42 Section 3.4 footnoteHeat Input Capacity 25.44 MMBtu/hr

Fuel Heat ValueFuel Consumption RateHours Uncontrolled 500

Hours Limited 100

Note: This generator unit is only intended to be used for emergency purposes. The facility will limit the non‐emergency operation of this unit to 100 hours per year.

Criteria Pollutants

Pollutant

Emission Factor

(lb/hp‐hr)Emission Rate

(lb/hr)




(tpy)

Limited Emissions

(tpy) Reference

PM 6.1E‐05 0.15 0.04 0.00% 0.04 0.01 EG1

PM10 6.1E‐05 0.15 0.04 0.00% 0.04 0.01 EG1

PM2.5 6.1E‐05 0.15 0.04 0.00% 0.04 0.01 EG1

SOx 2.1E‐03 5.125 1.28 0.00% 1.28 0.26 EG3

NOx 5.3E‐03 13.27 3.32 0.00% 3.32 0.66 EG1

VOC 2.9E‐04 0.72 0.18 0.00% 0.18 0.04 EG1

CO 5.3E‐03 13.27 3.32 0.00% 3.32 0.66 EG2

Lead 0.0E+00 0.00E+00 0.0E+00 0.00% 0.0E+00 0.0E+00 EG3

References:EG1

EG2

EG3

GHG

Pollutant GWP

Emission Factor


(lb/hr)




(tpy)

Limited Emissions

(tpy)

CO2 1 163.05 4,147.7 1,036.9 0.00% 1,036.9 207.4

CH4 25 6.6E‐03 1.68E‐01 4.21E‐02 0.00% 4.21E‐02 8.41E‐03N2O 298 1.3E‐03 3.36E‐02 8.41E‐03 0.00% 8.41E‐03 1.68E‐03CO2e ‐ 163.61 4,162.0 1,040.5 0.00% 1,040.5 208.1


No data for lead in AP‐42 Section 3.4 " Large Stationary Diesel And All Stationary Dual‐fuel Engines" (Rev 10/96); or in AP‐42 Section 3.3 "Gasoline and Diesel Industrial Engines" (Rev 10/96)

See GHG Table, Fuel Oil emission factors

Based on Nonroad Compression‐Ignition Engines ‐‐ Exhaust Emission Standards (40 CFR 1039.101), for 2500 kW, converted from g/kW‐hr to lb/hp‐hr

Based on Vendor Data, at 3633 braking hp, converted from g/hp‐hr to lb/hp‐hr

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Emerg Gen]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationDiesel Fired Emergency Generator

HAPs

Pollutant CAS #

Emission Factor


(lb/hr)




(tpy)

Limited Emissions

(tpy) ReferenceAcetaldehyde 75‐07‐0 2.52E‐05 6.41E‐04 1.60E‐04 0.00% 1.60E‐04 3.21E‐05 EG4

Acrolein 107‐02‐8 7.88E‐06 2.00E‐04 5.01E‐05 0.00% 5.01E‐05 1.00E‐05 EG4

Arsenic 7440‐38‐2 ‐ ‐ ‐ 0.00% ‐ ‐ EG4

Benzene 71‐43‐2 7.76E‐04 1.97E‐02 4.93E‐03 0.00% 4.93E‐03 9.87E‐04 EG4

1,3‐Butadiene 106‐99‐0 3.91E‐05 9.95E‐04 2.49E‐04 0.00% 2.49E‐04 4.97E‐05 EG5

Beryllium 7440‐41‐7 ‐ ‐ ‐ 0.00% ‐ ‐ EG4

Cadmium 7440‐43‐9 ‐ ‐ ‐ 0.00% ‐ ‐ EG4

Chromium 7440‐47‐3 ‐ ‐ ‐ 0.00% ‐ ‐ EG4

Cobalt 744‐48‐4 ‐ ‐ ‐ 0.00% ‐ ‐ EG4

Dichlorobenzene 25321‐22‐6 ‐ ‐ ‐ 0.00% ‐ ‐ EG4

Ethylbenzene 100‐41‐4 ‐ ‐ ‐ 0.00% ‐ ‐ EG4

Formaldehyde 50‐00‐0 7.89E‐05 2.01E‐03 5.02E‐04 0.00% 5.02E‐04 1.00E‐04 EG4

Hexane 110‐54‐3 ‐ ‐ ‐ 0.00% ‐ ‐ EG4

Manganese 7439‐96‐5 ‐ ‐ ‐ 0.00% ‐ ‐ EG4

Mercury 7439‐97‐6 ‐ ‐ ‐ 0.00% ‐ ‐ EG4

Naphthalene 91‐20‐3 1.30E‐04 3.31E‐03 8.27E‐04 0.00% 8.27E‐04 1.65E‐04 EG6

Nickel 7440‐02‐0 ‐ ‐ ‐ 0.00% ‐ ‐ EG4

PAH ‐ 2.12E‐04 5.39E‐03 1.35E‐03 0.00% 1.35E‐03 2.70E‐04 EG6

POM ‐ ‐ ‐ ‐ 0.00% ‐ ‐ EG4

Propylene Oxide 75‐56‐9 ‐ ‐ ‐ 0.00% ‐ ‐ EG4

Selenium 7782‐49‐2 ‐ ‐ ‐ 0.00% ‐ ‐ EG4

Toluene 108‐88‐3 2.81E‐04 7.15E‐03 1.79E‐03 0.00% 1.79E‐03 3.57E‐04 EG4

Xylenes 1330‐20‐7 1.93E‐04 4.91E‐03 1.23E‐03 0.00% 1.23E‐03 2.45E‐04 EG4


EG4

EG5

EG6 AP‐42 Section 3.4 " Large Stationary Diesel And All Stationary Dual‐fuel Engines" (Rev 10/96); Table 3.4‐4; Total PAH includes Naphthalene which is also separately counted

AP‐42 Section 3.3 "Gasoline and Diesel Industrial Engines" (Rev 10/96); Table 3.3‐2. (No data for 1,3‐Butadiene in AP‐42 Section 3.4)AP‐42 Section 3.4 " Large Stationary Diesel And All Stationary Dual‐fuel Engines" (Rev 10/96); Table 3.4‐3

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Emerg Gen]

Mankato Energy CenterFacility ID: 013000982015 Air Permit Application Indirect Gas‐fired Water Bath Heater

Unit InformationDescription: Bath HeaterUnit Delta ID: EU 011 Unit Tempo ID: EQUI 19Stack Delta ID: SV 009 Stack Tempo ID: STRU 22Fuel Natural GasHeat Input Capacity 2.87 MMBtu/hr

Fuel Heat Value 1020 Btu/scf

Fuel Consumption Rate 2,813.7 scf/hr


Hours Limited 8760

Criteria Pollutants

PollutantEmission Factor (lb/106 scf)






(tpy)

Limited Emissions

(tpy)

MN Rule 7007.1300 Subp 3(I)lb/yr

MN Rule 7007.1300 Subp 3(I)

tpyAbove

Threshold?

MN Rule 7007.1300 Subp 4lb/hr

Above Threshold? Reference

PM 7.6 7.5E‐03 0.021 0.09 0.00% 0.09 0.09 2,000 1.0 No 2.28 No BH2

PM10 7.6 7.5E‐03 0.021 0.09 0.00% 0.09 0.09 2,000 1.0 No 2.28 No BH2

PM2.5 7.6 7.5E‐03 0.021 0.09 0.00% 0.09 0.09 ‐ ‐ ‐ ‐ ‐ BH2

SOx 0.6 5.9E‐04 0.0017 0.01 0.00% 0.01 0.01 2,000 1.0 No 2.28 No BH2

NOx 100 9.8E‐02 0.28 1.23 0.00% 1.23 1.23 2,000 1.0 Yes 2.28 No BH1

VOC 5.5 5.4E‐03 0.015 0.07 0.00% 0.07 0.07 2,000 1.0 No 2.28 No BH2

CO 84 8.2E‐02 0.236 1.04 0.00% 1.04 1.04 4,000 2.0 No 5.7 No BH1

Lead 0.0005 4.9E‐07 1.41E‐06 6.2E‐06 0.00% 6.2E‐06 6.2E‐06 ‐ ‐ ‐ ‐ ‐ BH2

References:BH1

BH2

GHG

Pollutant GWPEmission Factor (lb/MMBtu)





(tpy)

Limited Emissions

(tpy)

MN Rule 7007.1300 Subp 3(I)

tpyAbove

Threshold?

MN Rule 7007.1300 Subp 4tpy

Above Threshold?

CO2 1 116.98 335.7 1,470.5 0.00% 1,470.5 1,470.5 ‐ ‐ ‐ ‐CH4 25 2.2E‐03 6.33E‐03 2.77E‐02 0.00% 2.77E‐02 2.77E‐02 ‐ ‐ ‐ ‐N2O 298 2.2E‐04 6.33E‐04 2.77E‐03 0.00% 2.77E‐03 2.77E‐03 ‐ ‐ ‐ ‐CO2e ‐ 117.10 336.1 1,472.0 0.00% 1,472.0 1,472.0 1,000 Yes 10,000 No


AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Table 1.4‐1; Small Boilers, UncontrolledAP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Table 1.4‐2


C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Bath Heater]

Mankato Energy CenterFacility ID: 013000982015 Air Permit Application Indirect Gas‐fired Water Bath Heater

HAPs

Pollutant CAS #Emission Factor (lb/106 scf)

Emission Factor


(lb/hr)




(tpy)

Limited Emissions

(tpy) ReferenceAcetaldehyde 75‐07‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ BH3

Acrolein 107‐02‐8 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ BH3

Arsenic 7440‐38‐2 2.0E‐04 1.96E‐07 5.63E‐07 2.46E‐06 0.00% 2.46E‐06 2.46E‐06 BH3

Benzene 71‐43‐2 2.1E‐03 2.06E‐06 5.91E‐06 2.59E‐05 0.00% 2.59E‐05 2.59E‐05 BH3

1,3‐Butadiene 106‐99‐0 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ BH3

Beryllium 7440‐41‐7 1.2E‐05 1.18E‐08 3.38E‐08 1.48E‐07 0.00% 1.48E‐07 1.48E‐07 BH3

Cadmium 7440‐43‐9 1.1E‐03 1.08E‐06 3.10E‐06 1.36E‐05 0.00% 1.36E‐05 1.36E‐05 BH3

Chromium 7440‐47‐3 1.4E‐03 1.37E‐06 3.94E‐06 1.73E‐05 0.00% 1.73E‐05 1.73E‐05 BH3

Cobalt 744‐48‐4 8.4E‐05 8.24E‐08 2.36E‐07 1.04E‐06 0.00% 1.04E‐06 1.04E‐06 BH3

Dichlorobenzene 25321‐22‐6 1.2E‐03 1.18E‐06 3.38E‐06 1.48E‐05 0.00% 1.48E‐05 1.48E‐05 BH3

Ethylbenzene 100‐41‐4 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ BH3

Formaldehyde 50‐00‐0 7.5E‐02 7.35E‐05 2.11E‐04 9.24E‐04 0.00% 9.24E‐04 9.24E‐04 BH3

Hexane 110‐54‐3 1.8E+00 1.76E‐03 5.06E‐03 2.22E‐02 0.00% 2.22E‐02 2.22E‐02 BH3

Manganese 7439‐96‐5 3.8E‐04 3.73E‐07 1.07E‐06 4.68E‐06 0.00% 4.68E‐06 4.68E‐06 BH3

Mercury 7439‐97‐6 2.6E‐04 2.55E‐07 7.32E‐07 3.20E‐06 0.00% 3.20E‐06 3.20E‐06 BH3

Naphthalene 91‐20‐3 6.1E‐04 5.98E‐07 1.72E‐06 7.52E‐06 0.00% 7.52E‐06 7.52E‐06 BH3

Nickel 7440‐02‐0 2.1E‐03 2.06E‐06 5.91E‐06 2.59E‐05 0.00% 2.59E‐05 2.59E‐05 BH3

PAH ‐ ‐ ‐ ‐ ‐ 0.00% ‐ ‐ BH3

POM ‐ 7.0E‐04 6.85E‐07 1.96E‐06 8.60E‐06 0.00% 8.60E‐06 8.60E‐06 BH4

Propylene Oxide 75‐56‐9 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ BH3

Selenium 7782‐49‐2 2.4E‐05 2.35E‐08 6.75E‐08 2.96E‐07 0.00% 2.96E‐07 2.96E‐07 BH3

Toluene 108‐88‐3 3.4E‐03 3.33E‐06 9.57E‐06 4.19E‐05 0.00% 4.19E‐05 4.19E‐05 BH3

Xylenes 1330‐20‐7 ‐ ‐ ‐ ‐ 0.00% ‐ ‐ BH3


BH3

BH4

AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Tables 1.4‐3 and 1.4‐4AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Tables 1.4‐3 and 1.4‐4, sum of all pollutants listed as POM (including Naphthalene)

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Bath Heater]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationCooling Tower

Unit InformationDescription: Cooling TowerUnit Delta ID: FS 001 Unit Tempo ID: FUGI 1Material Water

Drift Rate 0.0005%

Cycles 6

Make‐up Water TDS 1206 mg/L

Flow rate 200,000 gal/min

Control Equipment Mist eliminator


Hours Limited 8760

Make‐up Water TDS from correspondence 3‐13‐15.

PM emission factor is based on AP‐42 Section 13.4 "Wet Cooling Towers" (Rev 01/95) described procedures for estimating cooling tower water TDS.Emission Factor (lb/gal) = TDS * C * Dr * 3.785 L/gal * 1 g/1,000 mg * 1 lb/453.59 gwhere

TDS = Make‐up water TDS in mg/L

C = number of cyclesDr = drift rate

Emission Factor = 3.02E‐07 lb/gal

Particulate Matter

PollutantEmission Factor

(lb/gal)

Maximum Flow Rate(gal/min)

Wt % of PM emissions





(tpy)

Limited Emissions

(tpy)

PM 3.02E‐07 200,000 100.0% 3.62 15.87 0.00% 15.87 15.87

PM10 ‐‐‐ ‐‐‐ 17.0% 0.62 2.70 0.00% 2.70 2.70

PM2.5 ‐‐‐ ‐‐‐ 0.133% 0.005 0.021 0.00% 0.021 0.021

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Cooling Tower]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationCooling Tower

EPRI Droplet Droplet Particle Solid Solid EPRI % Wt% PM10 Wt% PM2.5

Droplet Volume Mass Mass Particle Particle Mass in PM in PMDiameter (Solids) Volume Diameter Smaller Emissions Emissions(µm) (µm3) (µg) (µg) (µm3) (µm) (%) (%) (%)10 524 5.24E‐04 3.79E‐06 1.72 1.487 0.000

20 4189 4.19E‐03 3.03E‐05 13.78 2.974 0.196 0.13330 14137 1.41E‐02 1.02E‐04 46.50 4.461 0.226

40 33510 3.35E‐02 2.42E‐04 110.22 5.949 0.514

50 65450 6.54E‐02 4.74E‐04 215.27 7.436 1.816

60 113097 1.13E‐01 8.18E‐04 371.99 8.923 5.702

70 179594 1.80E‐01 1.30E‐03 590.70 10.410 21.348 17.03390 381704 3.82E‐01 2.76E‐03 1255.46 13.384 49.812

110 696910 6.97E‐01 5.04E‐03 2292.20 16.359 70.509

130 1150347 1.15E+00 8.32E‐03 3783.59 19.333 82.023

150 1767146 1.77E+00 1.28E‐02 5812.30 22.307 88.012

180 3053628 3.05E+00 2.21E‐02 10043.66 26.769 91.032

210 4849048 4.85E+00 3.51E‐02 15948.96 31.230 92.468

240 7238229 7.24E+00 5.24E‐02 23807.19 35.692 94.091

270 10305995 1.03E+01 7.46E‐02 33897.35 40.153 94.689

300 14137167 1.41E+01 1.02E‐01 46498.43 44.615 96.288

350 22449298 2.24E+01 1.62E‐01 73837.78 52.051 97.011

400 33510322 3.35E+01 2.42E‐01 110218.49 59.487 98.340

450 47712938 4.77E+01 3.45E‐01 156932.19 66.922 99.071

500 65449847 6.54E+01 4.74E‐01 215270.50 74.358 99.071

600 113097336 1.13E+02 8.18E‐01 371987.42 89.230 100.000

PM10 and PM2.5 calculated as fraction of PM emissions using emission calculation procedure in "Calculating Realistic PM10

Emissions from Cooling Towers" by Reisman and Frisbie, Environmental Progress, Vol. 21, No.2.Assumptions: Droplet TDS: 7236 mg/L

Droplet TDS: 0.007 g/mL

Droplet TDS: 7236 ppm

water density: 1.0 g/cm3

particle density: 2.2 g/cm3

No Pollutants other than PM in Cooling Tower emissions.

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Cooling Tower]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationNatural Gas Fugitives Emissions

Fugitive Whole Gas Emissions Estimates for Natural Gas

FS 002 Density: 0.043 lb/scf Density of Natural gas. See Note 3 below.Conversion: 2.2046 lb/kg

Components serving CT/DB #1 CO2 Methane

0.27 (scf/hr/component) 0.012 (lb/hr/component)(3) 0.02 0.098 2.13 9.33




0.0150 (kg/hr/component) 0.033 (lb/hr/component) 0.0006 0.0027 0.06 0.26

Total: 0.24 1.07 23.27 101.92

Global Warming Potentials: 1 1 25 25

CO2e Emissions: 0.24 1.07 581.75 2548.08Total CO2e emissions: 582.00 2549.15

Components serving CT/DB #2 CO2 Methane






Total: 0.24 1.07 23.27 101.92



Components serving Common Systems CO2 Methane






Total: 0.15 0.66 14.34 62.81



Total Facility Fugitive Natural Gas CO2 Methane






Total: 0.64 2.80 60.88 266.65



Note 1: Emissions factors were obtained from 40 CFR Part 98 Subpart W "Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems; Final Rule" [77 FR 51494, Aug. 24, 2012]; Table W‐7, Default Methane Emission Factors for Natural Gas Distribution.Note 2: Emission factors were obtained from the kg/hr/component SOCMI emissions factors from "Protocol for Equipment Leak Emissions Estimates" (EPA‐453/R‐95‐017), Table 2‐1 (11/1995).Note 3: The density of natural gas was obtained from CFR 600.113‐93 (h) §538.7. Density of natural gas = 0.044 lb/cf (@60 F) = 0.043 lb/scf (@70 F).CO2 emissions based on mole % of CO2 in natural gas 0.93% from natural gas analysis 8/15/2014CH4 emissions based on mole % of CH4 in natural gas 88.60% from natural gas analysis 8/15/2014

Open‐Ended Lines(1) 22

34

Emission Factor Emission Factor

Emission Rate (lb/hr)

Emission Rate (tpy)

9

Sampling Connections (2)

20

Emission Rate (lb/hr) Emission Rate (tpy)

Emission Rate (lb/hr)

Valves(1) 207

Flanges/Connectors(1) 187

Relief Valves(1) 8

Open‐Ended Lines(1)

Component Type

Emission Rate (tpy)

Natural Gas

Valves(1) 619


Relief Valves(1)

Service Component Type Component Count Emission Factor Emission Factor

Sampling Connections (2) 38


Natural Gas

Valves(1) 205


Relief Valves(1) 4


Sampling Connections (2)



Sampling Connections (2) 2

Emission Rate (tpy)Component Count Emission Factor Emission Factor Emission Rate (lb/hr)

Service Component Type Component Count

2

Emission Rate (tpy)

Natural Gas

Service


Natural Gas

Valves(1) 207


Relief Valves(1) 8

Service Component Type Component Count Emission Factor Emission Factor Emission Rate (lb/hr)

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[NG Fugitive]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationBreaker Fugitives Emissions

FS 003

Breaker TypeQuantity of SF6(lb/breaker) Potential Operating Time

Generator 35 8760 hr

HV ‐ 115kV 72

HV ‐ 345kV 324

Existing Breakers

Breaker TypeQuantity of SF6(lb/breaker)

Number of Breakers

Leakage Rate (per year)

SF6(lb/hr)

SF6(tpy)

Global Warming Potential

CO2e(lb/hr)

CO2e(tpy)

Generator 35 2 0.5% 4.00E‐05 1.75E‐04 22,800 0.9 4.0

HV ‐ 115kV 72 1 0.5% 4.11E‐05 1.80E‐04 22,800 0.9 4.1

HV ‐ 345kV 324 1 0.5% 1.85E‐04 8.10E‐04 22,800 4.2 18.5

Total SF6: 2.66E‐04 1.17E‐03 Total CO2e: 6.1 26.6

Breakers for Expansion


Number of Breakers


SF6(lb/hr)

SF6(tpy)


CO2e(lb/hr)

CO2e(tpy)

Generator 35 1 0.5% 2.00E‐05 8.75E‐05 22,800 0.5 2.0

HV ‐ 115kV 72 1 0.5% 4.11E‐05 1.80E‐04 22,800 0.9 4.1


FS 003 ‐ All Breakers


Number of Breakers


SF6(lb/hr)

SF6(tpy)


CO2e(lb/hr)

CO2e(tpy)

Generator 35 3 0.5% 5.99E‐05 2.63E‐04 22,800 1.4 6.0

HV ‐ 115kV 72 2 0.5% 8.22E‐05 3.60E‐04 22,800 1.9 8.2

HV ‐ 345kV 324 1 0.5% 1.85E‐04 8.10E‐04 22,800 4.2 18.5


Note: Leakage Rates assumed to be on an annual basis for the purposes of estimating potential emissions.

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Breakers]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationFuel Tank

Unit InformationDescription: Fuel Oil Storage TankUnit Delta ID: TK 001 Unit Tempo ID: NA, Insignificant

Material Diesel Storage Potential Operating TimeCapacity 900,000 gal 8760 hr

Data obtained from TANKS 4.09d runDate of run: 10/23/2015

303.62 lb working loss18.09 lb breathing loss

321.71 lbs of VOC total

Emissions Summary





(tpy)

Limited Emissions

(tpy)VOC 0.04 0.16 0% 0.16 0.16

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Fuel Tank]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationFire Pump Fuel Tank

Unit InformationDescription: Fire Pump Fuel TankUnit Delta ID: NA, Insignificant Activity Unit Tempo ID: NA, Insignificant Activity

Material Diesel Storage Potential Operating TimeCapacity 360 gal 8760 hr


0.02 lb working loss0.03 lb breathing loss0.05 lbs of VOC total

Emissions Summary






(tpy)VOC 5.71E‐06 2.50E‐05 0% 2.50E‐05 2.50E‐05

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[FP Tank]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationEmergency Generator Diesel Fuel Tank

Unit InformationDescription: Emergency Generator Diesel Fuel TankUnit Delta ID: NA, Insignificant Activity Unit Tempo ID: EQUI 23

Material Diesel Storage Potential Operating TimeCapacity 5,000 gal 8760 hr


0.09 lb working loss0.46 lb breathing loss0.55 lbs of VOC total

Emissions Summary






(tpy)VOC 6.28E‐05 2.75E‐04 0% 2.75E‐04 2.75E‐04

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[EG Tank]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationNatural Gas Condensate Tank ‐ Plant

Unit Information

Unit InformationDescription: Natural Gas Condensate Tank ‐ PlantUnit Delta ID: NA, Insignificant Activity Unit Tempo ID: EQUI 24

Material Natural Gas condensate Potential Operating TimeCapacity 6,615 gal 8760 hr

Condensate Tank Emissions

Pollutant Calculated Emissions

Avg. Hourly Emissions (lb/hr)

Maximum Hourly

Emissions (lb/hr) 1

Annual Emissions (TPY) 2

NOX

Assumptions: COHours per year of operation 8,760 VOC 0.05 tons/yr 0.01 0.01 0.05

PM10

PM2.5

Tank Volume, gallons 6615 From email correspondence 10/22/15 SO2

NotesAnnual Throughput, gallons 661.5 Estimate of 10% of Tank Volume

TANKS 4.09d Total Emissions Date of run: 10/23/2015Working Loss, pounds 0.74Breathing Loss, pounds 84.98Total Loss, lbs 85.72Total Loss, tons 0.04Flash Gas Quantification Using Vasquez‐Beggs Correlation

Value CommentsAPI = NG API Gravity 78 Default valueC1 = Vasquez‐Beggs constant 0.0178 If APIG > 30o, then C1 = 0.0178; else C1 = 0.0362C2 = Vasquez‐Beggs constant 1.187 If APIG > 30°, then C2 = 1.187; else C2 = 1.0937C3 = Vasquez‐Beggs constant 23.931 If APIG > 30°, then C3 = 23.931; else C3 = 25.724SG = Specific gravity of gas in separator, air = 1.0 0.9 From gas analysis obtained from upstream vessel

UVP = Upstream Vessel Pressure, psig 40 Vessel upstream of flash source (tanks)T = Upstream Temperature, °F 100 Default = 100°F (fluid temperature in upstream vessel)

TOC = TOC weight percent, wt.% of total stream 80 Removes gas constituents such as N2, CO2, H2S, etc.Pa = Atmospheric Pressure, psia 14.696 Default = 14.696Q = Throughput, bbls/yr 15.8

Mv = Vapor Molecular Weight, lb/lb‐mole 49 Default Crude = 50E = Control Efficiency, % reduction 0 Efficiency of any control device present (flare, VRU, etc.)

Me = Methane Weight Percent 0 Natural Gas SDS; EP Energy 8/1/2012Et = Ethane Weight Percent 60 Natural Gas SDS; EP Energy 8/1/2012

Calculated ParametersCSG = Corrected specific gravity 0.77 SG*(1.0+0.00005912*API*T*log[(UVP+Pa)/114.7]GOR = Gas to oil ratio 44.21 C1*CSG*(UVP+Pa)^C28exp[(C3*API)/(T+460)]LfTOT = Flash losses TOC, tons 0.04 GOR*Q*Mv/379*(100‐E)/100*TOC/100/2000

VOC Emissions, tons 0.01 (TOC‐Me‐Et)/TOC*LfTOTMethane Emissions, tons 0.00 (Me/TOC)*LfTOTEthane Emissions, tons 0.03 (Et/TOC)*LfTOT

1 Maximum hourly emissions are assumed to be the same as the hourly emissions.2 Annual emissions are based on 8760 hours per year of operation.3 Below IA threshold

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Cond TK plant]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationNatural Gas Condensate Tank ‐ CT1

Unit Information

Unit InformationDescription: Natural Gas Condensate Tank ‐ CT1Unit Delta ID: NA, Insignificant Activity Unit Tempo ID: NA, Insignificant Activity

Material Natural Gas condensate Potential Operating TimeCapacity 45 gal 8760 hr




Maximum Hourly

Emissions (lb/hr) 1


NOX

Assumptions: COHours per year of operation 8,760 VOC 1.65E‐03 tons/yr 3.76E‐04 3.76E‐04 1.65E‐03

PM10

Tank Volume, bbls ‐ From Design Drawing PM2.5

Tank Volume, gallons 50 From Design Drawing SO2

NotesAnnual Throughput, gallons 5 Estimate of 10% of Tank Volume

TANKS 4.09d Total Emissions Date of run: 10/23/2015Working Loss, pounds 0.01Breathing Loss, pounds 3.15Total Loss, lbs 3.16Total Loss, tons 1.58E‐03Flash Gas Quantification Using Vasquez‐Beggs Correlation






Calculated ParametersCSG = Corrected specific gravity 0.77 SG*(1.0+0.00005912*API*T*log[(UVP+Pa)/114.7]GOR = Gas to oil ratio 44.21 C1*CSG*(UVP+Pa)^C28exp[(C3*API)/(T+460)]LfTOT = Flash losses TOC, tons 2.72E‐04 GOR*Q*Mv/379*(100‐E)/100*TOC/100/2000

VOC Emissions, tons 6.80E‐05 (TOC‐Me‐Et)/TOC*LfTOTMethane Emissions, tons 0.00E+00 (Me/TOC)*LfTOTEthane Emissions, tons 2.04E‐04 (Et/TOC)*LfTOT

1 Maximum hourly emissions are assumed to be the same as the hourly emissions.2 Annual emissions are based on 8760 hours per year of operation.

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Cond TK CT1]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationNatural Gas Condensate Tank ‐ CT2

Unit Information

Unit InformationDescription: Natural Gas Condensate Tank ‐ CT2Unit Delta ID: NA, Insignificant Activity Unit Tempo ID: NA, Insignificant Activity

Material Natural Gas condensate Potential Operating TimeCapacity 45 gal 8760 hr




Maximum Hourly

Emissions (lb/hr) 1


NOX

Assumptions: COHours per year of operation 8,760 VOC 1.65E‐03 tons/yr 3.76E‐04 3.76E‐04 1.65E‐03

PM10

Tank Volume, bbls ‐ From Design Drawing PM2.5

Tank Volume, gallons 50 From Design Drawing SO2

NotesAnnual Throughput, gallons 5 Estimate of 10% of Tank Volume

TANKS 4.09d Total Emissions Date of run: 10/23/2015Working Loss, pounds 0.01Breathing Loss, pounds 3.15Total Loss, lbs 3.16Total Loss, tons 1.58E‐03Flash Gas Quantification Using Vasquez‐Beggs Correlation






Calculated ParametersCSG = Corrected specific gravity 0.77 SG*(1.0+0.00005912*API*T*log[(UVP+Pa)/114.7]GOR = Gas to oil ratio 44.21 C1*CSG*(UVP+Pa)^C28exp[(C3*API)/(T+460)]LfTOT = Flash losses TOC, tons 2.72E‐04 GOR*Q*Mv/379*(100‐E)/100*TOC/100/2000

VOC Emissions, tons 6.80E‐05 (TOC‐Me‐Et)/TOC*LfTOTMethane Emissions, tons 0.00E+00 (Me/TOC)*LfTOTEthane Emissions, tons 2.04E‐04 (Et/TOC)*LfTOT

1 Maximum hourly emissions are assumed to be the same as the hourly emissions.2 Annual emissions are based on 8760 hours per year of operation.

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Cond TK CT2]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationUnit General Information Sheet

DELTA info TEMPO info

Emission Source Description Stack/Vent ID EU FS TK(SV, BG)"STRU" ID

(EU, TK, MR, DAS)"EQUI" ID

(FS)"FUGI" ID

Combined Cycle System #2 002 ‐ ‐ ‐ STRU 14 ‐ ‐Combustion Turbine #2 002 002 ‐ ‐ STRU 14 EQUI 5 ‐Duct Burners (Combustion Turbine #2) 002 004 ‐ ‐ STRU 14 EQUI 6 ‐

Combined Cycle System #1 007 ‐ ‐ ‐ STRU 20 ‐ ‐ Combustion Turbine #1 007 008 ‐ ‐ STRU 20 EQUI 16 ‐Duct Burners (Combustion Turbine #1) 007 009 ‐ ‐ STRU 20 EQUI 17 ‐

Auxiliary Boiler 003 005 ‐ ‐ STRU 17 EQUI 7 ‐Fire Pump Engine 005 007 ‐ ‐ STRU 18 EQUI 11 ‐Diesel Fired Emergency Generator 008 010 ‐ ‐ STRU 21 EQUI 18 ‐Bath Heater 009 011 ‐ ‐ STRU 22 EQUI 19 ‐

‐ ‐ ‐ ‐ ‐ ‐Cooling Tower NA ‐ 001 ‐ NA ‐ FUGI 1Natural Gas Fugitives NA ‐ 002 ‐ NA ‐ FUGI 2Breaker Fugitives NA ‐ 003 ‐ NA ‐ FUGI 3Fuel Oil Storage Tank NA ‐ ‐ 001 NA IA ‐

Emission Units Fugitive Sources Tank Sources

DescriptionCombustion Turbine #2

Duct Burners (Combustion Turbine #2)

Combustion Turbine #1

Duct Burners (Combustion Turbine #1)

Auxiliary Boiler

Fire Pump Engine

Diesel Fired Emergency Generator Bath Heater Description

Cooling Tower

Natural Gas Fugitives

Breaker Fugitives Description Fuel Oil Storage Tank Fire Pump Fuel Tank

Emergency Generator Diesel

Fuel Tank

Natural Gas Condensate Tank ‐

Plant


CT1


CT2Delta ID No. (EU) 002 004 008 009 005 007 010 011 Delta ID No. (FS) 001 002 003 Delta ID No. (TK) 001 NA, Insignificant Activity NA, Insignificant Activity NA, Insignificant Activity NA, Insignificant Activity NA, Insignificant Activity

Tempo ID No. (EQUI) EQUI 5 EQUI 6 EQUI 16 EQUI 17 EQUI 7 EQUI 11 EQUI 18 EQUI 19 Tempo ID No. (FUGI) FUGI 1 FUGI 2 FUGI 3 Tempo ID No. (EQUI) NA, Insignificant Activity NA, Insignificant Activity EQUI 23 EQUI 24 NA, Insignificant Activity NA, Insignificant Activity

Fuel 1 Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Diesel Diesel Natural Gas Material Water Natural Gas SF6 Material Diesel Storage Diesel Storage Diesel StorageNatural Gas condensate

Natural Gas condensate

Natural Gas condensate

Fuel 2 Fuel Oil ‐ ‐ ‐ ‐ ‐ ‐ ‐ Drift Rate 0.0005% NA NA Capacity (gal) 900,000 360 5,000 6,615 45 45

Heat Input Capacity 2082 800 2253.3 823.7 70 350 2500 2.87 Cycles 6 NA NA Capacity Units gal gal gal gal gal gal

Heat Input Units MMBtu/hr MMBtu/hr MMBtu/hr MMBtu/hr MMBtu/hr HP kW MMBtu/hr TDS (mg/L) 1500 NA NA

Heat Input Capacity 2 2243 3634 Flow rate (gal/min) 200,000 NA NA

Heat Input Units 2 MMBtu/hr bHP SF6 Leakage Rate NA NA 0.5%

Control Equipment 1 DescriptionDry Low NOx

burners

Dry Low NOx burners None None None None Control Equipment 1 Description

Mist eliminator NA NA

CE1 Delta ID (CE) 002 010 CE1 Delta ID (CE) NA

CE1 Tempo ID (TREA) TREA 9 TREA 10 CE1 Tempo ID (TREA) NA

CE1 Control Efficiency 71 ‐ NOx 71 ‐ NOx CE1 Control Efficiency NA

Control Equipment 2 Description

Steam or Water

Injection Total Particulate Control Efficiency NA

CE2 Delta ID (CE) 004

CE2 Tempo ID (TREA) TREA 4CE2 Control Efficiency 82 ‐ NOx

Control Equipment 3 Description

Selective Catalytic Reduction




CE3 Delta ID (CE) 006 006 011 011

CE3 Tempo ID (TREA) TREA 5 TREA 5 TREA 11 TREA 11CE3 Control Efficiency 80 ‐ NOx 80 ‐ NOx 80 ‐ NOx 80 ‐ NOx

Control Equipment 4 DescriptionCatalytic Oxidizer Catalytic Oxidizer

Catalytic Oxidizer Catalytic Oxidizer

CE4 Delta ID (CE) 008 008 012 012

CE4 Tempo ID (TREA) TREA 6 TREA 6 TREA 12 TREA 12

CE4 Control Efficiency90 ‐ CO40 ‐ VOC

90 ‐ CO40 ‐ VOC

90 ‐ CO40 ‐ VOC

90 ‐ CO40 ‐ VOC

Stack Delta ID No. (SV) 002 002 007 007 003 005 008 009

Stack Tempo ID No. (STRU) STRU 14 STRU 14 STRU 20 STRU 20 STRU 17 STRU 18 STRU 21 STRU 22

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Unit Info]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationEmission Factor Data Sheet

EU EU 008 EU 009 EU 002 EU 004FS

TK

SV SV 007 SV 002

Unit Description:

Combustion Turbine #1 ‐ Natural Gas Units Source

Combustion Turbine #1 ‐ Duct Burner Units Source

Combustion Turbine #2 ‐ Natural Gas Units Source

Combustion Turbine #2 ‐ Fuel Oil Units Source

Combustion Turbine #2 ‐ Duct Burner

PM 11.9 lb/hr CTDB1_1 ‐ Combined CTDB1_9 22 lb/hr CTDB2_1 72.6 lb/hr CTDB2_1 ‐ Combined CTDB2_12

PM10 11.9 lb/hr CTDB1_1 ‐ Combined CTDB1_9 22 lb/hr CTDB2_1 72.6 lb/hr CTDB2_1 ‐ Combined CTDB2_12

PM2.5 11.9 lb/hr CTDB1_2 ‐ Combined CTDB1_9 22 lb/hr CTDB2_2 72.6 lb/hr CTDB2_2 ‐ Combined CTDB2_12

SO2 2.2409E‐03 lb/MMBtu CTDB1_3 ‐ Combined CTDB1_9 2.2409E‐03 lb/MMBtu CTDB2_3 96.8 lb/hr CTDB2_1 ‐ Combined CTDB2_12

NOx 273.7 lb/hr CTDB1_1 ‐ Combined CTDB1_9 256.0 lb/hr CTDB2_1 381.9 lb/hr CTDB2_1 ‐ Combined CTDB2_12

VOC 25.1 lb/hr CTDB1_1 ‐ Combined CTDB1_9 19.2 lb/hr CTDB2_1 42.3 lb/hr CTDB2_1 ‐ Combined CTDB2_12

CO 169.5 lb/hr CTDB1_1 ‐ Combined CTDB1_9 119.1 lb/hr CTDB2_1 261.5 lb/hr CTDB2_1 ‐ Combined CTDB2_12

Pb 0.0005 lb/ 106 scf CTDB1_4 ‐ Combined CTDB1_9 0.0005 lb/ 106 scf CTDB2_4 1.40E‐05 lb/MMBtu CTDB2_9 ‐ Combined CTDB2_12

H2SO4 15.179% Calculated CTDB1_5 ‐ Combined CTDB1_9 15.179% Calculated CTDB2_5 15.179% Calculated CTDB2_5 ‐ Combined CTDB2_12

CO2eCO2 116.98 lb/MMBtu GHG Table 116.98 lb/MMBtu GHG Table 116.98 lb/MMBtu GHG Table 163.05 lb/MMBtu GHG Table 116.98 lb/MMBtu GHG TableCH4 2.2E‐03 lb/MMBtu GHG Table 2.2E‐03 lb/MMBtu GHG Table 2.2E‐03 lb/MMBtu GHG Table 6.6E‐03 lb/MMBtu GHG Table 2.2E‐03 lb/MMBtu GHG TableN2O 2.2E‐04 lb/MMBtu GHG Table 2.2E‐04 lb/MMBtu GHG Table 2.2E‐04 lb/MMBtu GHG Table 1.3E‐03 lb/MMBtu GHG Table 2.2E‐04 lb/MMBtu GHG TableSF6 ‐ NA ‐ ‐ NA ‐ NA ‐ ‐ NA ‐ ‐ NA ‐Individual HAPS: CAS #

Acetaldehyde 75‐07‐0 4.0E‐05 lb/MMBtu CTDB1_6 ‐ ND CTDB1_10 4.0E‐05 lb/MMBtu CTDB2_6 ‐ ND CTDB2_11 ‐ ND CTDB2_13

Acrolein 107‐02‐8 6.4E‐06 lb/MMBtu CTDB1_6 ‐ ND CTDB1_10 6.4E‐06 lb/MMBtu CTDB2_6 ‐ ND CTDB2_11 ‐ ND CTDB2_13

Arsenic 7440‐38‐2 ‐ lb/MMBtu CTDB1_6 2.0E‐04 lb/MMscf CTDB1_10 ‐ lb/MMBtu CTDB2_6 1.1E‐05 lb/MMBtu CTDB2_10 2.0E‐04 lb/MMscf CTDB2_13

Benzene 71‐43‐2 1.2E‐05 lb/MMBtu CTDB1_6 2.1E‐03 lb/MMscf CTDB1_10 1.2E‐05 lb/MMBtu CTDB2_6 5.5E‐05 lb/MMBtu CTDB2_11 2.1E‐03 lb/MMscf CTDB2_13

1,3‐Butadiene 106‐99‐0 4.3E‐07 lb/MMBtu CTDB1_6 ‐ ND CTDB1_10 4.3E‐07 lb/MMBtu CTDB2_6 1.6E‐05 lb/MMBtu CTDB2_11 ‐ ND CTDB2_13

Beryllium 7440‐41‐7 ‐ ND CTDB1_6 1.2E‐05 lb/MMscf CTDB1_10 ‐ ND CTDB2_6 3.1E‐07 lb/MMBtu CTDB2_10 1.2E‐05 lb/MMscf CTDB2_13

Cadmium 7440‐43‐9 ‐ ND CTDB1_6 1.1E‐03 lb/MMscf CTDB1_10 ‐ ND CTDB2_6 4.8E‐06 lb/MMBtu CTDB2_10 1.1E‐03 lb/MMscf CTDB2_13

Chromium 7440‐47‐3 ‐ ND CTDB1_6 1.4E‐03 lb/MMscf CTDB1_10 ‐ ND CTDB2_6 1.1E‐05 lb/MMBtu CTDB2_10 1.4E‐03 lb/MMscf CTDB2_13

Cobalt 744‐48‐4 ‐ ND CTDB1_6 8.4E‐05 lb/MMscf CTDB1_10 ‐ ND CTDB2_6 ‐ ND CTDB2_10 8.4E‐05 lb/MMscf CTDB2_13

Dichlorobenzene 25321‐22‐6 ‐ ND CTDB1_6 1.2E‐03 lb/MMscf CTDB1_10 ‐ ND CTDB2_6 ‐ ND CTDB2_11 1.2E‐03 lb/MMscf CTDB2_13

Ethylbenzene 100‐41‐4 3.2E‐05 lb/MMBtu CTDB1_6 ‐ ND CTDB1_10 3.2E‐05 lb/MMBtu CTDB2_6 ‐ ND CTDB2_11 ‐ ND CTDB2_13

Formaldehyde 50‐00‐0 ‐ NA see below ‐ Combined CTDB1_9 ‐ NA see below ‐ Combined CTDB2_12 ‐ Combined CTDB2_12

Hexane 110‐54‐3 ‐ NA see below ‐ Combined CTDB1_9 ‐ NA see below ‐ Combined CTDB2_12 ‐ Combined CTDB2_12

Manganese 7439‐96‐5 ‐ ND CTDB1_6 3.8E‐04 lb/MMscf CTDB1_10 ‐ ND CTDB2_6 7.9E‐04 lb/MMBtu CTDB2_10 3.8E‐04 lb/MMscf CTDB2_13

Mercury 7439‐97‐6 ‐ ND CTDB1_6 2.6E‐04 lb/MMscf CTDB1_10 ‐ ND CTDB2_6 1.2E‐06 lb/MMBtu CTDB2_10 2.6E‐04 lb/MMscf CTDB2_13

Naphthalene 91‐20‐3 1.3E‐06 lb/MMBtu CTDB1_6 6.1E‐04 lb/MMscf CTDB1_10 1.3E‐06 lb/MMBtu CTDB2_6 3.5E‐05 lb/MMBtu CTDB2_11 6.1E‐04 lb/MMscf CTDB2_13

Nickel 7440‐02‐0 ‐ ND CTDB1_6 2.1E‐03 lb/MMscf CTDB1_10 ‐ ND CTDB2_6 4.6E‐06 lb/MMBtu CTDB2_10 2.1E‐03 lb/MMscf CTDB2_13

PAH ‐ 2.2E‐06 lb/MMBtu CTDB1_6 ‐ ND CTDB1_10 2.2E‐06 lb/MMBtu CTDB2_6 4.0E‐05 lb/MMBtu CTDB2_11 ‐ ND CTDB2_13

POM ‐ ‐ ND CTDB1_6 6.98E‐04 lb/MMscf CTDB1_10 ‐ ND CTDB2_6 ‐ ND CTDB2_11 6.98E‐04 lb/MMscf CTDB2_13

Propylene Oxide 75‐56‐9 2.9E‐05 lb/MMBtu CTDB1_6 ‐ ND CTDB1_10 2.9E‐05 lb/MMBtu CTDB2_6 ‐ ND CTDB2_11 ‐ ND CTDB2_13

Selenium 7782‐49‐2 ‐ ND CTDB1_6 2.4E‐05 lb/MMscf CTDB1_10 ‐ ND CTDB2_6 2.5E‐05 lb/MMBtu CTDB2_10 2.4E‐05 lb/MMscf CTDB2_13

Toluene 108‐88‐3 1.3E‐04 lb/MMBtu CTDB1_6 3.4E‐03 lb/MMscf CTDB1_10 1.3E‐04 lb/MMBtu CTDB2_6 ‐ ND CTDB2_11 3.4E‐03 lb/MMscf CTDB2_13

Xylenes 1330‐20‐7 6.4E‐05 lb/MMBtu CTDB1_6 ‐ ND CTDB1_10 6.4E‐05 lb/MMBtu CTDB2_6 ‐ ND CTDB2_11 ‐ ND CTDB2_13Formaldehyde (< 60% Load) 50‐00‐0 0.00279 lb/MMBtu CTDB1_7 ‐ Combined CTDB1_9 0.00279 lb/MMBtu CTDB2_7 ‐ NA ‐ ‐ Combined CTDB2_12

Formaldehyde (60 ‐ < 90% Load) 50‐00‐0 0.00151 lb/MMBtu CTDB1_7 ‐ Combined CTDB1_9 0.00151 lb/MMBtu CTDB2_7 ‐ NA ‐ ‐ Combined CTDB2_12Formaldehyde (>= 90% Load) 50‐00‐0 0.00105 lb/MMBtu CTDB1_7 ‐ Combined CTDB1_9 0.00105 lb/MMBtu CTDB2_7 ‐ NA ‐ ‐ Combined CTDB2_12

Formaldehyde (Any Load) 50‐00‐0 ‐ NA ‐ ‐ NA ‐ ‐ NA ‐ 2.28 lb/hr CTDB2_7 ‐ Combined CTDB2_12

Hexane (Any Load) 110‐54‐3 0.00034 lb/MMBtu CTDB1_8 ‐ Combined CTDB1_9 0.00034 lb/MMBtu CTDB2_8 0.042 lb/hr CTDB2_12 ‐ Combined CTDB2_12

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[EF Data]


EU

FS

TK

SV

Unit Description:

PMPM10

PM2.5

SO2

NOxVOCCOPbH2SO4

CO2eCO2

CH4

N2OSF6Individual HAPS: CAS #









Formaldehyde (< 60% Load) 50‐00‐0Formaldehyde (60 ‐ < 90% Load) 50‐00‐0

Formaldehyde (>= 90% Load) 50‐00‐0Formaldehyde (Any Load) 50‐00‐0Hexane (Any Load) 110‐54‐3

EU 005 EU 007 EU 010 EU 011FS 001

Auxiliary Boiler Units Source Fire pump Units Source

Diesel Fired Emergency Generator Units Source Bath Heater Units Source Cooling Tower Units Source

8.0E‐03 lb/MMBtu AB1 2.4E‐04 lb/hp‐hr FP1 6.07E‐05 lb/hp‐hr EG1 7.6 lb/ 106 scf BH2 ‐ Formula CL1



1.0E‐03 lb/MMBtu AB1 3.3E‐04 lb/hp‐hr FP1 2.05E‐03 lb/hp‐hr EG3 0.6 lb/ 106 scf BH2 ‐ NA

3.6E‐02 lb/MMBtu AB1 3.37 lb/hr FP2 5.31E‐03 lb/hp‐hr EG1 100 lb/ 106 scf BH1 ‐ NA

7.0E‐03 lb/MMBtu AB1 4.4E‐04 lb/hp‐hr FP1 2.88E‐04 lb/hp‐hr EG1 5.5 lb/ 106 scf BH2 ‐ NA

6.0E‐02 lb/MMBtu AB1 1.4E‐03 lb/hp‐hr FP1 5.31E‐03 lb/hp‐hr EG1 84 lb/ 106 scf BH1 ‐ NA

0.0005 lb/ 106 scf AB2 ‐ ND FP3 ‐ ND EG3 0.0005 lb/ 106 scf BH2 ‐ NA

‐ NA ‐ ‐ NA ‐ ‐ NA ‐ ‐ NA ‐ ‐ NA

‐ NA

116.98 lb/MMBtu GHG Table 163.05 lb/MMBtu GHG Table 163.05 lb/MMBtu GHG Table 116.98 lb/MMBtu GHG Table ‐ NA

2.2E‐03 lb/MMBtu GHG Table 6.6E‐03 lb/MMBtu GHG Table 6.6E‐03 lb/MMBtu GHG Table 2.2E‐03 lb/MMBtu GHG Table ‐ NA

2.2E‐04 lb/MMBtu GHG Table 1.3E‐03 lb/MMBtu GHG Table 1.3E‐03 lb/MMBtu GHG Table 2.2E‐04 lb/MMBtu GHG Table ‐ NA

‐ NA ‐ ‐ NA ‐ ‐ NA ‐ ‐ NA ‐ ‐ NA

‐ ND AB4 7.67E‐04 lb/MMBtu FP4 2.52E‐05 lb/MMBtu EG4 ‐ ND BH3 ‐ NA


2.0E‐04 lb/ 106 scf AB4 ‐ ND FP4 ‐ ND EG4 2.0E‐04 lb/ 106 scf BH3 ‐ NA

2.1E‐03 lb/ 106 scf AB4 9.33E‐04 lb/MMBtu FP4 7.76E‐04 lb/MMBtu EG4 2.1E‐03 lb/ 106 scf BH3 ‐ NA







‐ ND AB4 ‐ ND FP4 ‐ ND EG4 ‐ ND BH3 ‐ NA


1.8E+00 lb/ 106 scf AB4 ‐ ND FP4 ‐ ND EG4 1.8E+00 lb/ 106 scf BH3 ‐ NA







‐ ND AB4 ‐ ND FP4 ‐ ND EG4 ‐ ND BH3 ‐ NA




‐ NA ‐ ‐ NA ‐ ‐ NA ‐ ‐ NA ‐ ‐ NA

‐ NA ‐ ‐ NA ‐ ‐ NA ‐ ‐ NA ‐ ‐ NA

‐ NA ‐ ‐ NA ‐ ‐ NA ‐ ‐ NA ‐ ‐ NA

‐ NA ‐ ‐ NA ‐ ‐ NA ‐ ‐ NA ‐ ‐ NA

‐ NA ‐ ‐ NA ‐ ‐ NA ‐ ‐ NA ‐ ‐ NA



EU

FS

TK

SV

Unit Description:

PMPM10

PM2.5

SO2

NOxVOCCOPbH2SO4

CO2eCO2

CH4












FS 002 FS 003TK 001 TK ‐ TK ‐ TK ‐

Natural Gas Fugitives Units Source Breaker Fugitives Units Source

Fuel Oil Storage Tank Units Source

Fire Pump Fuel Tank Units Source

Emergency Generator Diesel Fuel

Tank Units Source

Natural Gas Condensate Tank ‐ Plant Units Source

‐ NA ‐ NA ‐ NA ‐ NA ‐ NA ‐ NA





‐ NA ‐ NA ‐ Formula TK1_1 ‐ Formula TK2_1 ‐ Formula TK3_1 ‐ Formula TK4_1





‐ Formula NGF1 ‐ NA ‐ NA ‐ NA ‐ NA ‐ NA

‐ Formula NGF1 ‐ NA ‐ NA ‐ NA ‐ NA ‐ NA


‐ NA ‐ Formula BSF_1 ‐ NA ‐ NA ‐ NA ‐ NA































EU

FS

TK

SV

Unit Description:

PMPM10

PM2.5

SO2

NOxVOCCOPbH2SO4

CO2eCO2

CH4












TK ‐ TK ‐

Natural Gas Condensate Tank ‐ CT1 Units Source

Natural Gas Condensate Tank ‐ CT2 Units Source

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ Formula TK5_1 ‐ Formula TK6_1

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA

‐ NA ‐ NA



Emission Factor SourcesCombustion Turbine #1 + Duct BurnersCTDB1_1

CTDB1_2

CTDB1_3

CTDB1_4

CTDB1_5

CTDB1_6

CTDB1_7

CTDB1_8

CTDB1_9

CTDB1_10

Combustion Turbine #2 + Duct BurnersCTDB2_1

CTDB2_2

CTDB2_3

CTDB2_4

CTDB2_5

CTDB2_6

CTDB2_7

CTDB2_8

CTDB2_9

CTDB2_10

CTDB2_11

CTDB2_12

CTDB2_13

Auxiliary BoilerAB1

AB2

AB4

AB5

AB3 PM2.5 emission rate assumed equal to total PM rate


These pollutants are accounted for at the stack level in the combined CT and DB data.

AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Tables 1.4‐3 and 1.4‐4, sum of all pollutants listed as POM (including Naphthalene)

Hexane emission factor based on most recent stack test at SV002 (Report No: 183284.CTG2.AB.COMP; September 2011); Maximum of 3 runs

These pollutants are accounted for at the stack level in the combined CT and DB data.

Based on Permit 01300098‐002 emission limit

See "Worst Case Emissions CT1 CT2" sheet for emission factor selection and/or calculation, based on fuel type.

AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Table 1.4‐2AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Tables 1.4‐3 and 1.4‐4


DB: AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Tables 1.4‐3 and 1.4‐4, sum of all pollutants listed as POM (including Naphthalene)


Potential PM, PM10, and PM2.5 emissions were based on vendor data, operating experience and stack tests from other similar Calpine facilities.

PM2.5 emission factor assumed equal to PM emisison factor

No data for lead available in AP‐42 Section 3.1 "Stationary Gas Turbines" (rev 04/00) Table 3.1‐4; used natural gas lead emission factor from AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Table 1.4‐2

Based on Permit 01300098‐002 emission limit

H2SO4 calculated as percentage of SO2 emission factor.

Based on Auxiliary Boiler emission limits in Permit 01300098‐002


Lead emission factor for Fuel oil from from AP‐42 Section 3.1 "Stationary Gas Turbines" (rev 04/00); Table 3.1‐5

DB ‐ Emission factors from AP‐42, Section 1.4 "Natural Gas Combustion" (Rev 7/98); Tables 1.4‐3 and 1.4‐4. Total POM emission factor is equal to the sum of the individual emissions of POM compounds (including Naphthalene).

No data for lead available in AP‐42 Section 3.1 "Stationary Gas Turbines" (rev 04/00) Table 3.1‐4; used natural gas lead emission factor from AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Table 1.4‐2

PM2.5 emission factor assumed equal to PM emisison factor

H2SO4 calculated as percentage of SO2 emission factor.AP‐42 Section 3.1 "Stationary Gas Turbines" (rev 04/00); Table 3.1‐3Formaldehyde emission factors based on most recent stack test (Report No: 183284.CTG2.AB.COMP; September 2011); Maximum of 3 runs



Emission Factor SourcesFire PumpFP1

FP2

FP3

FP4

FP5

Diesel Fired Emergency GeneratorEG1

EG2

EG3

EG4

EG5

EG6

Bath HeaterBH1

BH2

BH3

BH4

Cooling TowerCL1

Natural Gas Fugitive EmissionsNGF1

Breaker Fugitive EmissionsBSF1

Fuel Oil Storage TankTK1_1

Fire Pump Fuel TankTK2_1

Emergency Generator Diesel Fuel TankTK3_1

Natural Gas Condensate Tank ‐ PlantTK4_1

Natural Gas Condensate Tank ‐ CT1TK5_1

Natural Gas Condensate Tank ‐ CT2TK6_1

TANKS run, 10/23/2015

AP‐42 Section 3.4 " Large Stationary Diesel And All Stationary Dual‐fuel Engines" (Rev 10/96); Table 3.4‐4; Total PAH includes Naphthalene which is also separately counted

Based on Vendor Data, at 3633 braking hp, converted from g/hp‐hr to lb/hp‐hr

AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Table 1.4‐2AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Tables 1.4‐3 and 1.4‐4AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Tables 1.4‐3 and 1.4‐4, sum of all pollutants listed as POM (including Naphthalene)

TANKS run, 10/23/2015

TANKS run, 10/23/2015

See Breaker Fugitive Emissions sheet for individual component factors for SF6.

AP‐42 Section 1.4 "Natural Gas Combustion" (Rev 7/98); Table 1.4‐1; Small Boilers, Uncontrolled

See Natural Gas Fugitive Emissions sheet for individual component factors for CO2 and CH4.

TANKS run, 10/23/2015

AP‐42 Section 3.3 "Gasoline and Diesel Industrial Engines" (Rev 10/96); Table 3.3‐2. (No data for 1,3‐Butadiene in AP‐42 Section 3.4)

PM emission factor is from AP‐42 Section 13.4 (01/95). See Cooling Tower sheet for additional details.

TANKS run, 10/23/2015

TANKS run, 10/23/2015

Based on Vendor Data, at 350 braking hp (See Fire Pump data sheet)Based on Vendor Data, at 300 or 340 braking hp (See Fire Pump data sheet)

AP‐42 Section 3.3 "Gasoline and Diesel Industrial Engines" (Rev 10/96); Table 3.3‐2 AP‐42 Section 3.3 "Gasoline and Diesel Industrial Engines" (Rev 10/96); Table 3.3‐2; Total PAH includes Naphthalene which is also separately counted

No data for lead in AP‐42 Section 3.3 "Gasoline and Diesel Industrial Engines" (Rev 10/96); or in vendor data

AP‐42 Section 3.4 " Large Stationary Diesel And All Stationary Dual‐fuel Engines" (Rev 10/96); Table 3.4‐3

Based on Nonroad Compression‐Ignition Engines ‐‐ Exhaust Emission Standards (40 CFR 1039.101), for 2500 kW, converted from g/kW‐hr to lb/hp‐hr

No data for lead in AP‐42 Section 3.4 " Large Stationary Diesel And All Stationary Dual‐fuel Engines" (Rev 10/96); or in AP‐42 Section 3.3 "Gasoline and Diesel Industrial Engines" (Rev 10/96)



GHG Emission Factor Table

GHG Pollutant GWPNatural Gas (kg/MMBtu)

Fuel Oil ("Distillate #2" or

"Petroleum") (kg/MMBtu)

Natural Gas (lb/MMBtu)

Fuel Oil (lb/MMBtu)

CO2 1 53.06 73.96 116.98 163.05 ConversionsCH4 25 1.0E‐03 3.0E‐03 2.20E‐03 6.61E‐03 lb/kg 2.2046

N2O 298 1.0E‐04 6.0E‐04 2.20E‐04 1.32E‐03HFCsPFCsSF6 22,800

The GWP for SF6 was updated in the final rule published on November 29, 2013 [78 FR 71904] and effective on January 1, 2014.

Source: 40 CFR 98 ; GWP from Table A-1 [79 FR 73779, Dec. 11, 2014], Emission factors from Tables C-1 [78 FR 71950, Nov. 29, 2013] and C-2 [78 FR 71952, Nov. 29, 2013]


Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationFire Pump Data Sheet

Vendor Data

Emissions DataEmission Factor for Emission Rate for

Pollutant the Listed BHP the Listed BHP300 340 350 300 340 350 Worst‐case Worst‐case

(g/HP/hr) (g/HP/hr) (g/HP/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (g/hp‐hr)PM/PM10/PM2.5 0.07 0.09 0.11 0.046 0.067 0.085 0.085 0.110SO2 0.14 0.14 0.15 0.093 0.105 0.116 0.116 0.150NOx 5.1 4.5 4.2 3.373 3.373 3.241 3.373 5.100CO 0.22 0.45 0.62 0.146 0.337 0.478 0.478 0.620VOC/HC 0.07 0.15 0.20 0.046 0.112 0.154 0.154 0.200

(g/hp‐hr emissions directly from vendor data)Conversion

Worst case emission factors lb/hp‐hr lb/hr HP rating 0.0022046 lb/gPM/PM10/PM2.5 2.43E‐04 ‐ 350 HPSO2 3.31E‐04 ‐ 350 HPNOx ‐ 3.373 300 HPVOC/HC 4.41E‐04 ‐ 350 HPCO 1.37E‐03 ‐ 350 HP

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Fire Pump Data]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationDiesel Fired Emergency Generator Data Sheet

Vendor Data

Emissions DataEmission Factor for Emission Rate for 0.0022046 lb/g

Pollutant the Listed BHP the Listed BHP3633 2760 1889 1029 497 3633 2760 1889 1029 497 Worst‐case Engine rating 2500 kW

(g/HP/hr) (g/HP/hr) (g/HP/hr) (g/HP/hr) (g/HP/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) 3633 BHPPM/PM10/PM2.5 0.05 0.05 0.07 0.14 0.29 0.41 0.27 0.29 0.31 0.31 0.41 0.688 kW/BHPNOx 6.38 5.15 3.74 3.50 6.47 50.59 31.09 15.44 7.87 7.02 50.59CO 0.76 0.48 0.58 1.47 4.26 6.01 2.88 2.41 3.30 4.62 6.01VOC/HC 0.14 0.18 0.29 0.40 0.89 1.10 1.10 1.20 0.90 0.96 1.20

Non‐road CI Engine emission standards (40 CFR 1039.101)

Rated Power (kW) TierModel Year NMHC

(g/kW‐hr)

NMHC + NOx (g/kW‐

hr)NOx (g/kW‐

hr)PM

(g/kW‐hr)CO

(g/kW‐hr)NMHC

(lb/kW‐hr)

NMHC + NOx (lb/kW‐

hr)NOx

(lb/kW‐hr)PM

(lb/kW‐hr)CO

(lb/kW‐hr)NMHC

(lb/hp‐hr)

NMHC + NOx

(lb/hp‐hr)NOx

(lb/hp‐hr)PM

(lb/hp‐hr)CO

(lb/hp‐hr)

12000‐2005

1.3 ‐ 9.2 0.54 11.4 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

22006‐2010

‐ 6.4 ‐ 0.2 3.5 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

2011‐2014

0.4 ‐ 3.5 0.1 3.5 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

2015+ 0.19 ‐ 3.5 0.04 3.5 4.19E‐04 ‐ 7.72E‐03 8.82E‐05 7.72E‐03 2.88E‐04 ‐ 5.31E‐03 6.07E‐05 5.31E‐03Excerpt of table from "http://www.epa.gov/otaq/standards/nonroad/nonroadci.htm", May 11, 2015The NOx standard for generator sets is 0.67 g/kW‐hr.The PM standard for generator sets is 0.03 g/kW‐hr.

Minimum emissions rate

Vendor Data

Non‐road CI Engine emission standards

Selected Rate Reason

lb/hp‐hr lb/hp‐hr lb/hp‐hrPM/PM10/PM2.5 1.10E‐04 6.07E‐05 6.07E‐05 Meets Non‐road CI Engine emission standardsNOx 1.41E‐02 5.31E‐03 5.31E‐03 Meets Non‐road CI Engine emission standardsCO 1.68E‐03 5.31E‐03 5.31E‐03 Meets Non‐road CI Engine emission standards, conservatively using highest emission factorVOC/HC 3.09E‐04 2.88E‐04 2.88E‐04 Meets Non‐road CI Engine emission standards

kW > 900

4

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Emerg Gen Data]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationSV007 ‐ CT1 Emissions by Operating Scenario ‐ Natural Gas

Mankato Energy Center Emission Representations for Air Permit Application Emission representations are on a per‐unit basis

CASE 1 2 3 4 5 6 7 8 9Siemens‐ Natural Gas

BASE (No DB) Siemens Generic Performance

60% Load Siemens Generic

Performance

BASE (DB) Siemens Generic

Performance


Performance


Performance


BASE (Evap cooler + DB) Siemens Generic

Performance

BASE (Evap cooler & No DB) Siemens

Generic Performance

BASE (Evap cooler off & No DB) Siemens

Generic Performance

60% Load Siemens Generic peformance

60% Load Mitsubishi peformance

Gas Turbine Ambient Temperature Dry Bulb (deg F) 6.0 6.0 6.0 44.0 44.0 44.0 95.0 95.0 95.0 95.0 95.0Exhaust Composition

Argon percent 0.90 0.90 0.90 0.89 0.89 0.89 0.88 0.88 0.87 0.88 0.90Nitrogen percent 75.10 75.27 75.10 74.09 74.49 74.09 73.45 73.45 73.31 73.52 73.10Oxygen percent 12.59 13.08 12.59 12.49 13.06 12.49 12.41 12.41 12.42 12.99 12.90

Carbon Dioxide percent 3.81 3.57 3.81 3.75 3.51 3.75 3.70 3.70 3.64 3.64 3.40 Water percent 7.62 7.17 7.62 8.79 8.04 8.79 9.57 9.57 9.60 9.76 9.70

CT Exhaust Flow lb/hr 4,237,304 3,020,461 4,237,304 4,017,524 2,875,811 4,017,524 3640882 3640882 3,517,247 2,640,395 2,499,000CT Power Output MW 211.6 126.9 211.6 194.6 115.9 194.6 172.3 172.3 167.2 96.6 93.3

Heating Value BTU/lb HHV 23,072 23,072 23,072 23072 23072 23072 23072 23072 23072 23072 23072Heat Input mmBtu/hr (LHV) 1,048Heat Input mmBtu/hr (HHV) 2,253 1,509 2,253 2,087 1,412 2,087 1,902 1,902 1,817 1,305 1,218 Max 2253.3 mmBtu/hr (HHV)

Emissions Data NOx ppmvd 35.2 33.1 35.2 35.6 33.2 35.6 36.0 36.0 35.9 33.5 33.9

ppmvd @15% 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0lb/hr 207.8 139.2 207.8 192.4 130.2 192.4 175.4 175.4 167.6 120.3 112.3

CO ppmvd 14.1 66.3 14.1 14.3 66.4 14.3 14.4 14.4 14.4 67.0 13.6ppmvd @15% 10.0 50.0 10.0 10.0 50.0 10.0 10.0 10.0 10.0 50.0 10.0lb/hr 50.6 169.5 50.6 46.9 158.6 46.9 42.7 42.7 40.8 146.5 27.3

VOC ppmvd @15% 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0lb/hr 8.7 5.8 8.7 8.0 5.4 8.0 7.3 7.3 7.0 5.0 4.7



Performance


Performance


Performance


Performance



Performance


Generic Performance


Generic Performance



Duct Burner Ambient Temperature (deg F) 6 6 6 44 44 44 95 95 95 95 95Exhaust Composition

Heat Input mmBtu/hr (LHV) 0 0 741.3 720 0 0 720 0 0 0 0Heat Input mmBtu/hr (HHV) 0 0 823.7 800.0 0 0 800.0 0 0 0 0 Max 823.7 mmBtu/hr (HHV)

Emissions Data NOx lb/mmBtu 0.080 0.080 0.080 0.080 0.080 0.080 0.080 0.080 0.080 0.080 0.080

lb/hr 0.0 0.0 65.9 64.0 0.0 0.0 64.0 0.0 0.0 0.0 0.0CO lb/mmBtu 0.100 0.100 0.100 0.100 0.100 0.100 0.100 0.100 0.100 0.100 0.100

lb/hr 0.0 0.0 82.4 80.0 0.0 0.0 80.0 0.0 0.0 0.0 0.0VOC lb/mmBtu 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020

lb/hr 0.0 0.0 16.5 16.0 0.0 0.0 16.0 0.0 0.0 0.0 0.0

10

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[CT1 Case Emissions NG]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationSV007 ‐ CT1 Emissions by Operating Scenario ‐ Natural Gas



Performance


Performance


Performance


Performance



Performance


Generic Performance


Generic Performance



Combined GT and DB Ambient Temperature (deg F) 6 6 6 44 44 44 95 95 95 95 95Exhaust Composition CT Hourly Heat Input mmBtu/hr (HHV) 2,253 1,509 2,253 2,087 1,412 2,087 1,902 1,902 1,817 1,305 1,218 Max 2253.3 mmBtu/hr (HHV)DB Hourly Heat Input mmBtu/hr (HHV) 0 0 824 800 0 0 800 0 0 0 0 Max 823.7 mmBtu/hr (HHV)

Total Hourly Heat Input mmBtu/hr (HHV) 2,253 1,509 3,077 2,887 1,412 2,087 2,702 1,902 1,817 1,305 1,218 Max 3077.0 mmBtu/hr (HHV)CT Annual Heat Input mmBtu/hr (HHV) 19,738,908 13,223,045 19,738,908 18,279,277 12,372,506 18,279,277 16,657,578 16,657,578 15,917,139 11,431,800 10,669,680

Emissions Data NOx ppmvd @15% O2 25.0 25.0 24.1 24.1 25.0 25.0 24.0 25.0 25.0 25.0 25.0 NOx

lb/mmBtu 0.0922 0.0922 0.0889 0.0888 0.0922 0.0922 0.0886 0.0922 0.0922 0.0922 0.0922lb/hr 207.8 139.2 273.7 256.4 130.2 192.4 239.4 175.4 167.6 120.3 112.3 Max 273.7 lb/hr SCR Control Eff (%) 88.0% 88.0% 87.6% 87.5% 88.0% 88.0% 87.5% 88.0% 88.0% 88.0% 88.0%ppmvd @15% O2 (controlled) 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 Max 3.0 ppmvd @15% O2 (controlled)lb/mmBtu (controlled) 0.0111 0.0111 0.0111 0.0111 0.0111 0.0111 0.0111 0.0111 0.0111 0.0111 0.0111lb/hr (controlled) 24.9 16.7 34.1 31.9 15.6 23.1 29.9 21.0 20.1 14.4 13.5 Max 34.1 lb/hr (controlled)

CO ppmvd @15% O2 10.0 50.0 19.2 19.6 50.0 10.0 20.2 10.0 10.0 50.0 10.0 CO lb/mmBtu 0.022 0.112 0.043 0.044 0.112 0.022 0.045 0.022 0.022 0.112 0.022lb/hr 50.6 169.5 133.0 126.9 158.6 46.9 122.7 42.7 40.8 146.5 27.3 Max 169.5 lb/hr CO Catalyst Control Eff (%) 60.0% 90.6% 79.2% 79.6% 90.6% 60.0% 80.2% 60.0% 60.0% 90.6% 53.0% Max 4.0 ppmvd @15% O2 (controlled) 90% load+ppmvd @15% O2 (controlled) 4.0 4.7 4.0 4.0 4.7 4.0 4.0 4.0 4.0 4.7 4.7 Max 4.7 ppmvd @15% O2 (controlled) 60 to 90% loadlb/mmBtu (controlled) 0.009 0.011 0.009 0.009 0.011 0.009 0.009 0.009 0.009 0.011 0.011lb/hr (controlled) 20.2 15.9 27.6 25.9 14.9 18.7 24.3 17.1 16.3 13.8 12.9 Max 27.6 lb/hr (controlled)

VOC ppmvd @15% O2 3.0 3.0 6.4 6.5 3.0 3.0 6.7 3.0 3.0 3.0 3.0 VOC lb/mmBtu 0.0038 0.0038 0.0082 0.0083 0.0038 0.0038 0.0086 0.0038 0.0038 0.0038 0.0038lb/hr 8.7 5.8 25.1 24.0 5.4 8.0 23.3 7.3 7.0 5.0 4.7 Max 25.1 lb/hrVOC Catalyst Control Eff (%) 0.0% 0.0% 46.6% 47.6% 0.0% 0.0% 49.5% 0.0% 0.0% 0.0% 0.0%ppmvd @15% O2 (controlled) 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 Max 3.4 ppmvd @15% O2 (controlled)lb/mmBtu (controlled) 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004lb/hr (controlled) 8.7 5.8 13.4 12.6 5.4 8.0 11.8 7.3 7.0 5.0 4.7 Max 13.4 lb/hr (controlled)lb/hr (controlled at 3.4 ppm) 9.8 6.6 13.4 12.6 6.2 9.1 11.8 8.3 7.9 5.7 5.3 Max 13.4 lb/hr (controlled at 3.4 ppm)

Stack Parameters Stack Parameters Height (ft) 200 200 200 200 200 200 200 200 200 200 200Diameter (ft) 19.0 19.0 19.0 19.0 19.0 19.0 19.0 19.0 19.0 19.0 19.0Stack Gas Mol, Wt. (lb/lbmol) 28.5 28.5 28.5 28.3 28.4 28.3 28.2 28.2 28.2 28.5 28.2Temp (deg F) 175 160 175 175 160 175 175 175 175 160 160 Min 160 Temp (deg F)Stack Mass Flow (lb/hr) 4,237,304 3,020,461 4,273,005 4,052,198 2,875,811 4,017,524 3,675,556 3,640,882 3,517,247 2,640,395 2,499,000Velocity (ft/sec) 67.6 47.0 68.2 65.0 44.9 64.4 59.1 58.6 56.7 41.2 39.3 Min 39.3075 Velocity (ft/sec)

Notes: 1) The majority of emissions data is based on Siemens generic data with 5% margin added to heat input2) Worst case VOC emissions are based on Mitsubishi emissions data3) Siemens F4 has highest heat input at 95F4) Mitsubishi has lowest stack velocity at 95F and 60% load

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[CT1 Case Emissions NG]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationSV002 ‐ CT2 Siemens Emissions by Operating Scenario ‐ Natural Gas


CASE 1 2 3 4 5 6 7 8 9Siemens‐ Natural Gas Simple Cycle ? No No

BASE (No DB) 60% BASE PWR AUG BASE 60% BASE (No DB) PWR AUG BASE BASE (No DB) 60%Gas Turbine Ambient Temperature Dry Bulb (deg F) 6.4 6.0 6.4 47.9 44.0 44.0 44.0 95.0 95.0 95.0 95.0

Exhaust Composition Argon percent 0.90 0.90 0.90 0.85 0.89 0.89 0.89 0.83 0.88 0.88 0.89

Nitrogen percent 75.10 75.26 75.10 70.91 74.09 74.49 74.09 69.73 73.45 73.45 74.20Oxygen percent 12.65 13.10 12.65 11.57 12.49 13.06 12.49 11.32 12.41 12.41 13.23

Carbon Dioxide percent 3.81 3.60 3.81 3.78 3.75 3.51 3.75 3.75 3.70 3.70 3.39 Water percent 7.55 7.14 7.55 12.90 8.79 8.04 8.79 14.37 9.57 9.57 8.30

CT Exhaust Flow lb/hr 4,114,775 2,935,433 4,114,775 3,980,103 3,822,998 2,778,491 3,822,998 3,711,423 3,591,151 3,591,151 2,573,859CT Power Output MW 206.1 123.2 206.1 206.1 186.0 110.6 186.0 187.8 169.8 169.8 93.3

CT + ST Power Output MW 309.165 184.74 309.165 309.165 279.038 165.896 279.038 281.64 254.73 254.73 139.905Heat Input mmBtu/hr (LHV) 1,876 1,264 1,876 1,841 1726 1173 1726 1,712 1,603 1,603 1,049Heat Input mmBtu/hr (HHV) 2,082 1,403 2,082 2,044 1,916 1,303 1,916 1,900 1,779 1,779 1,164

Emissions Data NOx ppmvd 35.0 33.0 35.0 39.6 35.6 33.2 35.6 40.6 36.0 36.0 32.5

ppmvd @15% 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0lb/hr 192.0 129.3 192.0 188.5 176.7 120.1 176.7 175.2 164.1 164.1 107.4 192.0 Maximum Emissions (lbs/hr)

CO ppmvd 10.0 50.0 10.0 25.0 10.0 50.0 10.0 25.0 10.0 10.0 50.0ppmvd @15% 7.1 37.8 7.1 15.8 7.0 37.6 7.0 15.4 7.0 7.0 38.4lb/hr 33.4 119.1 33.4 72.5 30.2 110.1 30.2 65.6 27.8 27.8 100.5 119.1 Maximum Emissions (lbs/hr)

VOC ppmvd @15% 1.2 3.0 1.2 1.2 1.2 3.0 1.2 1.2 1.2 1.2 3.0lb/hr 3.2 5.4 3.2 3.1 2.9 5.0 2.9 2.9 2.7 2.7 4.5 5.4 Maximum Emissions (lbs/hr)

PM lb/hr 10 10 10 10 10 10 10 10 10 10 10 10.0 Maximum Emissions (lbs/hr)lb/mmBtu (HHV) 0.0048 0.0071 0.0048 0.0049 0.0052 0.0077 0.0052 0.0053 0.0056 0.0056 0.0086

Simple Cycle ? No NoBASE (No DB) 60% BASE PWR AUG BASE 60% BASE (No DB) PWR AUG BASE BASE (No DB) 60%

Duct Burner Ambient Temperature (deg F) 6 6 6 48 44 44 44 95 95 95 95Exhaust Composition

Heat Input mmBtu/hr (LHV) 0 0 720 720 720 0 0 720 720 0 0Heat Input mmBtu/hr (HHV) 0 0 800 800 800 0 0 800 800 0

Emissions Data NOx lb/mmBtu 0.080 0.080 0.080 0.080 0.080 0.080 0.080 0.080 0.080 0.080 0.080

lb/hr 0.0 0.0 64.0 64.0 64.0 0.0 0.0 64.0 64.0 0.0 0.0 64.0 Maximum Emissions (lbs/hr)CO lb/mmBtu 0.100 0.100 0.100 0.250 0.100 0.100 0.100 0.250 0.100 0.100 0.100

lb/hr 0.0 0.0 80.0 200.0 80.0 0.0 0.0 200.0 80.0 0.0 0.0 80.0 Maximum Emissions (lbs/hr)VOC lb/mmBtu 0.020 0.020 0.020 0.050 0.020 0.020 0.020 0.050 0.020 0.020 0.020

lb/hr 0.0 0.0 16.0 40.0 16.0 0.0 0.0 40.0 16.0 0.0 0.0 16.0 Maximum Emissions (lbs/hr)PM lb/mmBtu 0.015 0.015 0.015 0.015 0.015 0.015 0.015 0.015 0.015 0.015 0.015

lb/hr 0.0 0.0 12.0 12.0 12.0 0.0 0.0 12.0 12.0 0.0 0.0 12.0 Maximum Emissions (lbs/hr)

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[CT2 Siemens Emission Calcs NG]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationSV002 ‐ CT2 Siemens Emissions by Operating Scenario ‐ Natural Gas

Simple Cycle ? No NoBASE (No DB) 60% BASE PWR AUG BASE 60% BASE (No DB) PWR AUG BASE BASE (No DB) 60%

Combined GT and DB Ambient Temperature (deg F) 6.4206 6 6.4206 47.8674 44 44 44 95 95 95 95Exhaust Composition CT Hourly Heat Input mmBtu/hr (HHV) 2,082 1,403 2,082 2,044 1,916 1,303 1,916 1,900 1,779 1,779 1,164DB Hourly Heat Input mmBtu/hr (HHV) 0 0 800 800 800 0 0 800 800 0 0

Total Hourly Heat Input mmBtu/hr (HHV) 2,082 1,403 2,882 2,844 2,716 1,303 1,916 2,700 2,579 1,779 1,164 2881.8 Maximum Heat Input (mmBtu/hr)CT Annual Heat Input mmBtu/hr (HHV) 18,236,826 12,286,939 18,236,826 17,902,705 16,782,928 11,410,566 16,782,928 16,643,337 15,588,206 15,588,206 10,199,213

Emissions Data NOx ppmvd @15% O2 25.0 25.0 24.1 24.1 24.0 25.0 25.0 24.0 24.0 25.0 25.0

lb/mmBtu 0.0922 0.0922 0.0888 0.0888 0.0886 0.0922 0.0922 0.0886 0.0884 0.0922 0.0922lb/hr 192.0 129.3 256.0 252.5 240.7 120.1 176.7 239.2 228.1 164.1 107.4 256.0 Maximum Emissions (lbs/hr)SCR Control Eff (%) 86.0% 86.0% 85.5% 85.5% 85.4% 86.0% 86.0% 85.4% 85.4% 86.0% 86.0%ppmvd @15% O2 (controlled) 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5lb/mmBtu (controlled) 0.0129 0.0129 0.0129 0.0129 0.0129 0.0129 0.0129 0.0129 0.0129 0.0129 0.0129lb/hr (controlled) 26.9 18.1 37.2 36.7 35.1 16.8 24.7 34.9 33.3 23.0 15.0 37.2 Maximum Emissions (lbs/hr)lb/MWh (controlled) 0.09 0.10 0.12 0.12 0.13 0.10 0.09 0.12 0.13 0.09 0.11

CO ppmvd @15% O2 7.1 37.8 17.5 42.7 18.1 37.6 7.0 43.8 18.6 7.0 38.4lb/mmBtu 0.016 0.085 0.039 0.096 0.041 0.084 0.016 0.098 0.042 0.016 0.086lb/hr 33.4 119.1 113.4 272.5 110.2 110.1 30.2 265.6 107.8 27.8 100.5 119.1 Maximum Emissions (lbs/hr)CO Catalyst Control Eff (%) 90.0% 90.0% 90.0% 89.0% 89.0% 90.0% 90.0% 90.0% 89.0% 90.0% 90.0%ppmvd @15% O2 (controlled) 0.7 3.8 1.8 4.7 2.0 3.8 0.7 4.4 2.0 0.7 3.8lb/mmBtu (controlled) 0.002 0.008 0.004 0.011 0.004 0.008 0.002 0.010 0.005 0.002 0.009lb/hr (controlled) 3.3 11.9 11.3 30.0 12.1 11.0 3.0 26.6 11.9 2.8 10.0 12.1 Maximum Emissions (lbs/hr)

VOC ppmvd @15% O2 1.2 3.0 5.2 11.8 5.4 3.0 1.2 12.4 5.7 1.2 3.0lb/mmBtu 0.0015 0.0038 0.0067 0.0152 0.0070 0.0038 0.0015 0.0159 0.0073 0.0015 0.0038lb/hr 3.2 5.4 19.2 43.1 18.9 5.0 2.9 42.9 18.7 2.7 4.5 19.2 Maximum Emissions (lbs/hr)VOC Catalyst Control Eff (%) 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0%ppmvd @15% O2 (controlled) 0.72 1.80 3.12 7.10 3.26 1.80 0.72 7.43 3.40 0.72 1.80lb/mmBtu (controlled) 0.001 0.002 0.004 0.009 0.004 0.002 0.001 0.010 0.004 0.001 0.002lb/hr (controlled) 1.9 3.2 11.5 25.9 11.4 3.0 1.8 25.8 11.2 1.6 2.7 11.5 Maximum Emissions (lbs/hr)

PM lb/hr 10.0 10.0 22.0 22.0 22.0 10.0 10.0 22.0 22.0 10.0 10.0 22.0 Maximum Emissions (lbs/hr)lb/mmBtu 0.005 0.007 0.008 0.008 0.008 0.008 0.005 0.008 0.009 0.006 0.009

Stack Parameters Height (ft) 150 150 150 150 150 150 150 150 150 150 150Diameter (ft) 19.0 19.0 19.0 19.0 19.0 19.0 19.0 19.0 19.0 19.0 19.0Stack Gas Mol, Wt. (lb/lbmol) 28.48 28.50 28.31 27.73 28.16 28.40 28.34 27.56 28.06 28.25 28.36Temp (deg F) 175 160 175 175 175 160 175 185 185 185 160 160.0 Lowest Stack Temp (deg F)Stack Mass Flow (lb/hr) 4,114,775 2,935,433 4,148,278 4,013,605 3,856,500 2,778,491 3,822,998 3,744,926 3,624,653 3,591,151 2,573,859Velocity (ft/sec) 65.6 45.7 66.6 65.8 62.2 43.4 61.3 62.7 59.6 58.7 40.3 40.3 Lowest Velocity (ft/sec)

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[CT2 Siemens Emission Calcs NG]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationSV002 ‐ CT2 Siemens Emissions by Operating Scenario ‐ Fuel Oil


CASE 1 2 3 4 5 6 7 8 9Siemens‐ Fuel Oil Simple Cycle ? No

BASE (No DB) BASE 60% BASE BASE (No DB) 60% BASE BASE (No DB) 60%Gas Turbine Ambient Temperature Dry Bulb (deg F) 44.0 44.0 44.0 ‐9.6 ‐9.6 ‐9.6 95.0 95.0 95.0

Exhaust Composition Argon percent 0.88 0.88 0.90 0.90 0.90 0.92 0.88 0.88 0.90

Nitrogen percent 73.98 73.98 75.40 75.01 75.01 76.57 73.35 73.35 75.03Oxygen percent 12.63 12.63 14.87 12.72 12.72 15.13 12.56 12.56 14.84

Carbon Dioxide percent 4.94 4.94 3.68 5.07 5.07 3.72 4.87 4.87 3.63 Water percent 7.56 7.56 5.15 6.30 6.30 3.67 8.34 8.34 5.60

CT Exhaust Flow lb/hr 3,868,176 3,868,176 3,409,311 4,262,125 4,262,125 3,751,334 3,633,403 3,633,403 3,094,336CT Power Output MW 178.8 178.8 106.3 206.1 206.1 123.6 163.0 163.0 89.3

CT + ST Power Output MW 268.24 268.24 159.41 309.165 309.165 185.428 244.44 244.44 133.95Heat Input mmBtu/hr (LHV) 1,712 1,712 1116 1924 1924 1233 1,589 1,589 1,001Heat Input mmBtu/hr (HHV) 1,827 1,827 1,190 2,051.8 2,052 1,315 1,695 1,695 1,068 2051.8 Maximum Heat Input (mmBtu/hr)

Emissions Data NOx ppmvd 58.9 58.9 51.1 58.2 58.2 48.9 59.3 59.3 51.4

ppmvd @15% 42.0 42.0 50.0 42.0 42.0 50.0 42.0 42.0 50.0lb/hr 283.0 283.0 219.5 317.9 317.9 242.6 262.6 262.6 196.9 317.9 Maximum Emissions (lbs/hr)

CO ppmvd 10.0 10.0 100.0 10.0 10.0 100.0 10.0 10.0 100.0ppmvd @15% 7.1 7.1 97.8 7.2 7.2 102.2 7.1 7.1 97.4lb/hr 29.3 29.3 261.5 33.2 33.2 301.9 26.9 26.9 233.4 261.5 Maximum Emissions (lbs/hr)

VOC ppmvd @15% 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0lb/hr 23.4 23.4 15.3 26.3 26.3 16.9 21.7 21.7 13.7 26.3 Maximum Emissions (lbs/hr)

PM lb/hr 54.8 54.8 82.2 60.8 60.8 91.2 51.1 51.1 74.3 82.2 Maximum Emissions (lbs/hr)lb/mmBtu (HHV) 0.0300 0.0300 0.0690 0.0296 0.0296 0.0693 0.0302 0.0302 0.0696

SO2 ppmvd 12.8 12.8 9.3 12.6 12.6 8.9 12.9 12.9 9.3ppmvd @15% 9.10 9.10 9.10 9.10 9.10 9.10 9.10 9.10 9.10lb/mmBtu 0.047 0.047 0.047 0.047 0.047 0.047 0.047 0.047 0.047lb/hr 85.29 85.29 55.58 95.81 95.81 61.42 79.15 79.15 49.86 95.8 Maximum Emissions (lbs/hr)

BASE (No DB) BASE 60% BASE BASE (No DB) 60% BASE BASE (No DB) 60%Duct Burner Ambient Temperature (deg F) 44 44 44 ‐10 ‐10 ‐10 95 95 95

Exhaust Composition Heat Input mmBtu/hr (LHV) 0 720 0 720 0 0 720 0 0Heat Input mmBtu/hr (HHV) 0 800 0 800 0 0 800 0 0

Emissions Data NOx lb/mmBtu 0.080 0.080 0.080 0.080 0.080 0.080 0.080 0.080 0.080

lb/hr 0.0 64.0 0.0 64.0 0.0 0.0 64.0 0.0 0.0 64.0 Maximum Emissions (lbs/hr)CO lb/mmBtu 0.100 0.100 0.100 0.100 0.100 0.100 0.100 0.100 0.100

lb/hr 0.0 80.0 0.0 80.0 0.0 0.0 80.0 0.0 0.0 80.0 Maximum Emissions (lbs/hr)VOC lb/mmBtu 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020 0.020

lb/hr 0.0 16.0 0.0 16.0 0.0 0.0 16.0 0.0 0.0 16.0 Maximum Emissions (lbs/hr)PM lb/mmBtu 0.015 0.015 0.015 0.015 0.015 0.015 0.015 0.015 0.015

lb/hr 0.0 12.0 0.0 12.0 0.0 0.0 12.0 0.0 0.0 12.0 Maximum Emissions (lbs/hr)SO2 lb/mmBtu 0.0012 0.0012 0.0012 0.0012 0.0012 0.0012 0.0012 0.0012 0.0012

lb/hr 0.00 0.96 0.00 0.96 0.00 0.00 0.96 0.00 0.00 1.0 Maximum Emissions (lbs/hr)

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[CT2 Siemen Emission Calcs FO]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationSV002 ‐ CT2 Siemens Emissions by Operating Scenario ‐ Fuel Oil

BASE (No DB) BASE 60% BASE BASE (No DB) 60% BASE BASE (No DB) 60%Combined GT and DB Ambient Temperature (deg F) 44 44 44 ‐9.6154 ‐9.6154 ‐9.6154 95 95 95

Exhaust Composition CT Hourly Heat Input mmBtu/hr (HHV) 1,827 1,827 1,190 2,052 2,052 1,315 1,695 1,695 1,068DB Hourly Heat Input mmBtu/hr (HHV) 0 800 0 800 0 0 800 0 0

Total Hourly Heat Input mmBtu/hr (HHV) 1,827 2,627 1,190 2,852 2,052 1,315 2,495 1,695 1,068 2851.8 Maximum Heat Input (mmBtu/hr)CT Annual Heat Input mmBtu/hr (HHV) 16,000,759 16,000,759 10,427,370 17,973,900 17,973,900 11,523,154 14,848,907 14,848,907 9,353,545

Emissions Data NOx ppmvd @15% O2 42.0 35.8 50.0 36.3 42.0 50.0 35.5 42.0 50.0

lb/mmBtu 0.1549 0.1321 0.1844 0.1339 0.1549 0.1844 0.1309 0.1549 0.1844lb/hr 283.0 347.0 219.5 381.9 317.9 242.6 326.6 262.6 196.9 381.9 Maximum Emissions (lbs/hr)SCR Control Eff (%) 85.7% 83.2% 88.0% 83.5% 85.7% 88.0% 83.1% 85.7% 88.0%ppmvd @15% O2 (controlled) 6.0 6.0 6.0 6.0 6.0 6.0 6.0 6.0 6.0lb/mmBtu (controlled) 0.0221 0.0221 0.0221 0.0221 0.0221 0.0221 0.0221 0.0221 0.0221lb/hr (controlled) 40.4 58.1 26.3 63.1 45.4 29.1 55.2 37.5 23.6 63.1 Maximum Emissions (lbs/hr)lb/MWh (controlled) 0.15 0.22 0.17 0.20 0.15 0.16 0.23 0.15 0.18

CO ppmvd @15% O2 7.1 18.5 97.8 17.7 7.2 102.2 19.1 7.1 97.4lb/mmBtu 0.016 0.042 0.220 0.040 0.016 0.230 0.043 0.016 0.219lb/hr 29.3 109.3 261.5 113.2 33.2 301.9 106.9 26.9 233.4 261.5 Maximum Emissions (lbs/hr)CO Catalyst Control Eff (%) 90.0% 90.0% 90.0% 90.0% 90.0% 90.0% 90.0% 90.0% 90.0%ppmvd @15% O2 (controlled) 0.7 1.9 9.8 1.8 0.7 10.2 1.9 0.7 9.7lb/mmBtu (controlled) 0.002 0.004 0.022 0.004 0.002 0.023 0.004 0.002 0.022lb/hr (controlled) 2.9 10.9 26.1 11.3 3.3 30.2 10.7 2.7 23.3 26.1 Maximum Emissions (lbs/hr)

VOC ppmvd @15% O2 10.0 11.7 10.0 11.6 10.0 10.0 11.8 10.0 10.0lb/mmBtu 0.0128 0.0150 0.0128 0.0148 0.0128 0.0128 0.0151 0.0128 0.0128lb/hr 23.4 39.4 15.3 42.3 26.3 16.9 37.7 21.7 13.7 42.3 Maximum Emissions (lbs/hr)VOC Catalyst Control Eff (%) 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0%ppmvd @15% O2 (controlled) 6.0 7.0 6.0 6.9 6.0 6.0 7.1 6.0 6.0lb/mmBtu (controlled) 0.008 0.009 0.008 0.009 0.008 0.008 0.009 0.008 0.008lb/hr (controlled) 14.1 23.7 9.2 25.4 15.8 10.1 22.6 13.0 8.2 25.4 Maximum Emissions (lbs/hr)

PM lb/hr 72.6 72.6 72.6 72.6 72.6 72.6 72.6 72.6 72.6 72.6 Maximum Emissions (lbs/hr)lb/mmBtu 0.040 0.028 0.061 0.025 0.035 0.055 0.029 0.043 0.068

SO2 ppmvd @15% O2 9.10 6.40 9.10 6.61 9.10 9.10 6.26 9.10 9.10lb/mmBtu 0.0467 0.0328 0.0467 0.0339 0.0467 0.0467 0.0321 0.0467 0.0467lb/hr 85.29 86.25 55.58 96.77 95.81 61.42 80.11 79.15 49.86 96.8 Maximum Emissions (lbs/hr)

Stack Parameters Height (ft) 150 150 150 150 150 150 150 150 150Diameter (ft) 19.0 19.0 19.0 19.0 19.0 19.0 19.0 19.0 19.0Stack Gas Mol, Wt. (lb/lbmol) 28.66 28.47 28.78 28.64 28.81 28.95 28.37 28.56 28.73Temp (deg F) 175 175 160 165 165 165 180 180 160 180.0 Lowest Stack Temp (deg F)Stack Mass Flow (lb/hr) 3,868,176 3,901,679 3,409,311 4,295,627 4,262,125 3,751,334 3,666,905 3,633,403 3,094,336Velocity (ft/sec) 61.3 62.2 52.5 67.1 66.2 57.9 59.2 58.2 47.8 67.1 Lowest Velocity (ft/sec)

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[CT2 Siemen Emission Calcs FO]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationWorst‐Case Emissions for Combustion Turbine #1 and Combustion Turbine #2

Operating Hours 8760

Combustion Turbine #1, Uncontrolled Combustion Turbine #2, Uncontrolled

Pollutant lb/hr ton/yr lb/hr ton/yr Pollutant lb/hr ton/yr lb/hr ton/yr lb/hr ton/yrPM 11.9 52.1 11.9 52.1 PM 22.0 96.4 72.6 318.0 72.6 318.0

PM10 11.9 52.1 11.9 52.1 PM10 22.0 96.4 72.6 318.0 72.6 318.0

PM2.5 11.9 52.1 11.9 52.1 PM2.5 22.0 96.4 72.6 318.0 72.6 318.0

SOx 6.9 30.2 6.9 30.2 SOx 6.5 28.3 96.8 423.9 96.8 423.9

NOx 273.7 1198.8 273.7 1198.8 NOx 256.0 1121.2 381.9 1672.6 381.9 1672.6

VOC 25.1 110.1 25.1 110.1 VOC 19.2 84.1 42.3 185.4 42.3 185.4

CO 169.5 742.2 169.5 742.2 CO 119.1 521.7 261.5 1145.2 261.5 1145.2

Note: SV007 potential PM, PM10, and PM2.5 emissions were based on vendor data, operating experience and stack tests from other similar Calpine facilities.SO2 lb/hr emissions rate based on lb/MMBtu limit

Combustion Turbine #1, Controlled Combustion Turbine #2, Controlled

Pollutant lb/hr ton/yr lb/hr ton/yr Pollutant lb/hr ton/yr lb/hr ton/yr lb/hr ton/yrPM 11.9 52.1 11.9 52.1 PM 22.0 96.4 72.6 318.0 72.6 318.0

PM10 11.9 52.1 11.9 52.1 PM10 22.0 96.4 72.6 318.0 72.6 318.0

PM2.5 11.9 52.1 11.9 52.1 PM2.5 22.0 96.4 72.6 318.0 72.6 318.0

SOx 6.9 30.2 6.9 30.2 SOx 6.5 28.3 96.8 423.9 96.8 423.9

NOx 34.1 149.1 34.1 149.1 NOx 37.2 163.0 63.1 276.5 63.1 276.5

VOC 13.4 58.8 13.4 58.8 VOC 11.5 50.5 25.4 111.2 25.4 111.2

CO 27.6 121.0 27.6 121.0 CO 12.1 53.1 26.1 114.5 26.1 114.5

Note: SV007 PM, PM10, PM2.5 lb/hr emissions rates based on modeling data.SO2 lb/hr emissions rate based on lb/MMBtu limit

Worst Case Siemens Worst Case Siemens SV002: CT#2Uncontrolled Natural Gas Uncontrolled Fuel Oil Uncontrolled Emissions

Emissions Emissions Gas or Oil Worst‐case

Worst Case Siemens Worst Case Siemens SV002: CT#2Controlled Natural Gas Controlled Fuel Oil Controlled Emissions

Emissions Emissions Gas or Oil Worst‐case

Worst Case SV007: CT #1Uncontrolled Natural Gas Uncontrolled Emissions

Emissions Natural Gas Only

Worst Case SV007: CT #1Controlled Natural Gas Controlled Emissions

Emissions Natural Gas Only

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[Worst Case Emissions CT1 CT2]

Mankato Energy CenterFacility ID: 013000982015 Air Permit ApplicationH2SO4 Emissions Derivation Calculations

Combined Cycle System (Combustion Turbine and Ductburners) Natural Gas or Fuel Oil Firing

AssumptionsPredicted Conversion of Sulfur to SO2 = 92.0%

Predicted Conversion of Sulfur to SO3 = 8.0%

Predicted Conversion of SO3 to H2SO4 = 100%

Predicted Additional % of H2SO4 from SCR = 10.0%

Predicted Additional % of H2SO4 from Oxidation Catalyst = 4.0%

Molecular Weight of Sulfur = 32

Molecular Weight of SO2 = 64

Molecular Weight of SO3 = 80

Molecular Weight of H2SO4 = 98

Initial SO2 content: 1.00 (lb SO2 / lb SO2 emitted)

Conversion from SO2 to Sulfur(1.00 lbs SO2 / lb SO2 emitted) / (1‐0.08) * (32/64) = 0.54 (lb Sulfur / lb SO2 emitted)

Conversion of Sulfur to SO3

(0.54 lb Sulfur / lb SO2 emitted)) * (0.08) * (80/32) = 0.11 (lb SO3 / lb SO2 emitted)

Conversion of SO3 to H2SO4

(0.11 lb SO3 / lb SO2 emitted) * (98/80) = 0.13 (lb H2SO4 / lb SO2 emitted)

Control Equipment H2SO4 Contribution

(0.13 lb H2SO4 / lb SO2 emitted) * (0.04+0.10) = 0.02 (lb H2SO4 / lb SO2 emitted)

Total H2SO4

(0.13 lb H2SO4 / lb SO2 emitted) + (0.02 lb H2SO4 / lb SO2 emitted) = 0.15 (lb H2SO4 / lb SO2 emitted)

Derived Percentage of H2SO4 Compared to SO2

(0.15 lb H2SO4 / lb SO2 emitted) * 100% = 15.18% (lb H2SO4 / lb SO2 emitted)

C:\Users\thanafy\AppData\Local\Microsoft\Windows\Temporary Internet Files\Content.IE5\VZ60O0D0\MEC Calculations (TSD Attachment 1).xlsx[H2SO4 derivation]

Attachment 2: Requirements Development Report

Subject ItemID Seq. # Requirement

TFAC 1(01300098)

1240

Permit Appendices: This permit contains appendices as listed in the permit Table of Contents. The Permitteeshall comply with all requirements contained in Appendices A (Insignificant Activities and ApplicableRequirements); C (Acid Rain Permit Application); and D (Transport Rule (TR) Trading Program Title VRequirements).

Modeling parameters in Appendix B (Stack Parameters Relied Upon in Modeling) are included for reference onlyas described elsewhere in this permit.

The Permittee is authorized to construct EQUI 16 (approximately 200 MW Combustion Turbine #1 with dry lowNOx burners at 6 degrees F), EQUI 17 (824 mmBtu/hr Duct Burners), EQUI 18 (2500 kW Diesel FiredEmergency Generator), EQUI 20 (CT#1 CEMS Data Acquisition System), EQUI 21 (CT#1 NOx CEMS), EQUI22 (CT#1 CO CEMS), TREA 11 (Selective Catalytic Reduction), TREA 12 (Catalytic Oxidizer), FUGI 2 (NaturalGas Fugitives), FUGI 3 (Breaker Fugitives), additional 4 cells to FUGI 1 (Cooling Tower). The constructionauthorization expires if construction does not commence within 18 months after receipt of such approval by AirEmissions Permit No. 01300098-101, if construction is discontinued for a period of 18 months or more, or ifconstruction is not completed within a reasonable time.

1260

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.

1300Modeled Parameters for CO: The parameters used in CO modeling for permit number 01300098-002 are listedin Appendix B of this permit. The parameters describe the operation of the facility at maximum permittedcapacity. The purpose of listing the parameters in the appendix is to provide a benchmark for future changes.

1310Changes to Modeled Parameters for CO: Any permit amendment that affects any modeled parameter oremission rate for CO listed in Appendix B must be a major amendment. Any addition to the informationdocumented in Appendix B requires a major amendment.

Equivalent or Better Dispersion (EBD) Modeling Triggers (Modeling Required) for NOx: Changes that affect anymodeled parameter or emission rate listed in Appendix B, or an addition to the information documented inAppendix B, trigger the EBD Modeling Submittal requirement.

1320

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

Minn. R. 7007.0800, subp. 2

40 CFR 52.21(r)(2) & Minn. R.7007.3000

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

Minn. R. 7007.3000, Title I Condition:40 CFR 52.21(k)




TSD Requirement (Print version)

Agency Interest Name: Mankato Energy Center LLCActivity Number: IND20150001

Subject ItemID Seq. # RequirementTFAC 1(01300098)

1320j g g

EBD Modeling Submittal for NOx: For changes meeting the criteria in the EBD Modeling Triggers (ModelingRequired) requirement, the Permittee shall submit an EBD modeling submittal in accordance with the currentversion of the MPCA Air Dispersion Modeling Guidance at the time of the modeling and shall wait for writtenapproval (in the form of an issued permit amendment) before making such changes.

1330EBD Modeling Results for NOx: The dispersion characteristics due to the revisions of the information inAppendix B must be equivalent to or better than the dispersion characteristics modeled October 2015. ThePermittee shall demonstrate this equivalency in the proposal.

Outdated EBD Baseline Modeling for NOx: Prior to conducting the EBD analysis, the Permittee shall use thecurrent version of the MPCA Air Dispersion Modeling Guidance to determine if the Baseline Modeling (the mostrecent refined modeling demonstration) is outdated. If the Baseline Modeling is outdated, the Permittee shallupdate the Baseline Modeling to be consistent with the current version of the MPCA Air Dispersion ModelingGuidance. The updated modeling will become the new Baseline Modeling.

This requirement does not require the Permittee to complete a new refined modeling demonstration using therevisions made for the EBD demonstration.

1340

Computer Dispersion Modeling Protocol: due 180 days after receipt of written MPCA request for NOx refinedmodeling. The Permittee shall submit a Computer Dispersion Modeling Protocol that is complete and approvableby MPCA by the deadline in this requirement. This protocol will describe the proposed modeling methodologyand input data, in accordance with the current version of the MPCA Air Dispersion Modeling Guidance. Theprotocol must be based on projected operating conditions under the next permit term.

Computer Dispersion Modeling Triggers for NOx: The Permittee shall conduct a refined remodeling analysis inaccordance with the Computer Dispersion Modeling requirements of this permit and the current version of theMPCA Air Dispersion Modeling Guidance if: (1) the results of the EBD modeling analysis do not demonstrateequivalent or better dispersion characteristics; (2) a conclusion cannot readily be made about the dispersion, or(3) the criteria in the EBD Modeling Triggers requirement are met and the Permittee has previously conductedthree successive EBD analyses using the same Baseline Modeling.

1350 Computer Dispersion Modeling Protocol: due 60 days after receipt of written MPCA request for revisions to thesubmitted protocol for NOx modeling.

Computer Dispersion Modeling Results: due 180 days after receipt of written MPCA approval of ComputerDispersion Modeling Protocol for NOx. The Permittee shall submit a final Computer Dispersion Modeling Reportthat is complete and approvable by MPCA by the deadline in this requirement. The submittal shall adhere to thecurrent version of the MPCA Air Dispersion Modeling Guidance and the approved Computer DispersionModeling Protocol.











g

1360

This source is subject to the U.S. EPA Acid Rain Program codified at 40 CFR pts. 72, 73, and 75. Eachcombustion turbine and duct burner (EQUI 5/EQUI 6 and EQUI 16/EQUI 17) is a utility unit that also is agas-fired unit and a new unit, as defined in 40 CFR Section 72.2.

Some of the Acid Rain Program requirements are included in this permit for MPCA tracking purposes. ThePermittee's acid rain permit application is in Appendix C of this permit.

1370

These requirements apply if a reasonable possibility (RP) as defined in 40 CFR Section 52.21(r)(6)(vi) existsthat a proposed project, analyzed using the actual-to-projected-actual (ATPA) test (either by itself or as part ofthe hybrid test at Section 52.21(a)(2)(iv)(f)) and found to not be part of a major modification, may result in asignificant emissions increase (SEI). If the ATPA test is not used for the project, or if there is no RP that theproposed project could result in a SEI, these requirements do not apply to that project. The Permittee is onlysubject to the Preconstruction Documentation requirement for a project where a RP occurs only within themeaning of Section 52.21(r)(6)(vi)(b).

Even though a particular modification is not subject to New Source Review (NSR), or where there isn't a RP thata proposed project could result in a SEI, a permit amendment, recordkeeping, or notification may still berequired by Minn. R. 7007.1150 - 7007.1500.

1400

Preconstruction Documentation -- Before beginning actual construction on a project, the Permittee shalldocument the following:

1. Project description2. Identification of any emission unit whose emissions of an NSR pollutant could be affected3. Pre-change potential emissions of any affected existing emission unit, and the projected post-changepotential emissions of any affected existing or new emission unit.4. A description of the applicability test used to determine that the project is not a major modification for anyregulated NSR pollutant, including the baseline actual emissions, the projected actual emissions, the amount ofemissions excluded due to increases not associated with the modification and that the emission unit could haveaccommodated during the baseline period, an explanation of why the amounts were excluded, and any credita..

1420

The Permittee shall monitor the actual emissions of any regulated NSR pollutant that could increase as a resultof the project and that were analyzed using the ATPA test, and the potential emissions of any regulated NSRpollutant that could increase as a result of the project and that were analyzed using potential emissions in thehybrid test. The Permittee shall calculate and maintain a record of the sum of the actual and potential (if thehybrid test was used in the analysis) emissions of the regulated pollutant, in tons per year on a calendar yearbasis, for a period of 5 years following resumption of regular operations after the change, or for a period of 10years following resumption of regular operations after the change if the project increases the design capacity ofor potential to emit of any unit associated with the project.

1440

The Permittee must submit a report to the Agency if the annual summed (actual, plus potential if used in hybridtest) emissions differ from the preconstruction projection and exceed the baseline actual emissions by asignificant amount as listed at 40 CFR Section 52.21(b)(23). Such report shall be submitted to the Agency within60 days after the end of the year in which the exceedances occur. The report shall contain:

a. The name and ID number of the Facility, and the name and telephone number of the Facility contact person

b. The annual emissions (actual, plus potential if any part of the project was analyzed using the hybrid test) foreach pollutant for which the preconstruction projection and significant emissions increase are exceeded...

1460Before beginning actual construction of any project which includes any electric utility steam generating unit(EUSGU), the Permittee shall submit a copy of the preconstruction documentation (items 1-4 underPreconstruction Documentation, above) to the Agency.

1470

For any project which includes any EUSGU, the Permittee must submit an annual report to the Agency, within60 days after the end of the calendar year. The report shall contain:

a. The name and ID number of the facility, and the name and telephone number of the facility contact person

b. The quantified annual emissions analyzed using the ATPA test, plus the potential emissions associated withthe same project analyzed as part of a hybrid test.

c. Any other information, such as an explanation as to why the summed emissions differ from the preconstructi..

40 CFR pt. 72, 40 CFR pt. 73, 40 CFRpt. 75, Minn. R. 7007.1075

Minn. R. 7007.0800, subp. 2, Title ICondition: 40 CFR 52.21(r)(6) andMinn. R. 7007.3000

Minn. R. 7007.0800, subps. 4-5, Minn.R. 7007.1200, subp. 4, Title I Condition:40 CFR 52.21(r)(6) and Minn. R.7007.3000

Minn. R. 7007.0800, subps. 4-5, Title ICondition: 40 CFR 52.21(r)(6) andMinn. R. 7007.3000


Minn. R. 7007.0800, subps. 4-5, Title ICondition: 40 CFR 52.21(r)(6)(ii) andMinn. R. 7007.3000





1480

For any project which does not include any EUSGU, the Permittee must submit a report to the Agency if theannual summed (actual, plus potential used in hybrid test) emissions differ from the preconstruction projectionand exceed the baseline actual emissions by a significant amount as listed at 40 CFR Section 52.21(b)(23).Such report shall be submitted to the Agency within 60 days after the end of the year in which the exceedancesoccur. The report shall contain:

a. The name and ID number of the facility, and the name and telephone number of the facility contact person

b. The annual emissions (actual, plus potential if any part of the project was analyzed using the hybrid test) for ..

1490The Permittee shall comply with National Primary and Secondary Ambient Air Quality Standards, 40 CFR pt. 50,and the Minnesota Ambient Air Quality Standards, Minn. R. 7009.0010 to 7009.0080. Compliance shall bedemonstrated upon written request by the MPCA.

1500Circumvention: 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.

1510 Air Pollution Control Equipment: Operate all pollution control equipment whenever the corresponding processequipment and emission units are operated.

1550

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.

1620Fugitive 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.

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.


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

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




p p

1630Noise: 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.

1640 Inspections: The Permittee shall comply with the inspection procedures and requirements as found in Minn. R.7007.0800, subp. 9(A).

1650 The Permittee shall comply with the General Conditions listed in Minn. R. 7007.0800, subp. 16.

1660 Performance Testing: Conduct all performance tests in accordance with Minn. R. ch. 7017 unless otherwisenoted in this permit.

1670

Performance Test Notifications and Submittals:

Performance Tests are due as outlined in this permit.

Performance Test Notification (written): due 30 days before each Performance Test

Performance Test Plan: due 30 days before each Performance Test

Performance Test Pre-test Meeting: due 7 days before each Performance Test..

1680

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.

1690

Monitoring Equipment Calibration - The Permittee shall either:

1. Calibrate or replace required monitoring equipment every 12 months; or

2. 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 an..

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. 7017.2018, 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)




1710

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.

1720 The Permittee shall submit an application for permit reissuance : Due 180 calendar days before PermitExpiration Date.

1750

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).

1760Recordkeeping: 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.

1870

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. For expiring permits, theserecords shall be kept for a period of five years from the date the change was made or until permit reissuance,whichever is longer. The records shall be kept at the stationary source for the current calendar year of operationand may be kept at the stationary source or office of the stationary source for all other years. The records maybe maintained in either electronic or paper format.

1880

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.

3340

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.

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

Minn. R. 7007.0400, subp. 2

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




18910Notification 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.

18920

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; and ..

18930

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.

18940

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.

18950

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).

18960The 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.

18970 Emission Inventory Report: due on or before April 1 of each calendar year following permit issuance, to besubmitted on a form approved by the Commissioner.

Minn. R. 7019.1000, subp. 1

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. 7007.0800, subp. 6(C)

Minn. R. 7019.3000-7019.3100




pp y

18980 Emission Fees: due 30 days after receipt of an MPCA bill.

19390

The Permittee shall submit excess emission/downtime report : Due by 30 days after the end of each calendarquarter following permit issuance. Submit Deviations Reporting Form DRF-1 as amended. The EER shallindicate all periods of monitor bypass and all periods of exceedances of the limit including exceedances allowedby an applicable standard, i.e. during startup, shutdown, and malfunctions. The EER must be submitted even ifthere were no excess emissions, downtime or bypasses during the quarter.

COMG 5 1Formaldehyde <= 9.0 tons per year 12-month rolling sum, regardless of fuel type. This limit applies to the totalcombined emissions from the subject items associated with COMG 5, and at all times including startup,shutdown, and malfunction.

2Hexane <= 9.0 tons per year 12-month rolling sum, regardless of fuel type. This limit applies to the totalcombined emissions from the subject items associated with COMG 5, and at all times including startup,shutdown, and malfunction.

3 HAPs - Total <= 22.5 tons per year 12-month rolling sum. This limit applies to the total combined emissions fromthe subject items associated with COMG 5, and at all times including startup, shutdown, and malfunction.

4

HAP Emissions Monitoring: The Permittee shall determine EQUI 7, EQUI 11, EQUI 18 and EQUI 19formaldehyde, n-hexane, other single HAPs, and total HAP emissions using monthly heat input records, monthlyoperating hours, and applicable emission factors as listed below.EQUI 7: AP 42 Tables 1.4-3 and 1.4-4;EQUI 11: AP 42 Table 3.3-2;EQUI 18: AP 42 Tables 3.3-2, 3.4-3 and 3.4-4;EQUI 19: AP 42 Tables 1.4-3 and 1.4-4.

5 Monthly Heat Input Monitoring: By the 15th of the month, the Permittee shall calculate and record total heat input(in million Btus) for EQUI 7, EQUI 11, EQUI 18 and EQUI 19 for the previous operating month.

Minn. R. 7002.0005-7002.0095

40 CFR 60.7(c), 40 CFR 75.64, Minn.R. 7017.1110, subp. 1-2

Minn. R. 7011.7000, Title I Condition:Avoid major source under 40 CFR 63.2



Minn. R. 7007.0800, subp. 4, Minn. R.7011.7000, Title I Condition: Avoidmajor source under 40 CFR 63.2




Subject ItemID Seq. # RequirementCOMG 5

( ) p p g

6

Monthly HAPs Emissions Monitoring and Recordkeeping:By the 15th of the month, the Permittee shall calculate and record monthly EQUI 7, EQUI 11, EQUI 18 andEQUI 19 formaldehyde, n-hexane and total HAP emissions for the previous calendar month, and the 12 monthrolling sum by summing the formaldehyde, n-hexane and total HAP emissions for the previous 12 months.Formaldehyde, n-hexane and other single HAP emissions are determined using monthly EQUI 7, EQUI 11,EQUI 18 and EQUI 19 heat input data and the applicable lb/mmBtu emission factor from the appropriate Tablein AP 42.Total HAP emissions are determined by summing all individual HAPs data for the previous calendar month andprevious 12 months (12-month rolling sum).

7HAP Emissions Monitoring, Daily Heat Input Monitoring and Monthly HAPs Emissions Monitoring andRecordkeeping requirements are located at STRU 14 for EQUI 5 and EQUI 6, and at STRU 20 for EQUI 16 andEQUI 17.

8

In lieu of using monthly recordkeeping for EQUI 7, EQUI 11, EQUI 18 and EQUI 19, the Permittee may use thefollowing monthly potential to emit values:EQUI 7: Formaldehyde = 0.002 tons/month, n-hexane = 0.045 tons/month, Total HAPs = 0.048 tons/monthEQUI 11: Formaldehyde = 1.2E-05 tons/month, n-hexane = 0 tons/month, Total HAPs = 3.95E-05 tons/monthEQUI 18: Formaldehyde = 8.36E-06 tons/month, n-hexane = 0 tons/month, Total HAPs = 1.71E-04 tons/monthEQUI 19: Formaldehyde = 7.70E-05 tons/month, n-hexane = 1.85E-03 tons/month, Total HAPs = 1.94E-03tons/month.

EQUI 3(MR003)

1 NOx CEMS Daily Calibration Error (CE) Test: Conduct daily CE testing on the NOx CEMS in accordance with 40CFR pt. 75, Appendix B.

4 NOx CEMS RATA Notification: due 30 days before CEMS Relative Accuracy Test Audit (RATA).

5

NOx CEMS Relative Accuracy Test Audit (RATA): Due semiannually following Permit Issuance, i.e., once everytwo successive QA operating quarters (calendar quarter in which there are at least 168 unit operating hours).Conduct a RATA on all CEMS required by the Acid Rain Program, in accordance with 40 CFR pt. 75, AppendixB. Relative accuracy test audits may be performed annually (i.e., once every four successive QA operatingquarters, rather than once every two successive QA operating quarters) if any of the conditions listed in 40 CFRpt. 75, Appendix B, Sections 2.3.1.2(a) through 2.3.1.2(i) are met.

2200 Relative Accuracy Test Audit (RATA) Results Summary: due 30 days after end of each calendar quarter inwhich a RATA was conducted.

Minn. R. 7007.0800, subps. 4-5, Minn.R. 7011.7000, Title I Condition: Avoidmajor source under 40 CFR 63.2

Minn. R. 7007.0800, subp. 2

Minn. R. 7007.0800, subps. 4-5, Minn.R. 7011.7000, Title I Condition: Avoidmajor source under 40 CFR 63.2

40 CFR pt. 75, Appendix B(Sect 2.1)

Minn. R. 7017.1180, subp. 2

40 CFR pt. 75, Appendix B (Sect 2.3.1),Minn. R. 7017.1020

Minn. R. 7017.1180, subp. 3



Subject ItemID Seq. # RequirementEQUI 3(MR003)

2220 Cylinder Gas Audit (CGA) Results Summary: due 30 days after end of each calendar quarter in which a CGAwas conducted.

2410The CEMS/COMS requirements listed below outline the typical standards of 40 CFR Pt. 75. Additionalmonitoring requirements may also apply to the Facility based on the standard and it is the responsibility of theFacility to meet all applicable requirements.

2420 Emissions Monitoring: The owner or operator shall use a CEMS to measure emissions from EQUI 5.

2440

Monitoring Data: Hourly averages shall be computed using at least one data point in each fifteen minutequadrant of an hour, where the unit combusted fuel during that quadrant of an hour. Not withstanding thisrequirement, an hourly average may be computed from at least two data points separated by a minimum of 15minutes (where the unit operates for more than one quadrant of an hour) if data is unavailable as a result of theperformance of calibration, quality assurance, or preventive maintenance activities pursuant to 40 CFR Section75.21 and appendix B of pt. 75, or backups of data from the data acquisition and handling system, orrecertification, pursuant to Section 75.20. The owner or operator shall use all valid measurements or data pointscollected during an hour to calculate the hourly averages. All data points collected during an hour shall be, to theextent practicable, evenly spaced over the hour.

2450 CEMS QA/QC NOx and Diluent Monitoring: The owner or operator of an affected facility shall operate, calibrate,and maintain each CEMS according to the QA/QC procedures in 40 CFR pt. 75, Appendix B as amended.

2470

The Permittee shall conduct linearity and leak check : Due after Startup of Monitor Date quarterly in accordancewith procedures in 40 CFR pt. 75, Appendix B, Sections 2.2.1 and 2.2.2, and Appendix A, Section 6.2. Thismeans once every calendar quarter in which there are at least 168 unit operating hours. Perform a leak check atleast once during each QA operating quarter.

2490 Quarterly Reports: Electronically report the data and information in 40 CFR Section 75.64 (a), (b), and (c) to theAdministrator quarterly.

Minn. R. 7017.1180, subp. 1

Minn. R. 7007.subp. 4, A

40 CFR 75.10(a)

40 CFR 75.10(d)(1)

40 CFR 75.21(a)

40 CFR pt. 75, Appendix B, 2.2

40 CFR 75.64




q y

2500

Recordkeeping: The owner or operator shall maintain for each affected unit a file of all measurements, data,reports, and other information required by this part at the source in a form suitable for inspection for at leastthree (3) years from the date of each record. The file shall contain all information required by 40 CFR Section75.57.

EQUI 4(MR004)

4 CEMS QA/QC Diluent Monitoring: The owner or operator of an affected facility shall operate, calibrate, andmaintain each CEMS according to the QA/QC procedures in 40 CFR pt. 75, Appendix B as amended.

2200 Relative Accuracy Test Audit (RATA) Notification: due 30 days before CO CEMS Relative Accuracy Test Audit(RATA).



2240The CEMS/COMS requirements listed below outline the typical standards of 40 CFR pt. 60 when combined withMinn. R. Additional monitoring requirements may also apply to the Facility based on this combination ofstandards and it is the responsibility of the Facility to meet all applicable requirements.

2260 Carbon Monoxide: Emissions Monitoring: The owner or operator shall use a CEMS to measure emissions fromEQUI 5.

40 CFR 75.57

40 CFR 75.21(a)

Minn. R. 7017.1180, subp. 2

Minn. R. 7017.1180, subp. 3

Minn. R. 7017.1180, subp. 1

Minn. R. 7017.1010

40 CFR pt. 60, subp. GG, Minn. R.7017.1010, subp 1




2270

Certification Test Plan due 30 days before Certification Test.Certification Test Pretest Meeting due 7 days before Certification Test.Certification Test Report - Microfiche Copy due 105 days after Certification Test.Certification Test Report due 45 days after Certification Test.The Notification, Test Plan, and Test Report may be submitted in alternate format as allowed by Minn. R.7017.1120, subp. 2.

2280

Continuous Operation: CEMS must be operated and data recorded during all periods of emission unit operationincluding periods of emission unit start-up, shutdown, or malfunction except for periods of acceptable monitordowntime. This requirement applies whether or not a numerical emission limit applies during these periods. ACEMS must not be bypassed except in emergencies where failure to bypass would endanger human health,safety, or plant equipment.

2290

QA Plan: Develop and implement a written quality assurance plan that covers each CEMS. The plan shall be onsite and available for inspection within 30 days after monitor certification. The plan shall contain all of theinformation required by 40 CFR Part 60, Appendix F, Section 3. The plan shall include the manufacturer's spareparts list for each CEMS and require that those parts be kept at the facility unless the Commissioner giveswritten approval to exclude specific spare parts from the list.

2300

CEMS QA/QC: The owner or operator of an affected facility is subject to the performance specifications listed in40 CFR pt. 60, Appendix B and shall operate, calibrate, and maintain each CEMS according to the QA/QCprocedures in 40 CFR pt. 60, Appendix F as amended and maintain a written QA/QC program available in aform suitable for inspection.

2310

CEMS Daily Calibration Drift Test: Check the zero (low level value between 0 and 20 percent of span value) andspan (50 to 100 percent of span value) calibration drifts at least once daily. The zero and span must, at aminimum, be adjusted whenever the drift exceeds two times the limit specified in 40 CFR pt. 60, Appendix B. 40CFR pt. 60, Appendix F, Section 4.3.1 shall be used to determine out-of-control periods for CEMS.

2360Recordkeeping: The owner or operator must retain records of all CEMS monitoring data and support informationfor a period of five years from the date of the monitoring sample, measurement or report. Records shall be keptat the source.

2370CEMS Certification/Recertification Test: due 90 days after the first excess emissions report required for theCEMS or any change which invalidates the monitor's certification status as outlined in Minn. R. 7017.1050, subp.2.

40 CFR 60.7(a)(5), Minn. R.7017.1060, subp. 1-3, Minn. R.7017.1080, subp. 1-4

40 CFR 60.13(e), Minn. R. 7017.1090

40 CFR pt. 60, Appendix F, 3, Minn. R.7017.1170, subp. 2

40 CFR 60.13(a), 40 CFR pt. 60,Appendix F

40 CFR 60.13(d)(1), 40 CFR pt. 60,Appendix F, 4.1, Minn. R. 7017.1170,subp. 3

40 CFR 60.7(f), Minn. R. 7017.1130

40 CFR 60.13(b)




2380The Permittee shall conduct CEMS cylinder gas audit (CGA) : Due after CEMS Certification Test Date quarterlybut no more than three quarters in succession. A CGA is not required during any calendar quarter in which aRATA was performed.

2381 The Permittee shall conduct CEMS relative accuracy test audit (RATA) : Due after CEMS Certification Test Dateannually meaning by the end of every one of four calendar quarters.

EQUI 5(EU002)

1

Nitrogen Oxides: less than or equal to the value determined by the following equation:

STD = 0.0075 * (14.4/Y) + F

STD = NOx limit in percent by volume at 15 percent oxygen and on a dry basisY = manufacturer's rated heat rate at manufacturer's rated load in kilojoules per watt hour, or actual measuredheat rate based on lower heating value of fuel as measured at actual peak load, not to exceed 14.4 kilojoulesper watt hourF = NOx emission allowance for fuel-bound nitrogen

The use of F (fuel-bound nitrogen allowance) is optional.

2The Permittee shall limit Sulfur Dioxide <= 0.015 percent by volume at 15 percent oxygen and on a dry basis, or

The Permittee shall limit Sulfur Content of Fuel <= 0.8 percent by weight.

3 The Permittee shall limit Sulfur Dioxide <= 0.50 pounds per million Btu heat input The potential to emit from theunit is 0.0022409 lb/MMBtu due to equipment design and allowable fuels.

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

6Permitted Fuel Types: Natural gas as defined in 40 CFR Section 72.2, except total sulfur content shall notexceed 0.8 grains/100 scf and the natural gas shall be obtained from a supplier through a pipeline, and distillatefuel oil with a sulfur content not to exceed 0.05% by weight.

40 CFR pt. 60, Appendix F, 5.1.3


40 CFR 60.332(a)(1), Minn. R.7011.2350

40 CFR 60.333, Minn. R. 7011.2350

Minn. R. 7011.2300, subp. 2

Minn. R. 7011.2300, subp. 1

Minn. R. 7011.2300, subp. 2, Title ICondition: 40 CFR 52.21(j)(BACT) &Minn. R. 7007.3000



Subject ItemID Seq. # RequirementEQUI 5(EU002)

y g

7 The Permittee shall limit Operating Hours <= 875 hours per year 12-month rolling sum while using distillate fueloil.

8NOx Monitoring: The Permittee shall use a CEM to measure NOx emissions according to 40 CFR Sections60.334(d) and (e), or continuously measure the water to fuel or steam to fuel ratio as described in 40 CFRSection 60.334(a).

9Fuel Monitoring: The Permittee shall follow the applicable fuel sulfur and nitrogen content monitoringrequirements in 40 CFR Section 60.334(h) and shall monitor at the frequency specified in 40 CFR Section60.334(i).

10

Recordkeeping - Fuel Oil Operating Hours: Once each day the Permittee shall calculate and record the numberof hours, to the nearest tenth, that the combustion turbine combusted fuel oil, during the previous calendar day.

By the last day of each month, the Permittee shall calculate and record the total fuel oil combustion operatinghours for the combustion turbine, for the previous calendar month and the previous 12-month period.

Separate daily, monthly, and 12-month rolling sum records shall be kept for the combustion turbine.

11 Excess Emission Reports: The Permittee shall submit reports of excess emissions required by 40 CFR Section60.334(j) with the EER required for STRU 14 listed in this permit.

12Performance Testing: The Permittee shall conduct performance testing to measure NOx and SO2, as requiredby 40 CFR Section 60.335, unless the Permittee obtains approval from the Administrator to use alternate testmethods according to 40 CFR Section 60.8(b).

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

Title I Condition: 40 CFR52.21(j)(BACT) & Minn. R. 7007.3000

40 CFR 60.334(d) & (e), Minn. R.7011.2350

40 CFR 60.334(h) & (i), Minn. R.7011.2350

Minn. R. 7007.0800, subps. 4-5, Title ICondition: 40 CFR 52.21(j)(BACT) &Minn. R. 7007.3000

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

40 CFR 60.335, 40 CFR 60.8(a), Minn.R. 7011.2350

Minn. R. 7007.0800, subp. 5




p yp g y

14 Fuel Supplier Certification: The Permittee shall obtain and maintain annual fuel supplier certification for pipelinedelivery of natural gas, certifying that the sulfur content does not exceed 0.8 grains/100 scf.

15 For the purposes of the 40 CFR pt. 97, subp. AAAAA requirements in this permit, the "Permittee" is an "owner"and "operator" as defined in 40 CFR Section 97.402.

16 Transport Rule (TR) NOx Annual Trading Program Requirements.The Permittee shall comply with the TR NOx Annual Trading Program requirements contained in Appendix D.

17Designated representative requirements.The owners and operators shall comply with the requirement to have a designated representative, and mayhave an alternate designated representative, in accordance with 40 CFR Sections 97.413 through 97.418.

18

TR NOx Emissions monitoring, reporting, and recordkeeping requirements.1) The owners and operators and the designated representative of each TR NOx Annual source and each TRNOx Annual unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of 40CFR Section 97.430 (general requirements, including installation, certification, and data accounting, compliancedeadlines, reporting data, prohibitions, and long-term cold storage), 40 CFR Section 97.431 (initial monitoringsystem certification and recertification procedures), 40 CFR Section 97.432 (monitoring system out-of-controlperiods), 40 CFR Section 97.433 (notifications concerning monitoring), 40 CFR Section 97.434 (recordkeepingand reporting, including monitoring plans, certification applications, quarterly reports, and compliancecertification), and 40 CFR Section 97.435 (petitions for alternatives to monitoring, recordkeeping, or reportingrequirements).2) The emissions data determined in accordance with 40 CFR Section 97.430 through 97.435 shall be used to ..

19

TR NOx Annual emissions limitation.i) As of the allowance transfer deadline (midnight of March 1 (if it is a business day), or midnight of the firstbusiness day thereafter (if March 1 is not a business day)) for a control period in a given year, the owners andoperators of each TR NOx Annual source and each TR NOx Annual unit at the source shall hold, in the source'scompliance account, TR NOx Annual allowances available for deduction for such control period under 40 CFRSection 97.424(a) in an amount not less than the tons of total NOx emissions for such control period from all TRNOx Annual units at the source.ii) If total NOx emissions during a control period in a given year from the TR NOx Annual units at a TR NOxAnnual source are in excess of the TR NOx Annual emissions limitation set forth in 40 CFR Section97.406(c)(1)(i) above, then: A) The owners and operators of the source and each TR NOx Annual unit at thesource shall hold the TR NOx Annual allowances required for deduction under 40 CFR Section 97.424(d); and ..

20

TR NOx Annual assurance provisions.i) If total NOx emissions during a control period in a given year from all TR NOx Annual units at TR NOx Annualsources in Minnesota and Indian country within the borders of Minnesota exceed the state assurance level, thenthe owners and operators of such sources and units in each group of one or more sources and units having acommon designated representative for such control period, where the common designated representative'sshare of such NOx emissions during such control period exceeds the common designated representative'sassurance level for the state and such control period, shall hold (in the assurance account established for theowners and operators of such group) TR NOx Annual allowances available for deduction for such control periodunder 40 CFR Section 97.425(a) in an amount equal to two times the product (rounded to the nearest wholenumber), as determined by the Administrator in accordance with 40 CFR Section 97.425(b), of multiplying— A)The quotient of the amount by which the common designated representative's share of such NOx emissions ex..

Minn. R. 7007.0800, subps. 4-5, Title ICondition: 40 CFR pt. 52, 21(j)(BACT)& Minn. R. 7007.3000

Minn. R. 7007.0800, subp. 2

40 CFR 97.430-435

40 CFR 97.406(a)

40 CFR 97.406(b)

40 CFR 97.406(c)(1)

40 CFR 97.406(c)(2)(i)-(v)




21

Compliance periods.i) A TR NOx Annual unit shall be subject to the requirements under 40 CFR Section 97.406(c)(1) above for thecontrol period starting on the later of January 1, 2015, or the deadline for meeting the unit's monitor certificationrequirements under 40 CFR 97.430(b) and for each control period thereafter.ii) A TR NOx Annual unit shall be subject to the requirements under 40 CFR Section 97.406(c)(2) above for thecontrol period starting on the later of January 1, 2017 or the deadline for meeting the unit's monitor certificationrequirements under 40 CFR 97.430(b) and for each control period thereafter.

22

Vintage of allowances held for compliance.i) A TR NOx Annual allowance held for compliance with the requirements under 40 CFR Section 97.406(c)(1)(i)above for a control period in a given year must be a TR NOx Annual allowance that was allocated for suchcontrol period or a control period in a prior year.ii) A TR NOx Annual allowance held for compliance with the requirements under 40 CFR Section97.406(c)(1)(ii)(A) and (2)(i) through (iii) above for a control period in a given year must be a TR NOx Annualallowance that was allocated for a control period in a prior year or the control period in the given year or in theimmediately following year.

23Allowance Management System requirements.Each TR NOx Annual allowance shall be held in, deducted from, or transferred into, out of, or betweenAllowance Management System accounts in accordance with 40 CFR part 97, subpart AAAAA.

24

Limited authorization.A TR NOx Annual allowance is a limited authorization to emit one ton of NOx during the control period in oneyear. Such authorization is limited in its use and duration as follows:i) Such authorization shall only be used in accordance with the TR NOx Annual Trading Program; andii) Notwithstanding any other provision of 40 CFR part 97, the Administrator has the authority to terminate or limitthe use and duration of such authorization to the extent the Administrator determines is necessary orappropriate to implement any provision of the Clean Air Act.

25 Property right. A TR NOx Annual allowance does not constitute a property right.

26

Additional recordkeeping and reporting requirements.1) Unless otherwise provided, the owners and operators of each TR NOx Annual source and each TR NOxAnnual unit at the source shall keep on site at the source each of the following documents (in hardcopy orelectronic format) for a period of 5 years from the date the document is created. This period may be extended forcause, at any time before the end of 5 years, in writing by the Administrator.i) The certificate of representation under 40 CFR Section 97.416 for the designated representative for the sourceand each TR NOx Annual unit at the source and all documents that demonstrate the truth of the statements inthe certificate of representation; provided that the certificate and documents shall be retained on site at thesource beyond such 5-year period until such certificate of representation and documents are supersededbecause of the submission of a new certificate of representation under 40 CFR Section 97.416 changing thedesignated representative. ..

27

Liability.1) Any provision of the TR NOx Annual Trading Program that applies to a TR NOx Annual source or thedesignated representative of a TR NOx Annual source shall also apply to the owners and operators of suchsource and of the TR NOx Annual unit shall also apply to the owners and operators of such unit.2) Any provision of the TR NOx Annual Trading Program that applies to a TR NOx Annual unit or the designatedrepresentative of a TR NOx Annual unit shall also apply to the owners and operators of such unit.

40 CFR 97.406(c)(3)

40 CFR 97.406(c)(4)

40 CFR 97.406(c)(5)

40 CFR 97.406(c)(6)

40 CFR 97.406(c)(7)

40 CFR 97.406(e)

40 CFR 97.406(f)




p pp y p

28

Effect on other authorities.No provision of the TR NOx Annual Trading Program or exemption under 40 CFR Section 97.405 shall beconstrued as exempting or excluding the owners and operators, and the designated representative, of a TR NOxAnnual source or TR NOx Annual unit from compliance with any other provision of the applicable, approvedstate implementation plan, a federally enforceable permit, or the Clean Air Act.

29 Transport Rule (TR) SO2 Group 2 Trading Program Requirements.The Permittee shall comply with the TR SO2 Group 2 Trading Program Requirements contained in Appendix D.

30Designated representative requirements.The owners and operators shall comply with the requirement to have a designated representative, and mayhave an alternate designated representative, in accordance with 40 CFR Section 97.713 through 97.718.

31

TR SO2 Group 2 Emissions monitoring, reporting, and recordkeeping requirements.1) The owners and operators, and the designated representative, of each TR SO2 Group 2 source and each TRSO2 Group 2 unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of40 CFR Section 97.730 (general requirements, including installation, certification, and data accounting,compliance deadlines, reporting data, prohibitions, and long-term cold storage), 40 CFR Section 97.731 (initialmonitoring system certification and recertification procedures), 40 CFR Section 97.732 (monitoring systemout-of-control periods), 40 CFR Section 97.733 (notifications concerning monitoring), 40 CFR Section 97.734(recordkeeping and reporting, including monitoring plans, certification applications, quarterly reports, andcompliance certification), and 40 CFR Section 97.735 (petitions for alternatives to monitoring, recordkeeping, orreporting requirements).2) The emissions data determined in accordance with 40 CFR Section 97.730 through 97.735 shall be used to ..

32

TR SO2 Group 2 emissions limitation.i) As of the allowance transfer deadline (midnight of March 1 (if it is a business day), or midnight of the firstbusiness day thereafter (if March 1 is not a business day)) for a control period in a given year, the owners andoperators of each TR SO2 Group 2 source and each TR SO2 Group 2 unit at the source shall hold, in thesource's compliance account, TR SO2 Group 2 allowances available for deduction for such control period under40 CFR Section 97.724(a) in an amount not less than the tons of total SO2 emissions for such control periodfrom all TR SO2 Group 2 units at the source.ii) If total SO2 emissions during a control period in a given year from the TR SO2 Group 2 units at a TR SO2Group 2 source are in excess of the TR SO2 Group 2 emissions limitation set forth in paragraph 40 CFR Section97.706(c)(1)(i) above, then: A) The owners and operators of the source and each TR SO2 Group 2 unit at thesource shall hold the TR SO2 Group 2 allowances required for deduction under 40 CFR Section 97.724(d); and..

33

TR SO2 Group 2 assurance provisions.i) If total SO2 emissions during a control period in a given year from all TR SO2 Group 2 units at TR SO2 Group2 sources in Minnesota and Indian country within the borders of Minnesota exceed the state assurance level,then the owners and operators of such sources and units in each group of one or more sources and units havinga common designated representative for such control period, where the common designated representative'sshare of such SO2 emissions during such control period exceeds the common designated representative'sassurance level for the state and such control period, shall hold (in the assurance account established for theowners and operators of such group) TR SO2 Group 2 allowances available for deduction for such controlperiod under 40 CFR Section 97.725(a) in an amount equal to two times the product (rounded to the nearestwhole number), as determined by the Administrator in accordance with 40 CFR Section 97.725(b), ofmultiplying— A) The quotient of the amount by which the common designated representative's share of such S..

34

Compliance Periods.i) A TR SO2 Group 2 unit shall be subject to the requirements under 40 CFR Section 97.706(c)(1) above for thecontrol period starting on the later of January 1, 2015 or the deadline for meeting the unit's monitor certificationrequirements under 40 CFR Section 97.730(b) and for each control period thereafterii) A TR SO2 Group 2 unit shall be subject to the requirements under 40 Section CFR 97.706(c)(2) above for thecontrol period starting on the later of January 1, 2017 or the deadline for meeting the unit's monitor certificationrequirements under 40 CFR Section 97.730(b) and for each control period thereafter.

40 CFR 97.406(g)

40 CFR 97.730-735

40 CFR 97.706(a)

40 CFR 97.706(b)

40 CFR 97.706(c)(1)

40 CFR 97.706(c)(2)(i)-(v)

40 CFR 97.706(c)(3)




q ( ) p

35

Vintage of allowances held for compliance.i) A TR SO2 Group 2 allowance held for compliance with the requirements under 40 CFR Section 97.706(c)(1)(i)above for a control period in a given year must be a TR SO2 Group 2 allowance that was allocated for suchcontrol period or a control period in a prior year.ii) A TR SO2 Group 2 allowance held for compliance with the requirements under 40 CFR Section97.706(c)(1)(ii)(A) and (2)(i) through (iii) above for a control period in a given year must be a TR SO2 Group 2allowance that was allocated for a control period in a prior year or the control period in the given year or in theimmediately following year.

36Allowance Management System requirements.Each TR SO2 Group 2 allowance shall be held in, deducted from, or transferred into, out of, or betweenAllowance Management System accounts in accordance with 40 CFR part 97, subpart DDDDD.

37

Limited authorization.A TR SO2 Group 2 allowance is a limited authorization to emit one ton of SO2 during the control period in oneyear. Such authorization is limited in its use and duration as follows:i) Such authorization shall only be used in accordance with the TR SO2 Group 2 Trading Program; andii) Notwithstanding any other provision of 40 CFR part 97, subpart DDDDD, the Administrator has the authorityto terminate or limit the use and duration of such authorization to the extent the Administrator determines isnecessary or appropriate to implement any provision of the Clean Air Act.

38 Property right.A TR SO2 Group 2 allowance does not constitute a property right.

39

Additional recordkeeping and reporting requirements.1) Unless otherwise provided, the owners and operators of each TR SO2 Group 2 source and each TR SO2Group p2 unit at the source shall keep on site at the source each of the following documents (in hardcopy orelectronic format) for a period of 5 years from the date the document is created. This period may be extended forcause, at any time before the end of 5 years, in writing by the Administrator.i) The certificate of representation under 40 CFR Section 97.716 for the designated representative for the sourceand each TR SO2 Group 2 unit at the source and all documents that demonstrate the truth of the statements inthe certificate of representation; provided that the certificate and documents shall be retained on site at thesource beyond such 5-year period until such certificate of representation and documents are supersededbecause of the submission of a new certificate of representation under 40 CFR Section 97.716 changing thedesignated representative. ..

40

Liability.1) Any provision of the TR SO2 Group 2 Trading Program that applies to a TR SO2 Group 2 source or thedesignated representative of a TR SO2 Group 2 source shall also apply to the owners and operators of suchsource and of the TR SO2 Group 2 units at the source.2) Any provision of the TR SO2 Group 2 Trading Program that applies to a TR SO2 Group 2 unit or thedesignated representative of a TR SO2 Group 2 unit shall also apply to the owners and operators of such unit.

41

Effect on other authorities.No provision of the TR SO2 Group 2 Trading Program or exemption under 40 CFR Section 97.705 shall beconstrued as exempting or excluding the owners or operators, and the designated representative, of a TR SO2Group 2 source or TR SO2 Group 2 unit from compliance with any other provision of the applicable, approvedstate implementation plan, a federally enforceable permit, or the Clean Air Act.

40 CFR 97.706(c)(4)

40 CFR 97.706(c)(5)

40 CFR 97.706(c)(6)

40 CFR 97.706(c)(7)

40 CFR 97.706(e)

40 CFR 97.706(f)

40 CFR 97.706(g)




p p y p

42 Additional requirements for Combustion Turbine #2 are located at STRU 14.

EQUI 6(EU004)

1

The Permittee shall limit Sulfur Dioxide <= 0.20 pounds per million Btu heat input 30-day rolling average exceptduring startup, shutdown, or malfunction.

'30-day Rolling Average' is '30 successive boiler operating days rolling average', and 'boiler operating day' isdefined at 40 CFR Section 60.41Da.

2

The Permittee shall limit Nitrogen Oxides <= 1.6 pounds per megawatt-hour 30-day rolling average exceptduring startup, shutdown, or malfunction, or,

The Permittee shall limit Nitrogen Oxides <= 0.15 lb/million Btu using 30-day Rolling Average except duringstartup, shutdown, or malfunction.

'30-day Rolling Average' is '30 successive boiler operating days rolling average', and 'boiler operating day' isdefined at 40 CFR Section 60.41Da. Megawatt-hour is on a gross output basis.

3 Permitted Fuel Type: Natural gas as defined in 40 CFR Section 72.2, except total sulfur content shall not exceed0.8 grains/100 scf and the natural gas shall be obtained from a supplier through a pipeline.


5Duct Burner Compliance Provisions: The Permittee shall follow the compliance provisions in 40 CFR Section60.48Da to determine duct burner compliance with the SO2 limit in 40 CFR Section 60.42Da(b)(2) and the NOxlimit in 40 CFR Section 60.44Da(d).

6 Reporting: Follow reporting requirements in 40 CFR Section 60.49Da as applicable.

Minn. R. 7007.0800, subp. 2

40 CFR 60.43Da(b)(2), 40 CFR60.48Da(a) & (b), Minn. R. 7011.0560

40 CFR 60.44Da(d), 40 CFR60.48Da(a) & (b), Minn. R. 7011.0560



40 CFR 60.48Da, Minn. R. 7011.0560

40 CFR 60.49Da, Minn. R. 7011.0560




p g p g q pp




20780


20790


20800


20810


Minn. R. 7007.0800, subp. 2

40 CFR 97.430-435

40 CFR 97.406(a)

40 CFR 97.406(b)

40 CFR 97.406(c)(1)

40 CFR 97.406(c)(2)(i)-(v)

40 CFR 97.406(c)(3)




q ( ) p

20820



20840



20860


20870


20880


40 CFR 97.406(c)(4)

40 CFR 97.406(c)(5)

40 CFR 97.406(c)(6)

40 CFR 97.406(c)(7)

40 CFR 97.406(e)

40 CFR 97.406(f)

40 CFR 97.406(g)




p p y p



20910


20920


20930


20940


20950


40 CFR 97.730-735

40 CFR 97.706(a)

40 CFR 97.706(b)

40 CFR 97.706(c)(1)

40 CFR 97.706(c)(2)(i)-(v)

40 CFR 97.706(c)(3)

40 CFR 97.706(c)(4)




y g y


20970



20990


21000


21010


21011 Additional requirements for Duct Burner (Combustion Turbine #2) are located at STRU 14.

40 CFR 97.706(c)(5)

40 CFR 97.706(c)(6)

40 CFR 97.706(c)(7)

40 CFR 97.706(e)

40 CFR 97.706(f)

40 CFR 97.706(g)

Minn. R. 7007.0800, subp. 2



Subject ItemID Seq. # Requirement( ) q ( )

EQUI 7(EU005)

2 Total Particulate Matter <= 0.008 pounds per million Btu heat input 3-hour block average.

3 PM < 10 micron <= 0.008 pounds per million Btu heat input 3-hour block average.

4 Nitrogen Oxides <= 0.036 pounds per million Btu heat input 3-hour block average.

5 Sulfur Dioxide <= 0.001 pounds per million Btu heat input 3-hour block average.

6 Carbon Monoxide <= 0.06 pounds per million Btu heat input 3-hour block average.

7 Volatile Organic Compounds <= 0.007 pounds per million Btu heat input 3-hour block average.

9 Permitted Fuel Type: Restricted to natural gas with a sulfur content no greater than 0.8 grains per 100 scf.











yp g g g p

11 Fuel Usage Recordkeeping: Record and maintain records of the amounts fuel combusted on a monthly basis.These records may be in the form of fuel bills or meter readings.

19950

PM < 10 micron : The Permittee shall conduct an initial performance test : Due 180 calendar days after PermitIssuance Date to measure emissions. The performance test shall be conducted at worst case conditions asdefined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 201A and 202, or other method approvedby MPCA in the performance test plan approval.

19970

Total Particulate Matter : The Permittee shall conduct an initial performance test : Due 180 calendar days afterPermit Issuance Date to measure emissions. The performance test shall be conducted at worst case conditionsas defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 5 and 202, or other method approvedby MPCA in the performance test plan approval.

20000

Sulfur Dioxide : The Permittee shall conduct an initial performance test : Due 180 calendar days after PermitIssuance Date to measure emissions. The performance test shall be conducted at worst case conditions asdefined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 6C, or other method approved by MPCAin the performance test plan approval.

20010

Volatile Organic Compounds : The Permittee shall conduct an initial performance test : Due 180 calendar daysafter Permit Issuance Date to measure emissions. The performance test shall be conducted at worst caseconditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 25A, or other methodapproved by MPCA in the performance test plan approval.

20260

Carbon Monoxide : The Permittee shall conduct a performance test : Due before 07/13/2021 every 60 months tomeasure emissions. The first test is due by the date specified and all subsequent tests are due by the end ofeach 60-month period following that date. The performance test shall be conducted at worst case conditions asdefined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 10, or other method approved by MPCAin 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 ..

20270

Nitrogen Oxides : The Permittee shall conduct a performance test : Due before 07/13/2021 every 60 months tomeasure emissions. The first test is due by the date specified and all subsequent tests are due by the end ofeach 60-month period following that date. The performance test shall be conducted at worst case conditions asdefined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 7E, or other method approved by MPCAin 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 ..

40 CFR 60.48c(g)(2), Minn. R.7011.0570










20300

PM < 10 micron: The Permittee shall submit a test frequency plan for PM10: Due 60 calendar days after InitialPerformance Test Date for PM10 emissions. The plan shall specify a testing frequency based on the test dataand MPCA guidance. Future performance tests based on 12-month, 36-month, or 60-month intervals, or asapplicable, shall be required upon written approval of the MPCA.

20320

Total Particulate Matter: The Permittee shall submit a test frequency plan for Total Particulate Matter: Due 60calendar days after Initial Performance Test Date for PM emissions. The plan shall specify a testing frequencybased on the test data and MPCA guidance. Future performance tests based on 12-month, 36-month, or60-month intervals, or as applicable, shall be required upon written approval of the MPCA.

20350

Sulfur Dioxide: The Permittee shall submit a test frequency plan for Sulfur Dioxide: Due 60 calendar days afterInitial Performance Test Date for SO2 emissions. The plan shall specify a testing frequency based on the testdata and MPCA guidance. Future performance tests based on 12-month, 36-month, or 60-month intervals, or asapplicable, shall be required upon written approval of the MPCA.

20360

Volatile Organic Compounds: The Permittee shall submit a test frequency plan for Volatile Organic Compounds:Due 60 calendar days after Initial Performance Test Date for VOC emissions. The plan shall specify a testingfrequency based on the test data and MPCA guidance. Future performance tests based on 12-month, 36-month,or 60-month intervals, or as applicable, shall be required upon written approval of the MPCA.

EQUI 11(EU007)

2EQUI 11 is a 350 hp existing compression ignition reciprocating internal combustion engine (RICE) for whichconstruction commenced prior to June 12, 2006 and is located at an area source of hazardous air pollutants(HAPs).

3 The Permittee shall comply with the applicable requirements for EQUI 11 under 40 CFR pt. 63, subp. ZZZZ nolater than May 3, 2013.

5

Part 63, Subpart ZZZZ Table 2d Requirements:

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; andc. Inspect all hoses and belts every 500 hours of operation or annually, whichever comes first, and replace asnecessary.





40 CFR 63.6590(a)(1)(iii), Minn. R.7011.8150

40 CFR 63.6595(a), Minn. R.7011.8150

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




y

6 The Permittee shall be in compliance with the emission limitations and operating limitations in 40 CFR pt. 63,subp. ZZZZ that apply to EQUI 11 at all times.

7

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.

8

The Permittee must operate and maintain EQUI 11 and after-treatment control device (if any) according to themanufacturer's emission-related written instructions, or develop a maintenance plan which must provide to theextent practicable for the maintenance and operation of EQUI 11 in a manner consistent with good air pollutioncontrol practice for minimizing emissions.

9 The Permittee shall install a non-resettable hour meter on EQUI 11 if one is not already installed.

10The Permittee shall minimize EQUI 11 time spent at idle during startup and minimize EQUI 11 startup time to aperiod needed for appropriate and safe loading of EQUI 11, not to exceed 30 minutes, after which time theemission standards applicable to all times other than startup in Table 2d in 40 CFR pt. 63, subp. ZZZZ apply.

11

The Permittee has the option of utilizing an oil analysis program in order to extend the specified oil changerequirement in Table 2d to 40 CFR pt. 63, subp. ZZZZ. The oil analysis must be performed at the samefrequency specified for changing the oil in Table 2d to 40 CFR pt. 63, subp. ZZZZ. The analysis program must ata minimum analyze the following three parameters: Total Base Number, viscosity, and percent water content.The condemning limits for these parameters are as follows: Total Base Number is less than 30 percent of theTotal Base Number of the oil when new; viscosity of the oil has changed by more than 20 percent from theviscosity of the oil when new; or percent water content (by volume) is greater than 0.5. If all of these condemninglimits are not exceeded, the Permittee is not required to change the oil. If any of the limits are exceeded, thePermittee must change the oil within 2 days of receiving the results of the analysis; if EQUI 11 is not in operationwhen the results of the analysis are received, the Permittee must change the oil within 2 days or beforecommencing operation, whichever is later. The Permittee must keep records of the parameters that are analyz..

13The Permittee must demonstrate continuous compliance with each emission limitation and operating limitation inTable 2d to 40 CFR pt. 63, subp. ZZZZ that applies to EQUI 11 according to methods specified in item 9 inTable 6 to 40 CFR pt. 63, subp. ZZZZ.

40 CFR 63.6605(a), Minn. R.7011.8150

40 CFR 63.6605(b), Minn. R.7011.8150

40 CFR 63.6625(e)(3), 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 63.6640(a), Minn. R.7011.8150




p p

14 The Permittee must also report each instance in which the Permittee did not meet the applicable requirementsfor EQUI 11 in Table 8 of 40 CFR pt. 63, subp. ZZZZ.

15

The Permittee must operate EQUI 11 according to the requirements in 40 CFR Section 63.6640(f)(1) through(4). Any operation other than emergency operation, maintenance and testing, and operation in nonemergencysituations for 50 hours per year, as described in 40 CFR Section 63.6640(f)(1) through (4), is prohibited. If thePermittee does not operate EQUI 11 according to the requirements in 40 CFR Section 63.6640(f)(1) through (4),EQUI 11 will not be considered an emergency engine under 40 CFR pt. 63, subp. ZZZZ and will need to meet allrequirements for non-emergency engines.

16 There is no time limit on the use of EQUI 11 in emergency situations.

17

The Permittee may operate EQUI 11 for any combination of the purposes specified in 40 CFR Section63.6640(f)(2)(i) through (iii) for a maximum of 100 hours per calendar year. Any operation for non-emergencysituations as allowed by 40 CFR Section 63.6640(f)(3) and (4) counts as part of the 100 hours per calendar yearallowed by 40 CFR Section 63.6640(f)(2).

18

The Permittee may operate EQUI 11 for the purpose of maintenance checks and readiness testing, providedthat the tests are recommended by Federal, State or local government, the manufacturer, the vendor, or theinsurance company associated with EQUI 11. Maintenance checks and readiness testing of such units is limitedto 100 hours per year. The Permittee may petition the Administrator for approval of additional hours to be usedfor maintenance checks and readiness testing, but a petition is not required if the Permittee maintains recordsindicating that Federal, State, or local standards require maintenance and testing of emergency RICE beyond100 hours per year.

19EQUI 11 may be operated for up to 50 hours per calendar year in non-emergency situations. The 50 hours ofoperation in non-emergency situations are counted as part of the 100 hours per calendar year for maintenanceand testing provided in 40 CFR Section 63.6640(f)(2)(i).

20 The requirement to submit all of the notifications in 40 CFR Sections 63.7(b) and (c), 63.8(e), (f)(4) and (f)(6),63.9(b) through (e), and (g) and (h) do not apply to EQUI 11 (existing emergency RICE).

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

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

40 CFR 63.6640(f)(1), Minn. R.7011.8150

40 CFR 63.6640(f)(2), Minn. R.7011.8150

40 CFR 63.6640(f)(2)(i), Minn. R.7011.8150

40 CFR 63.6640(f)(4), Minn. R.7011.8150

40 CFR 63.6645(a)(5), Minn. R.7011.8150




( ) g ( ) (g) ( ) pp y ( g g y )

22

If EQUI 11 is operating during an emergency and it is not possible to shut down EQUI 11 in order to perform themanagement practice requirements on the schedule required in Table 2d of 40 CFR pt. 63, subp. ZZZZ, or ifperforming the management practice on the required schedule would otherwise pose an unacceptable riskunder federal, state, or local law, the management practice can be delayed until the emergency is over or theunacceptable risk under federal, state, or local law has abated. The management practice should be performedas soon as practicable after the emergency has ended or the unacceptable risk under federal, state, or local lawhas abated. The Permittee must report any failure to perform the management practice on the schedule requiredand the federal, state or local law under which the risk was deemed unacceptable.

24

The Permittee shall keep the following records:

(1) A copy of each notification and report that you submitted to comply with 40 CFR pt. 63, subp. ZZZZ,including all documentation supporting any Initial Notification or Notification of Compliance Status submitted,according to the requirement in 40 CFR Section 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 Section 63.10(b)(2)(viii).(4) Records of all required maintenance performed on the air pollution control and monitoring equipment.(5) Records of actions taken during periods of malfunction to minimize emissions in accordance with 40 CFRSection 63.6605(b), including corrective actions to restore malfunctioning process and air pollution control and ..

26 The Permittee must keep the records required in Table 6 of 40 CFR pt. 63, subp. ZZZZ to show continuouscompliance with each applicable emission or operating limitation.

27The Permittee must keep records of the maintenance conducted on EQUI 11 in order to demonstrate that thePermittee operated and maintained EQUI 11 and after-treatment control device (if any) according to thePermittee's maintenance plan.

28

If EQUI 11 does not meet the standards applicable to non-emergency engines, the Permittee must keep recordsof the hours of operation of EQUI 11 that is recorded through the non-resettable hour meter. The Permittee mustdocument how many hours are spent for emergency operation, including what classified the operation asemergency and how many hours are spent for non-emergency operation.

29

(a) Records must be in a form suitable and readily available for expeditious review according to 40 CFR Section63.10(b)(1).

(b) As specified in 40 CFR Section 63.10(b)(1), the Permittee must keep each record for 5 years following thedate of each occurrence, measurement, maintenance, corrective action, report, or record.

(c) The Permittee must keep each record readily accessible in hard copy or electronic form for at least 5 yearsafter the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to40 CFR Section 63.10(b)(1).


40 CFR pt. 63, subp. ZZZZ(Table2d)(footnote 2)

40 CFR 63.6655(a), Minn. R.7011.8150

40 CFR 63.6655(d), Minn. R.7011.8150

40 CFR 63.6655(e), Minn. R.7011.8150

40 CFR 63.6655(f), Minn. R. 7011.8150

40 CFR 63.6660, Minn. R. 7011.8150

Minn. R. 7011.2300, subp. 1




p y p p y p g p

33 The Permittee shall limit Total Particulate Matter <= 0.07 grams per horsepower-hour 3-hour block average.

34 The Permittee shall limit PM < 10 micron <= 0.07 grams per horsepower-hour 3-hour block average.

35 The Permittee shall limit Sulfur Dioxide <= 0.14 grams per horsepower-hour 3-hour block average.

36 The Permittee shall limit Sulfur Dioxide <= 0.50 pounds per million Btu heat input. The potential to emit from theunit is 0.04735 lb/MMBtu due to equipment design and allowable fuels.

37 The Permittee shall limit Nitrogen Oxides <= 5.70 grams per horsepower-hour 3-hour block average.

39 The Permittee shall limit Carbon Monoxide <= 0.25 grams per horsepower-hour 3-hour block average.

40 The Permittee shall limit Volatile Organic Compounds <= 0.08 grams per horsepower-hour 3-hour blockaverage.




Minn. R. 7011.2300, subp. 2







g

43 Permitted Fuel Type: Restricted to distillate fuel oil with a sulfur content no greater than 0.05% by weight.

3520

The Permittee shall limit Operating Hours <= 300 hours per year 12-month rolling sum calculated monthly by thelast day of each month. Note this limit is pre-empted by the 100 hour per year limit prescribed by 40 CFRSection 63.6640(f)(2)(i) (except for emergency operation for which the 100 hour per year limit does not apply asprescribed by 40 CFR Section 63.6640(f)(1)).

3530

Monitoring - Distillate Fuel Oil Sulfur Content:

The Permittee shall determine the sulfur content of all distillate fuel oil deliveries using one of the followingoptions:

1. Obtain a supplier certification for each fuel oil delivery stating the percent sulfur by weight in the delivereddistillate fuel oil;

2. Use the results of the 40 CFR part 75 Appendix D fuel oil sulfur determination requirements conducted forEQUI 5, if the distillate fuel oil used by EQUI 11 is from the same supplier and delivery as the distillate fuel oilused by EQUI 5 (two separate fuel oil storage tanks are used; one for EQUI 11 and another for EQUI 5).

3540

Operating Hours Recordkeeping: On each day of operation, the Permittee shall record the operating hours to thenearest tenth of an hour. By the last day of each month, the Permittee shall calculate and record the operatinghours for the previous month based on the daily records, and for the previous 12-month period based on themonthly records.

3550

Hours 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. (EQUI 11 is limitedto 300 hours of operation per year.).


3565 Fuel Supplier Certification: The Permittee shall obtain and maintain a fuel supplier certification for each shipmentof diesel fuel oil, certifying that the sulfur content does not exceed 0.050 percent by weight.


Title I Condition: 40 CFR 52.21(k)(1)(i)& Minn. R. 7007.3000

Minn. R. 7007.subps. 4-5, Title ICondition: 40 CFR 52.21(j)(BACT) &Minn. R. 7007.3000

Minn. R. 7007.0800, subps. 4-5, Title ICondition: 40 CFR 52.21(k)(1)(i) &Minn. R. 7007.3000

Minn. R. 7007.0800, subps. 4-5

Minn. R. 7007.0800, subp. 5

Minn. R. 7007.0800, subps. 4-5




y g p y g

3566 EQUI 11 shall operate on ultra low sulfur (15 ppm) diesel fuel.

3568 The Permittee shall orient STRU 18 so that it vents emissions from EQUI 11 vertically without obstruction.

3569 The Permittee shall locate EQUI 11 away from fresh air intake vents. If the generator is located near a school ordaycare, be aware of times and areas when and where people congregate and avoid them.

EQUI 16(EU008)

2 The combustion turbine shall demonstrate a maximum net heat rate of 7,979 Btu/kWh (HHV) while conductingnet rate performance testing at base load unfired 1X1 operation.



5 Permitted Fuel Type: Natural gas as defined in 40 CFR Section 72.2 except total sulfur content shall not exceed0.8 grains/100 scf and the natural gas shall be obtained from a supplier through a pipeline.

Minn. R. 7007.0800, subp. 2

Minn. R. 7007.0800, subp. 2

Minn. R. 7007.0800, subp. 2


Minn. R. 7011.2300, subp. 2

Minn. R. 7011.2300, subp. 1





g g pp g p p



8 The Permittee shall conduct an initial performance test : Due 180 calendar days after Initial Startup Date of firstfiring and again prior to obtaining a new permit to verify compliance with the heat rate limit.




12


Minn. R. 7007.0800, subp. 5



Minn. R. 7007.0800, subp. 2

40 CFR 97.430-435

40 CFR 97.406(a)

40 CFR 97.406(b)




13


14


15


16



18



40 CFR 97.406(c)(1)

40 CFR 97.406(c)(2)(i)-(v)

40 CFR 97.406(c)(3)

40 CFR 97.406(c)(4)

40 CFR 97.406(c)(5)

40 CFR 97.406(c)(6)

40 CFR 97.406(c)(7)




p y g p p y g

20


21


22




25


26


40 CFR 97.406(e)

40 CFR 97.406(f)

40 CFR 97.406(g)

40 CFR 97.730-735

40 CFR 97.706(a)

40 CFR 97.706(b)

40 CFR 97.706(c)(1)




27


28


29



31



33


40 CFR 97.706(c)(2)(i)-(v)

40 CFR 97.706(c)(3)

40 CFR 97.706(c)(4)

40 CFR 97.706(c)(5)

40 CFR 97.706(c)(6)

40 CFR 97.706(c)(7)

40 CFR 97.706(e)




34


35


36 Additional requirements for Combustion Turbine #1 are located at STRU 20.

EQUI 17(EU009)

1 Permitted Fuel Type: Natural gas as defined in 40 CFR Section 72.2, except total sulfur content shall not exceed0.8 grains/100 scf and the natural gas shall be obtained from a supplier through a pipeline.




40 CFR 97.706(f)

40 CFR 97.706(g)

Minn. R. 7007.0800, subp. 2



Minn. R. 7007.0800, subp. 2

40 CFR 97.430-435




p y g g q pp


20780


20790


20800


20810


20820



40 CFR 97.406(a)

40 CFR 97.406(b)

40 CFR 97.406(c)(1)

40 CFR 97.406(c)(2)(i)-(v)

40 CFR 97.406(c)(3)

40 CFR 97.406(c)(4)

40 CFR 97.406(c)(5)




g y p p

20840



20860


20870


20880




40 CFR 97.406(c)(6)

40 CFR 97.406(c)(7)

40 CFR 97.406(e)

40 CFR 97.406(f)

40 CFR 97.406(g)

40 CFR 97.730-735

40 CFR 97.706(a)




g p g

20910


20920


20930


20940


20950



20970


40 CFR 97.706(b)

40 CFR 97.706(c)(1)

40 CFR 97.706(c)(2)(i)-(v)

40 CFR 97.706(c)(3)

40 CFR 97.706(c)(4)

40 CFR 97.706(c)(5)

40 CFR 97.706(c)(6)




y pp p p y p


20990


21000


21010


21011 Additional requirements for Duct Burners (Combustion Turbine #1) are located at STRU 20.

EQUI 18(EU010)



40 CFR 97.706(c)(7)

40 CFR 97.706(e)

40 CFR 97.706(f)

40 CFR 97.706(g)

Minn. R. 7007.0800, subp. 2

Minn. R. 7011.2300, subp. 2

Minn. R. 7011.2300, subp. 1




p y p p y p g p

4 The Permittee shall limit Operating Hours <= 100 hours per year 12-month rolling sum calculated monthly by thelast day of each month.

5 Operating Hours Daily Recordkeeping: On each day of operation, the Permittee shall record the operating hoursto the nearest tenth of an hour.

6Operating Hours Monthly Recordkeeping: By the 15th of each month, the Permittee shall calculate and recordthe operating hours for the previous month by summing the daily operating hour records, and for the previous12-month period by summing the previous 12 monthly records.

7 The Permittee shall operate EQUI 18 in a manner consistent with good energy efficiency measures according tothe manufacturer's specifications to restrict GHG (greenhouse gas) emissions.

12 Fuel type: No. 2 fuel oil/diesel fuel meeting the requirements of 40 CFR Section 80.510(c) only.


15 Fuel Supplier Certification: The Permittee shall obtain and maintain a fuel supplier certification for each shipmentof diesel fuel oil, certifying that the sulfur content does not exceed 0.050 percent by weight.



Minn. R. 7007.0800, subps. 4-5


Minn. R. 7005.0100, subp. 35a

Minn. R. 7007.0800, subp. 5

Minn. R. 7007.0800, subps. 4-5




y g p y g

16 The Permittee shall use only ultra low sulfur (15 ppm) diesel fuel in EQUI 18.

17 The Permittee shall orient STRU 21 so that it vents emissions from EQUI 18 vertically without obstruction.

18The Permittee shall place EQUI 18 in a location that does not affect ambient or indoor air. If the generator islocated near a school or daycare, be aware of times and areas when and where people congregate and avoidthem.

19

EQUI 18 is a new affected source as defined under 40 CFR pt. 63, subp. ZZZZ, and the facility is an area sourceas defined at 40 CFR Section 63.2, and EQUI 18 is a CI RICE with a site rating of 3352.6 brake HP (2500 kW).The Permittee shall meet the requirements of 40 CFR pt. 63, subp. ZZZZ by meeting the requirements of 40CFR pt. 60, subp. IIII. No further requirements of 40 CFR pt. 63, subp. ZZZZ apply to EQUI 18.

20An affected source that meets any of the criteria in 40 CFR Section 63.6590(c)(1) through (7) must meet therequirements of this part by meeting the requirements of 40 CFR part 60 subpart IIII, for compression ignitionengines. No further requirements apply for such engines under this part.

21The Permittee must comply with the emission standards for new nonroad CI engines in 40 CFR Section60.4202, for all pollutants, for the same model year and maximum engine power for their 2007 model year andlater emergency stationary CI ICE.

22 The Permittee must operate and maintain stationary CI ICE that achieve the emission standards as required in40 CFR Sections 60.4204 and 60.4205 over the entire life of the engine.

Minn. R. 7007.0800, subp. 2

Minn. R. 7007.0800, subp. 2

Minn. R. 7007.0800, subp. 2

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

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

40 CFR 60.4205(b), 40 CFR63.6590(c)(1), Minn. R. 7011.2305,Minn. R. 7011.8150

40 CFR 60.4206, 40 CFR63.6590(c)(1), Minn. R. 7011.2305,Minn. R. 7011.8150




g

23The Permittee must use diesel fuel that meets the requirements of 40 CFR Section 80.510(b) for nonroad dieselfuel, except that any existing diesel fuel purchased (or otherwise obtained) prior to October 1, 2010, may beused until depleted.

24 The Permittee must meet the monitoring requirements of this section. In addition, the Permittee must also meetthe monitoring requirements specified in 40 CFR Section 60.4211.

25

The Permittee must do all of the following, except as permitted under 40 CFR Section 60.4211(g):

(1) Operate and maintain the stationary CI internal combustion engine and control device according to themanufacturer's emission-related written instructions;(2) Change only those emission-related settings that are permitted by the manufacturer; and(3) Meet the requirements of 40 CFR parts 89, 94 and/or 1068, as they apply to you.(c) The Permittee must comply by purchasing an engine certified to the emission standards in 40 CFR Section60.4204(b), or 40 CFR Section 60.4205(b) or (c), as applicable, for the same model year and maximum (or inthe case of fire pumps, NFPA nameplate) engine power. The engine must be installed and configured accordingto the manufacturer's emission-related specifications, except as permitted in 40 CFR Section 60.4211(g).(f) The Permittee must operate the emergency stationary ICE according to the requirements in 40 CFR Section..

26

(continued from above)(3) Emergency stationary ICE may be operated for up to 50 hours per calendar year in non-emergencysituations. The 50 hours of operation in non-emergency situations are counted as part of the 100 hours percalendar year for maintenance and testing and emergency demand response provided in 40 CFR Section60.4211(f)(2). Except as provided in 40 CFR Section 60.4211(f)(3)(i), the 50 hours per calendar year fornon-emergency situations cannot be used for peak shaving or non-emergency demand response, or to generateincome for a facility to an electric grid or otherwise supply power as part of a financial arrangement with anotherentity.

(i) The 50 hours per year for non-emergency situations can be used to supply power as part of a financialarrangement with another entity if all of the following conditions are met:..

27

The Permittee is not required to submit an initial notification. Starting with the model years in 40 CFR pt. 60,subp. IIII table 5, if the emergency engine does not meet the standards applicable to non-emergency engines inthe applicable model year, the Permittee must keep records of the operation of the engine in emergency andnon-emergency service that are recorded through the non-resettable hour meter. The Permittee must record thetime of operation of the engine and the reason the engine was in operation during that time.

28

Except as provided in subparts B and C, the provisions of this part apply to the owner or operator of anystationary source which contains an affected facility, the construction or modification of which is commencedafter the date of publication in this part of any standard (or, if earlier, the date of publication of any proposedstandard) applicable to that facility.

29

Any new or revised standard of performance promulgated pursuant to section 111(b) of the Act shall apply to theowner or operator of any stationary source which contains an affected facility, the construction or modification ofwhich is commenced after the date of publication in this part of such new or revised standard (or, if earlier, thedate of publication of any proposed standard) applicable to that facility.

40 CFR 60.4207(b), 40 CFR63.6590(c)(1), 40 CFR 80.510(b), Minn.R. 7011.2305, Minn. R. 7011.8150

40 CFR 60.4209, 40 CFR63.6590(c)(1), Minn. R. 7011.2305,Minn. R. 7011.8150

40 CFR 60.4211(a) - (f)(2), 40 CFR63.6590(c)(1), Minn. R. 7011.2305,Minn. R. 7011.8150

40 CFR 60.4211(f)(3), 40 CFR63.6590(c)(1), Minn. R. 7011.2305,Minn. R. 7011.8150

40 CFR 60.4214(b), 40 CFR63.6590(c)(1), 40 CFR pt. 60, subp.IIII(Table 5), Minn. R. 7011.2305, Minn.R. 7011.8150

40 CFR 60.1(a), Minn. R. 7011.0050

40 CFR 60.1(b), Minn. R. 7011.0050




p y p p ) pp y

30

In addition to complying with the provisions of this part, the owner or operator of an affected facility may berequired to obtain an operating permit issued to stationary sources by an authorized State air pollution controlagency or by the Administrator of the U.S. Environmental Protection Agency (EPA) pursuant to Title V of theClean Air Act (Act) as amended November 15, 1990 (42 U.S.C. 7661). For more information about obtaining anoperating permit see 40 CFR pt. 70.

31

The availability to the public of information provided to, or otherwise obtained by, the Administrator under thispart shall be governed by 40 CFR pt. 2. (Information submitted voluntarily to the Administrator for the purposesof 40 CFR Sections 60.5 and 60.6 is governed by 40 CFR Sections 2.201 through 2.213 and not by 40 CFRSection 2.301.).

32

The provisions of this part shall not be construed in any manner to preclude any State or political subdivisionthereof from:

(a) Adopting and enforcing any emission standard or limitation applicable to an affected facility, provided thatsuch emission standard or limitation is not less stringent than the standard applicable to such facility.(b) Requiring the Permittee to obtain permits, licenses, or approvals prior to initiating construction, modification,or operation of such facility.

33 No 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.

34

Except as provided under 40 CFR Section 60.14(e) and (f), any physical or operational change to an existingfacility which results in an increase in the emission rate to the atmosphere of any pollutant to which a standardapplies shall be considered a modification within the meaning of section 111 of the Act. Upon modification, anexisting facility shall become an affected facility for each pollutant to which a standard applies and for whichthere is an increase in the emission rate to the atmosphere.

35 Emission rate shall be expressed as kg/hr of any pollutant discharged into the atmosphere for which a standardis applicable. The Administrator shall use 40 CFR Section 60.14(b)(1) and (2) to determine emission rate.

36 The addition of an affected facility to a stationary source as an expansion to that source or as a replacement foran existing facility shall not by itself bring within the applicability of this part any other facility within that source.

40 CFR 60.1(c), Minn. R. 7011.0050

40 CFR 60.9

40 CFR 60.10

40 CFR 60.12, Minn. R. 7011.0050

40 CFR 60.14(a), Minn. R. 7011.0050

40 CFR 60.14(b), Minn. R. 7011.0050

40 CFR 60.14(c), Minn. R. 7011.0050




g y y g pp y p y y

37

The following shall not, by themselves, be considered modifications under this part:

(1) Maintenance, repair, and replacement which the Administrator determines to be routine for a sourcecategory, subject to the provisions of 40 CFR Section 60.14(c) and 40 CFR Section 60.15.(2) An increase in production rate of an existing facility, if that increase can be accomplished without a capitalexpenditure on that facility.(3) An increase in the hours of operation.(4) Use of an alternative fuel or raw material if, prior to the date any standard under this part becomes applicableto that source type, as provided by 40 CFR Section 60.1, the existing facility was designed to accommodate thatalternative use. A facility shall be considered to be designed to accommodate an alternative fuel or raw materialif that use could be accomplished under the facility's construction specifications as amended prior to the chang..

38 Special provisions set forth under an applicable subpart of this part shall supersede any conflicting provisions ofthis section.

39 Within 180 days of the completion of any physical or operational change subject to the control measuresspecified in 40 CFR Section 60.14(a), compliance with all applicable standards must be achieved.

40

No physical change, or change in the method of operation, at an existing electric utility steam generating unitshall be treated as a modification for the purposes of this section provided that such change does not increasethe maximum hourly emissions of any pollutant regulated under this section above the maximum hourlyemissions achievable at that unit during the 5 years prior to the change.

45 An existing facility, upon reconstruction, becomes an affected facility, irrespective of any change in emissionrate.

46

Reconstruction means the replacement of components of an existing facility to such an extent that:

(1) The fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would berequired to construct a comparable entirely new facility, and(2) It is technologically and economically feasible to meet the applicable standards set forth in this part.

47 Fixed capital cost means the capital needed to provide all the depreciable components.

40 CFR 60.14(e), Minn. R. 7011.0050

40 CFR 60.14(f), Minn. R. 7011.0050

40 CFR 60.14(g), Minn. R. 7011.0050

40 CFR 60.14(h), Minn. R. 7011.0050

40 CFR 60.15(a), Minn. R. 7011.0050

40 CFR 60.15(b), Minn. R. 7011.0050

40 CFR 60.15(c), Minn. R. 7011.0050




p p p p p

48

If a Permittee proposes to replace components, and the fixed capital cost of the new components exceeds 50percent of the fixed capital cost that would be required to construct a comparable entirely new facility, thePermittee shall notify the Administrator of the proposed replacements. The notice must be postmarked 60 days(or as soon as practicable) before construction of the replacements is commenced and must include thefollowing information:

(1) Name and address of the owner or operator.(2) The location of the existing facility.(3) A brief description of the existing facility and the components which are to be replaced.(4) A description of the existing air pollution control equipment and the proposed air pollution control equipment.(5) An estimate of the fixed capital cost of the replacements and of constructing a comparable entirely new facil..

49The Administrator will determine, within 30 days of the receipt of the notice required by 40 CFR Section 60.15(d)and any additional information he may reasonably require, whether the proposed replacement constitutesreconstruction.

50

The Administrator's determination under 40 CFR Section 60.15(e) shall be based on:

(1) The fixed capital cost of the replacements in comparison to the fixed capital cost that would be required toconstruct a comparable entirely new facility;(2) The estimated life of the facility after the replacements compared to the life of a comparable entirely newfacility;(3) The extent to which the components being replaced cause or contribute to the emissions from the facility;and(4) Any economic or technical limitations on compliance with applicable standards of performance which areinherent in the proposed replacements.

3520 Individual subparts of this part may include specific provisions which refine and delimit the concept ofreconstruction set forth in this section.

3560

If the Permittee is required to submit periodic reports under 40 CFR pt. 60, and there is an established timelinefor submission of periodic reports that is consistent with the reporting frequency(ies) specified for such facility,the Permittee may change the dates by which periodic reports under 40 CFR pt. 60 shall be submitted (withoutchanging the frequency of reporting) to be consistent with the schedule by mutual agreement between thePermittee and the State. The allowance in the previous sentence applies in each State beginning 1 year afterthe affected facility is required to be in compliance with the applicable subpart in 40 CFR pt. 60. Proceduresgoverning the implementation of this provision are specified in paragraph (f) of 40 CFR Section 60.19.

3565

If a Permittee supervises one or more stationary sources affected by standards set under 40 CFR pt. 60 and thatstandards set under pts. 61, 63 or both of this chapter, the Permittee may arrange by mutual agreementbetween the Permittee and the Administrator (or the State with approved permit program) a common scheduleon which periodic reports required by each applicable standard shall be submitted throughout the year. Theallowance in the previous sentence applies in each State beginning 1 year after the affected facility is required tobe in compliance with the applicable subpart in 40 CFR pt. 60, or 1 year after the stationary source is required tobe in compliance with the applicable 40 CFR pt. 61 or 63 of this chapter standard, whichever is latest.Procedures governing the implementation of this provision are specified in paragraph (f) of 40 CFR Section60.19.

19530

Until an adjustment of a time period or postmark deadline has been approved by the Administrator under 40CFR Section 60.19(f)(2) and (f)(3), the Permittee remains strictly subject to the requirements of 40 CFR pt. 60.A Permittee shall request the adjustment provided for in 40 CFR Section 60.19(f)(2) and (f)(3) each time he orshe wishes to change an applicable time period or postmark deadline specified in 40 CFR pt. 60.

(2) Notwithstanding time periods or postmark deadlines specified in this part for the submittal of information tothe Administrator by a Permittee, or the review of such information by the Administrator, such time periods ordeadlines may be changed by mutual agreement between the Permittee and the Administrator. A Permittee whowishes to request a change in a time period or postmark deadline for a particular requirement shall request theadjustment in writing as soon as practicable before the subject activity is required to take place. The Permitteeshall include in the request whatever information he or she considers useful to convince the Administrator that ..

40 CFR 60.15(d), Minn. R. 7011.0050

40 CFR 60.15(e), Minn. R. 7011.0050

40 CFR 60.15(f), Minn. R. 7011.0050

40 CFR 60.15(g), Minn. R. 7011.0050

40 CFR 60.19(d), Minn. R. 7011.0050

40 CFR 60.19(e), Minn. R. 7011.0050

40 CFR 60.19(f), Minn. R. 7011.0050



Subject ItemID Seq. # Requirement( )

EQUI 19(EU011)

1 The Permittee shall limit Total Particulate Matter <= 0.40 pounds per million Btu heat input 3-hour average.

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

EQUI 21(MR005)

1 NOx CEMS Daily Calibration Error (CE) Test: Conduct daily CE testing on the NOx CEMS in accordance with 40CFR pt. 75, Appendix B.

4 NOx CEMS RATA Notification: due 30 days before CEMS Relative Accuracy Test Audit (RATA).

5

NOx CEMS Relative Accuracy Test Audit (RATA): Due semiannually following certification of the equipment, i.e.,once every two successive QA operating quarters (calendar quarter in which there are at least 168 unitoperating hours). Conduct a RATA on all CEMS required by the Acid Rain Program, in accordance with 40 CFRpt. 75, Appendix B. Relative accuracy test audits may be performed annually (i.e., once every four successiveQA operating quarters, rather than once every two successive QA operating quarters) if any of the conditionslisted in 40 CFR pt. 75, Appendix B, Sections 2.3.1.2(a) through 2.3.1.2(i) are met.


2210 Installation Notification: due 60 days before installing the continuous emissions monitoring system. Thenotification shall include plans and drawings of the system.

Minn. R. 7011.0515, subp. 1, Minn. R.7011.0550

Minn. R. 7011.0515, subp. 2

40 CFR pt. 75, Appendix B(Sect 2.1)

Minn. R. 7017.1180, subp. 2

40 CFR pt. 75, Appendix B (Sect 2.3.1),Minn. R. 7017.1020

Minn. R. 7017.1180, subp. 3

Minn. R. 7017.1040, subp. 1




p g y


2410The CEMS/COMS requirements listed below outline the typical standards of 40 CFR Pt. 75. Additionalmonitoring requirements may also apply to the Facility based on the standard and it is the responsibility of theFacility to meet all applicable requirements.

2420 Emissions Monitoring: The owner or operator shall use a CEMS to measure emissions from EQUI 16.

2430

Certification Application: The owner or operator shall apply for certification of each continuous emission oropacity monitoring system used under the Acid Rain Program. The owner or operator shall submit thecertification application in accordance with 40 CFR Section 75.60 and each complete certification applicationshall include the information specified in Section 75.63.

2440

Monitoring Data: Hourly averages shall be computed using at least one data point in each fifteen minutequadrant of an hour, where the unit combusted fuel during that quadrant of an hour. Not withstanding thisrequirement, an hourly average may be computed from at least two data points separated by a minimum of 15minutes (where the unit operates for more than one quadrant of an hour) if data is unavailable as a result of theperformance of calibration, quality assurance, or preventive maintenance activities pursuant to 40 CFR Section75.21 and appendix B of pt. 75, or backups of data from the data acquisition and handling system, orrecertification, pursuant to Section 75.20. The owner or operator shall use all valid measurements or data pointscollected during an hour to calculate the hourly averages. All data points collected during an hour shall be, to theextent practicable, evenly spaced over the hour.

2450 CEMS QA/QC NOx and Diluent Monitoring: The owner or operator of an affected facility shall operate, calibrate,and maintain each CEMS according to the QA/QC procedures in 40 CFR pt. 75, Appendix B as amended.

2470

The Permittee shall conduct linearity and leak check : Due after Startup of Monitor Date quarterly in accordancewith procedures in 40 CFR pt. 75, Appendix B, Sections 2.2.1 and 2.2.2, and Appendix A, Section 6.2. Thismeans once every calendar quarter in which there are at least 168 unit operating hours. Perform a leak check atleast once during each QA operating quarter.

Minn. R. 7017.1180, subp. 1

Minn. R. 7007.subp. 4, A

40 CFR 75.10(a)

40 CFR 75.20(a)(2), 40 CFR75.60(b)(1), 40 CFR 75.63

40 CFR 75.10(d)(1)

40 CFR 75.21(a)

40 CFR pt. 75, Appendix B, 2.2




g p g q

2490 Quarterly Reports: Electronically report the data and information in 40 CFR Section 75.64 (a), (b), and (c) to theAdministrator quarterly.

2500

Recordkeeping: The owner or operator shall maintain for each affected unit a file of all measurements, data,reports, and other information required by this part at the source in a form suitable for inspection for at leastthree (3) years from the date of each record. The file shall contain all information required by 40 CFR Section75.57.

EQUI 22(MR006)

4 CEMS QA/QC Diluent Monitoring: The owner or operator of an affected facility shall operate, calibrate, andmaintain each CEMS according to the QA/QC procedures in 40 CFR pt. 75, Appendix B as amended.

2200 Relative Accuracy Test Audit (RATA) Notification: due 30 days before CO CEMS Relative Accuracy Test Audit(RATA).


2220 Installation Notification: due 60 days before installing the continuous emissions monitoring system. Thenotification shall include plans and drawings of the system.


40 CFR 75.64

40 CFR 75.57

40 CFR 75.21(a)

Minn. R. 7017.1180, subp. 2

Minn. R. 7017.1180, subp. 3

Minn. R. 7017.1040, subp. 1

Minn. R. 7017.1180, subp. 1




2240The CEMS/COMS requirements listed below outline the typical standards of 40 CFR pt. 60 when combined withMinn. R. Additional monitoring requirements may also apply to the Facility based on this combination ofstandards and it is the responsibility of the Facility to meet all applicable requirements.

2260 Carbon Monoxide: Emissions Monitoring: The owner or operator shall use a CEMS to measure emissions fromEQUI 16.

2270

Certification Test Plan due 30 days before Certification Test.Certification Test Pretest Meeting due 7 days before Certification Test.Certification Test Report - Microfiche Copy due 105 days after Certification Test.Certification Test Report due 45 days after Certification Test.The Notification, Test Plan, and Test Report may be submitted in alternate format as allowed by Minn. R.7017.1120, subp. 2.

2280

Continuous Operation: CEMS must be operated and data recorded during all periods of emission unit operationincluding periods of emission unit start-up, shutdown, or malfunction except for periods of acceptable monitordowntime. This requirement applies whether or not a numerical emission limit applies during these periods. ACEMS must not be bypassed except in emergencies where failure to bypass would endanger human health,safety, or plant equipment.

2290

QA Plan: Develop and implement a written quality assurance plan that covers each CEMS. The plan shall be onsite and available for inspection within 30 days after monitor certification. The plan shall contain all of theinformation required by 40 CFR Part 60, Appendix F, Section 3. The plan shall include the manufacturer's spareparts list for each CEMS and require that those parts be kept at the facility unless the Commissioner giveswritten approval to exclude specific spare parts from the list.

2300


2310

CEMS Daily Calibration Drift Test: Check the zero (low level value between 0 and 20 percent of span value) andspan (50 to 100 percent of span value) calibration drifts at least once daily. The zero and span must, at aminimum, be adjusted whenever the drift exceeds two times the limit specified in 40 CFR pt. 60, Appendix B. 40CFR pt. 60, Appendix F, Section 4.3.1 shall be used to determine out-of-control periods for CEMS.

Minn. R. 7017.1010

40 CFR pt. 60, subp. KKKK, Minn. R.7017.1010, subp 1

40 CFR 60.7(a)(5), Minn. R.7017.1060, subp. 1-3, Minn. R.7017.1080, subp. 1-4

40 CFR 60.13(e), Minn. R. 7017.1090

40 CFR pt. 60, Appendix F, 3, Minn. R.7017.1170, subp. 2

40 CFR 60.13(a), 40 CFR pt. 60,Appendix F

40 CFR 60.13(d)(1), 40 CFR pt. 60,Appendix F, 4.1, Minn. R. 7017.1170,subp. 3




p pp p

2350Recordkeeping: The owner or operator must retain records of all CEMS monitoring data and support informationfor a period of five years from the date of the monitoring sample, measurement or report. Records shall be keptat the source.

2360 The Permittee shall submit start-up notification : Due 10 working days after Startup of Monitor Date.

2370CEMS Certification/Recertification Test: due 90 days after the first excess emissions report required for theCEMS or any change which invalidates the monitor's certification status as outlined in Minn. R. 7017.1050, subp.2.

2380The Permittee shall conduct CEMS cylinder gas audit (CGA) : Due after CEMS Certification Test Date quarterlybut no more than three quarters in succession. A CGA is not required during any calendar quarter in which aRATA was performed.

2381 The Permittee shall conduct CEMS relative accuracy test audit (RATA) : Due after CEMS Certification Test Dateannually meaning by the end of every one of four calendar quarters.

EQUI 23 1 The Permittee shall install a fixed roof tank.

2 The Permittee shall maintain the tank in good working condition according to the operation and maintenance(O&M) plan.

40 CFR 60.7(f), Minn. R. 7017.1130

Minn. R. 7007.0800, subp. 2

40 CFR 60.13(b)







Subject ItemID Seq. # RequirementEQUI 23

( ) p

3 The Permittee shall equip the storage vessel with a permanent submerged fill pipe.

EQUI 24 1 The Permittee shall maintain the tank in good working condition according to the operation and maintenance(O&M) plan.

2 The Permittee shall equip the storage vessel with a permanent submerged fill pipe.

FUGI 1(FS001)

1 The Permittee shall control PM, PM10 and PM2.5 emissions by installing, operating, and maintaining a misteliminator with a drift rate designed not to exceed 0.0005%.

2 Total Particulate Matter <= 0.020 grains per dry standard cubic foot.

3680 Opacity <= 20 percent opacity.

3681 The Permittee shall maintain documentation of manufacturer's guarantee that the mist eliminator meets thedesign drift rate of 0.0005%.

Minn. R. 7011.1505, subp. 3.B


Minn. R. 7011.1505, subp. 3.B


Minn. R. 7011.0735, Table 2

Minn. R. 7011.0715, subp. 1(B)

Minn. R. 7007.0800, subp. 2



Subject ItemID Seq. # Requirement( ) g

FUGI 2(FS002)

1 The Permittee shall conduct audio/visual/olfactory (AVO) inspections each calendar quarter for natural gaspiping components to detect leaks of natural gas.

2 The Permittee shall keep records of the quarterly AVO leak inspections on natural gas piping components.

FUGI 3(FS003)

1 The Permittee shall use state-of-the-art enclosed-pressure sulfur hexafluoride (SF6) circuit breakers with leakdetection for the breakers associated with EQUI 16.

2 At least once per calendar month, the Permittee shall inspect the pressure and record the results of theinspection.

3Corrective Actions: The Permittee shall take corrective action as soon as possible if the pressure of the breakersis found to be outside the manufacturer's recommended range during the monthly inspection. The Permitteeshall keep a record of the type and date of any corrective action taken for FUGI 3.

STRU 14(SV002)

3 The Permittee shall operate the combustion turbine generator/duct burner (CTG/DB; EQUI 5/EQUI 6) in amanner consistent with good combustion practices to restrict emissions of PM, PM10, NOx, CO, and VOC.

5

Operating Mode: Normal operating mode is all operation of EQUI 5 at 60% or greater of the CTG maximumpotential load based on ambient conditions at the time of operation when combusting natural gas or distillate fueloil. Limits apply whether or not the duct burners are operating.

For CO limit applicability, full load is all operation at 90% or greater of rated capacity for the ambient conditions,and less than full load is all operation greater than or equal to 60% load and less than 90% of rated capacity forthe ambient conditions.

The CEMS data acquisition and handling system monitors EQUI 5 load (using a CTG gross megawatt signalprovided by the CTG control system (not including steam turbine electrical output)) and indicates whether EQUI5 is operating in normal mode or startup/shutdown mode. The percent load signal is also used by the CEMS to ..




Title I Condition: 40 CFR pt. 52,21(j)(BACT) & Minn. R. 7007.3000

Minn. R. 7007.0800, subp. 2


Minn. R. 7007.0800, subp. 2



Subject ItemID Seq. # RequirementSTRU 14(SV002)

8The Permittee shall limit Nitrogen Oxides <= 3.0 parts per million 3-hour rolling average by volume on a drybasis corrected to 15% O2 when EQUI 5 combusts natural gas. This limit does not apply during startup,shutdown, or malfunction.

9The Permittee shall limit Nitrogen Oxides <= 5.5 parts per million 3-hour rolling average by volume on a drybasis corrected to 15% O2 when EQUI 5 combusts distillate fuel oil. This limit does not apply during startup,shutdown, or malfunction.

11The Permittee shall limit Carbon Monoxide <= 4.0 parts per million 3-hour rolling average by volume on a drybasis corrected to 15% O2. This limit applies at all times when EQUI 5 combusts natural gas and operates at fullload. This limit does not apply during startup, shutdown, or malfunction.

12The Permittee shall limit Carbon Monoxide <= 4.7 parts per million 3-hour rolling average by volume on a drybasis corrected to 15% O2. This limit applies at all times when EQUI 5 combusts natural gas and operates atless than full load. This limit does not apply during startup, shutdown, or malfunction.

13The Permittee shall limit Carbon Monoxide <= 4.8 parts per million 3-hour rolling average by volume on a drybasis corrected to 15% O2 when EQUI 5 combusts distillate fuel oil and operates at full load. This limit does notapply during startup, shutdown, or malfunction.

14The Permittee shall limit Carbon Monoxide <= 10.2 parts per million 3-hour rolling average by volume on a drybasis corrected to 15% O2 when EQUI 5 combusts distillate fuel oil and operates at less than full load. This limitdoes not apply during startup, shutdown, or malfunction.

16The Permittee shall limit Volatile Organic Compounds <= 3.4 parts per million 3-hour block average by volumeon a dry basis corrected to 15% O2 when EQUI 5 combusts natural gas. This limit applies at all times exceptduring startup, shutdown, or malfunction.

40 CFR 60.332(a)(1), Minn. R.7011.2350, Title I Condition: 40 CFR52.21(j)(BACT) & Minn. R. 7007.3000,Title I Condition: 40 CFR 52.21(k)(1)(i)& Minn. R. 7007.3000

40 CFR 60.332(a)(1), Minn. R.7011.2350, Title I Condition: 40 CFR52.21(j)(BACT) & Minn. R. 7007.3000,Title I Condition: 40 CFR 52.21(k)(1)(i)& Minn. R. 7007.3000









g p

17The Permittee shall limit Volatile Organic Compounds <= 7.1 parts per million 3-hour block average by volumeon a dry basis corrected to 15% O2 when EQUI 5 combusts distillate fuel oil. This limit applies at all times exceptduring startup, shutdown, or malfunction.

19The Permittee shall limit Total Particulate Matter <= 0.009 pounds per million Btu heat input 3-hour blockaverage and not to exceed 22.0 lb/hr, also on a 3-hour block average, when combusting natural gas in EQUI 5.This limit applies at all times including during startup, shutdown, or malfunction.

20The Permittee shall limit Total Particulate Matter <= 0.057 pounds per million Btu heat input 3-hour blockaverage and not to exceed 72.8 lb/hr, also on a 3-hour block average, when combusting distillate fuel oil in EQUI5. This limit applies at all times including during startup, shutdown, or malfunction.

22The Permittee shall limit PM < 10 micron <= 0.009 pounds per million Btu heat input 3-hour block average andnot to exceed 22.0 lb/hr, also on a 3-hour block average, when combusting natural gas in EQUI 5. This limitapplies at all times including during startup, shutdown, or malfunction.

23The Permittee shall limit PM < 10 micron <= 0.057 pounds per million Btu heat input 3-hour block average andnot to exceed 72.8 lb/hr, also on a 3-hour block average, when combusting distillate fuel oil in EQUI 5. This limitapplies at all times including during startup, shutdown, or malfunction.

25The Permittee shall limit PM < 2.5 micron <= 0.009 pounds per million Btu heat input 3-hour block average andnot to exceed 22.0 lb/hr, also on a 3-hour block average, when combusting natural gas in EQUI 5. This limitapplies at all times including during startup, shutdown, or malfunction.

26The Permittee shall limit PM < 2.5 micron <= 0.057 pounds per million Btu heat input 3-hour block average andnot to exceed 72.8 lb/hr, also on a 3-hour block average, when combusting distillate fuel oil in EQUI 5. This limitapplies at all times including during startup, shutdown, or malfunction.






Minn. R. 7007.0800, subp. 2

Minn. R. 7007.0800, subp. 2




pp g g p

33The Permittee shall limit Sulfur Dioxide <= 0.8 grains of sulfur/100 standard cubic feet of natural gas on acalendar year average. This limit applies at all times including startup, shutdown, and malfunction. This limit isequivalent to 0.0022409 lb SO2/mmBtu at 1020 Btu/scf.

34 The Permittee shall limit Sulfur Content of Fuel <= 0.05 percent by weight for No. 2 distillate fuel oil. This limitapplies at all times including startup, shutdown, and malfunction.

35

Startup and Shutdown Operating Mode is all operation of EQUI 5 at less than 60 percent of the CTG maximumpotential load based on ambient conditions at the time of operation when combusting natural gas or distillate fueloil.

Cold startup is when the Combustion Turbine #2 steam turbine was last online more than 48 hours prior to thestartup. Warm startup is any startup that occurs when the steam turbine was last online no more than 48 hoursprior to the startup. The steam turbine is online when any steam is fed to the steam turbine.

For distillate fuel oil startup, EQUI 5 initially combusts natural gas and then switches to distillate fuel oil duringthe startup process. For distillate fuel oil shutdown, EQUI 5 switches from distillate fuel oil to natural gas duringthe shutdown process.

37 EQUI 5 Startup, Shutdown, and Malfunction: The terms "startup", "shutdown", and "malfunction" shall have thesame meanings as defined in 40 CFR Section 60.2.

38 The Permittee shall restrict startup and shutdown operation for the CTG/DB (EQUI 5/EQUI 6) to the shortesttime period possible to restrict emissions of PM, PM10, NOx, CO, and VOC.

39Control Equipment Operation During Startup and Shutdown: Operation of TREA 4, TREA 5, and TREA 6, andTREA 9 is not required during EQUI 5 startup. During shutdown, control equipment operation shall continue aslong as is physically possible.

40 The Permittee shall limit Nitrogen Oxides <= 7.44 tons per year 12-month rolling sum during cold startups onnatural gas. NOx is limited to 323.5 lbs per cold startup event on natural gas.











g p p g

41

The Permittee shall limit Nitrogen Oxides <= 1.38 tons per year 12-month rolling sum during cold startups ondistillate fuel oil. NOx is limited to 459.3 lbs per cold startup event on distillate fuel oil.

Emissions from natural gas combustion that occur before the switch to distillate fuel oil that is part of the distillatefuel oil startup process are included in the emissions subject to this limit.

42 The Permittee shall limit Nitrogen Oxides <= 13.64 tons per year 12-month rolling sum during warm startups onnatural gas. NOx is limited to 148.3 lbs per warm startup event on natural gas.

44

The Permittee shall limit Nitrogen Oxides <= 1.69 tons per year 12-month rolling sum during warm startups ondistillate fuel oil. NOx is limited to 140.7 lbs per warm startup event on distillate fuel oil.


45 The Permittee shall limit Nitrogen Oxides <= 0.50 tons per year 12-month rolling sum during shutdown ofequipment while firing natural gas. NOx is limited to 4.4 lbs per shutdown event while firing natural gas.

46

The Permittee shall limit Nitrogen Oxides <= 0.25 tons per year 12-month rolling sum during shutdown ofequipment while firing distillate fuel oil. NOx is limited to 16.8 lbs per shutdown event while firing distillate fuel oil.

Emissions from natural gas combustion that occur after the switch from distillate fuel oil to natural gas as part ofthe distillate fuel oil shutdown process are included in the emissions subject to this limit.

47 The Permittee shall limit Carbon Monoxide <= 123.94 tons per year 12-month rolling sum during cold startups onnatural gas. CO is limited to 5387.6 lbs per cold startup event on natural gas.

48

The Permittee shall limit Carbon Monoxide <= 4.49 tons per year 12-month rolling sum during cold startups ondistillate fuel oil. CO is limited to 1498.2 lbs per cold startup event on distillate fuel oil.












p p j

49 The Permittee shall limit Carbon Monoxide <= 282.31 tons per year 12-month rolling sum during warm startupson natural gas. CO is limited to 3068.6 lbs per warm startup event on natural gas.

51

The Permittee shall limit Carbon Monoxide <= 6.55 tons per year 12-month rolling sum during warm startups ondistillate fuel oil. CO is limited to 545.9 lbs per warm startup event on distillate fuel oil.


52 The Permittee shall limit Carbon Monoxide <= 5.39 tons per year 12-month rolling sum during shutdown ofequipment while firing natural gas. CO is limited to 46.8 lbs per shutdown event while firing natural gas.

53

The Permittee shall limit Carbon Monoxide <= 4.64 tons per year 12-month rolling sum during shutdown ofequipment while firing distillate fuel oil. CO is limited to 309.3 lbs per shutdown event while firing distillate fuel oil.


54 The Permittee shall limit Volatile Organic Compounds <= 61.96 tons per year 12-month rolling sum during coldstartups on natural gas only. VOC is limited to 2693.8 lbs per cold startup event on natural gas only.

55

The Permittee shall limit Volatile Organic Compounds <= 2.25 tons per year 12-month rolling sum during coldstartups on distillate fuel oil. VOC is limited to 749.1 lbs per cold startup event on distillate fuel oil.


56 The Permittee shall limit Volatile Organic Compounds <= 141.15 tons per year 12-month rolling sum duringwarm startups on natural gas. VOC is limited to 1534.3 lbs per warm startup event on natural gas.











p g p p g

58

The Permittee shall limit Volatile Organic Compounds <= 3.28 tons per year 12-month rolling sum during warmstartups on distillate fuel oil. VOC is limited to 272.9 lbs per warm startup event on distillate fuel oil.


59The Permittee shall limit Volatile Organic Compounds <= 2.69 tons per year 12-month rolling sum duringshutdown of equipment while firing natural gas. VOC is limited to 23.4 lbs per shutdown event while firing naturalgas.

60

The Permittee shall limit Volatile Organic Compounds <= 2.32 tons per year 12-month rolling sum duringshutdown of equipment while firing distillate fuel oil. VOC is limited to 154.7 lbs per shutdown event while firingdistillate fuel oil.


64HAP Emissions Monitoring: The Permittee shall determine STRU 14 formaldehyde, n-hexane, other singleHAPs, and total HAP emissions using daily heat input records, daily operating hours, and applicable emissionfactors as specified in this permit.

71

Daily Heat Input Monitoring: Once each calendar day, the Permittee shall calculate and record total EQUI 5 heatinput (in million Btus) for each of the three defined EQUI 5 operating levels (<60% load, 60% - <90% load, and90% or greater load) during the previous operating day. If EQUI 6 is operated, the Permittee shall calculate andseparately record EQUI 6 heat input (in million Btus) for the previous operating day.

EQUI 5 operating load is determined on an hourly basis according to the CTG operating capacity for the ambientconditions at the time of operation.

72

Determination of Formaldehyde and n-Hexane Emission Factors For Emission Calculations:

1. The Permittee shall determine the load-dependent formaldehyde emission factors for calculatingformaldehyde emissions from combusting natural gas (NG) using the results from the most recentMPCA-approved and reviewed stack test as follows:

a. The NG formaldehyde factor for determining emissions from operation at less than 60 percent load shall bethe average of three test runs, or the maximum one hour test run as allowed by this permit, at 15 to 30 percentload;b. The NG formaldehyde factor for determining emissions from operation at 60 to less than 90 percent load shallbe the average of three test runs, or the maximum one hour test run as allowed by this permit, at 60 to 70 perc..

73

Monthly HAPs Emissions Monitoring and Recordkeeping:

By the last day of each month, the Permittee shall calculate and record monthly STRU 14 formaldehyde,n-hexane, and total HAP emissions for the previous calendar month.

NG HAP Emissions: Formaldehyde and n-hexane emissions from NG combustion are determined using dailyEQUI 5 and EQUI 6 heat input data and the applicable lb/mmBtu emission factor. For all other single HAPs fromNG combustion, EQUI 5 and EQUI 6 single HAP emissions are determined for each emission unit using eachunit's daily heat input records and applicable AP-42 emission factor.

FO HAP Emissions: Formaldehyde and n-hexane emissions from FO combustion are determined using daily E..






Minn. R. 7007.0800, subp. 4

Minn. R. 7007.0800, subp. 4




74 See EQUI 3 for additional NOx CEMS requirements and EQUI 4 for additional CO CEMS requirements.

75 Emissions Monitoring: The Permittee shall measure or calculate SO2, NOx, and CO2 emission rates inaccordance with 40 CFR pt. 75.

76

Emissions Monitoring: The Permittee shall use a Continuous Emissions Monitoring System (CEMS) to measureNOx emissions, and measure or calculate SO2 and CO2 in accordance with 40 CFR pt. 75 for STRU 14. ThePermittee shall measure NOx emissions in ppmvd corrected to 15% oxygen and automatically calculate andrecord the 3-hour average NOx emission rate. NOx ppmvd emission data shall also be converted to lb/mmBtuas required by 40 CFR pt. 75.

78 Emissions Monitoring: The Permittee shall use a CEMS to measure CO emissions in ppmvd corrected to 15%oxygen. The Permittee shall automatically calculate and record the 3-hour average CO emission rate.

79

Operating Load and Operating Conditions Monitoring - The Permittee shall:

1. Continuously monitor, determine, and record the hourly heat input rate (mmBtu/hr) for EQUI 5/EQUI 6 usingthe methods specified at 40 CFR pt. 75, Appendix D Section 3.4;2. Monitor and record the time and duration of each startup, shutdown, and malfunction;3. Record the start and stop time of each steam turbine-generator on-line and off-line period.4. Monitor and record the percent operating load (using the combustion turbine automated control system andthe CEMS data aquisition and handling system).

80 NOx CEMS Quality Assurance/Quality Control (QA/QC): The Permittee shall operate, calibrate, and maintain theNOx CEMS according to the QA/QC procedure in 40 CFR pt. 75, Appendix B, as amended.

82

NOx CEMS and CO CEMS Continuous Operation: The NOx CEMS and CO CEMS must be operated and datarecorded during all periods of emission unit operation including periods of emission unit start-up, shutdown, ormalfunction except for periods of acceptable monitor downtime. This requirement applies whether or not anumerical emission limit applies during these periods. The CEMS must not be bypassed except in emergencieswhere failure to bypass would endanger human health, safety, or plant equipment.

Acceptable CEM downtime includes reasonable periods as listed in items A, B, C and D of Minn. R. 7017.1090,subp. 2.

Minn. R. 7007.0800, subp. 2

40 CFR 75.10, Minn. R. 7017.1020

40 CFR 75.10, Minn. R. 7017.1006,Title I Condition: 40 CFR52.21(j)(BACT) & Minn. R. 7007.3000


40 CFR 75.10, Minn. R. 7007.0800,subp. 4, Minn. R. 7011.7000, Minn. R.7017.1006, Title I Condition: 40 CFR52.21(j)(BACT) & Minn. R. 7007.3000,Title I Condition: Avoid major sourceunder 40 CFR 63.2

40 CFR 75.21

Minn. R. 7017.1090, subp. 1




p

84 NOx and CO CAM Requirements: The Permittee shall use the NOx CEMS and CO CEMS to satisfy therequirements of 40 CFR pt. 64.

85

VOC CAM Requirements: The Permittee shall use the CO CEMS for VOC compliance assurance monitoring.Compliance with the CO limit indicated by the CO CEMS assures that VOC emissions are in compliance withthe VOC limit.

The Permittee shall demonstrate this correlation by recording and comparing CO CEMS emissions data duringSTRU 14 VOC performance testing, with results of the VOC testing. The correlation shall be valid only if testingdemonstrates that VOC emissions comply with the applicable VOC limit at the same time that CO emissions(measured by the CO CEMS) comply with the applicable CO limit, and the CO CEMS certification testing hasbeen satisfactorily completed.

96

Documentation of Need for Improved VOC Monitoring: If the Permittee fails to achieve compliance with the VOCemission limit when the CO CEMS did not provide an indication of a VOC emissions excursion or exceedancewhile the CO CEMS provided valid CO emissions data, or the results of VOC performance testing document aneed to modify the existing CO indicator of VOC emissions compliance, the Permittee shall promptly notify theMPCA and, if necessary, submit a permit amendment application to address the necessary monitoring changes.

97Recordkeeping: The Permittee must retain records of all CEMS monitoring data and support information for aperiod of five years from the date of the monitoring sample, measurement or report. Records shall be kept at thesource.

98

PM < 10 micron : The Permittee shall conduct a performance test : Due before 09/30/2016 every 60 months tomeasure emissions at Natural Gas base load with duct burner operation. The first test is due by the datespecified and all subsequent tests are due by the end of each 60-month period following that date. Theperformance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, usingEPA Reference Method 201A and 202, or other method approved by MPCA in the performance test planapproval. Testing while combusting distillate fuel oil at base load is only required if EQUI 5 combusts distillatefuel oil for more than 50 hours in any 12-month period during the 60 months prior to the required performancetest.

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: ..

99

PM < 2.5 micron : The Permittee shall conduct a performance test : Due before 06/23/2018 every 60 months tomeasure emissions at Natural Gas base load with duct burner operation. The first test is due by the datespecified and all subsequent tests are due by the end of each 60-month period following that date. Theperformance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, usingEPA Reference Method 201A and 202, or other method approved by MPCA in the performance test planapproval. Testing while combusting distillate fuel oil at base load is only required if EQUI 5 combusts distillatefuel oil for more than 50 hours in any 12-month period during the 60 months prior to the required performancetest.

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: ..

19880

Total Particulate Matter : The Permittee shall conduct a performance test : Due before 09/30/2016 every 60months to measure emissions at Natural Gas base load with duct burner operation. The first test is due by thedate specified and all subsequent tests are due by the end of each 60-month period following that date. Theperformance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, usingEPA Reference Method 5 and 202, or other method approved by MPCA in the performance test plan approval.Testing while combusting distillate fuel oil at base load is only required if EQUI 5 combusts distillate fuel oil formore than 50 hours in any 12-month period during the 60 months prior to the required performance test.

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; ..

40 CFR 64.3(d), Minn. R. 7017.0200

40 CFR 64.3(a), 40 CFR 64.6(b), Minn.R. 7017.0200

40 CFR 64.7(e), Minn. R. 7017.0200

40 CFR 75.57, Minn. R. 7017.1130


Minn. R. 7007.0800, subp. 2, Minn. R.7017.2020, subp. 1





19890

Volatile Organic Compounds : The Permittee shall conduct a performance test : Due before 09/30/2016 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 25A, or other methodapproved by MPCA in the performance test plan approval. Testing while combusting distillate fuel oil is onlyrequired if EQUI 5 combusts distillate fuel oil for more than 50 hours in any 12-month period during the 60months prior to the required performance test.

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; ..

20230

Hexane : The Permittee shall conduct a performance test : Due before 09/30/2016 every 60 months to verify theemission factor of hexane (in lb/mmBtu). The first test is due by the date specified and all subsequent tests aredue by the end of each 60-month period following that date. The performance test shall be conducted at worstcase conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 18, 320, or othermethod approved by MPCA in the performance test plan approval. The tests shall be conducted whilecombusting natural gas at 90 to 100 percent load (base load with EQUI 6).

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; or ..

20240

Formaldehyde : The Permittee shall conduct a performance test : Due before 09/30/2016 every 30 months toverify the emission factor of formaldehyde (in lb/mmBtu). The first test is due by the date specified and allsubsequent tests are due by the end of each 30-month period following that date. The performance test shall beconducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method18, 320, or other method approved by MPCA in the performance test plan approval. The tests shall beconducted while combusting natural gas under the following conditions:

1. 15 to 30 percent load;2. 60 to 70 percent load;3. 90 to 100 percent load (base load with EQUI 6)...

20250

NG Formaldehyde Testing Frequency Plan:The Permittee may submit a Testing Frequency Plan (TFP) after any formaldehyde emission factor test in orderto reduce test frequency, based on the MPCA emission factor test frequency guidance, and the most recent NGformaldehyde test results. Any revision to test frequency through submittal of a TFP does not take effect until thetest frequency is incorporated into this permit through a permit amendment.Notwithstanding other STRU 14 testing requirements in this permit that allow formaldehyde testing at 60-monthintervals, test frequency may only be reduced through the submittal of a TFP if current test results showformaldehyde emission factor variability is less than or equal to 40% of the previous formaldehyde test at thecomparable CTG operating level.As described in the MPCA emission factor test frequency guidance, test frequency may be relaxed to onceevery 36 months if emission factor variability is between 10% through 40% of the previous test result for the co..

20290

Protocol for Re-Setting Emission Factors Used For Calculating Formaldehyde and n-Hexane Emissions FromNG Combustion: The Permittee shall conduct performance testing under conditions that produce:

1. The maximum formaldehyde emission rate for each of the three operating ranges (<60%, 60% - <90%, and90% or greater load (also referred to as 'full load')); and,

2. The maximum n-hexane emission rate at 90% or greater load.

The Permittee shall use U.S. EPA Reference Methods 323 and 18 to measure formaldehyde and n-hexaneemissions, respectively, as required elsewhere in this permit. The Permittee shall report each test result as alb/mmBtu emission factor in the performance test report required by Minn. R. 7017.2035, subp. 1...

20291

Notwithstanding the Protocol detailed above, the MPCA reserves the right to set operational limits andrequirements as allowed under Minn. R. 7017.2025. If the MPCA sets limits, the new limits shall be implementedupon receipt of the NOC letter that notifies the Permittee of preliminary approval. The limits set according toMinn. R. 7017.2025 are final upon issuance of a permit amendment incorporating the change.

20292The Permittee must apply for and obtain a major permit amendment if the Permittee wishes to deviate from theProtocol for Re-Setting Emission Factors Used For Calculating Formaldehyde and n-Hexane Emissions FromNatural Gas Combustion established by this permit.


Minn. R. 7011.7000, Minn. R.7017.2020, subp. 1, Title I Condition:Avoid major source under 40 CFR 63.2


Minn. R. 7017.2020, subp. 1


Minn. R. 7017.2025

Minn. R. 7007.1500, subp. 1




y p

20293 Additional requirements for Combustion Turbine #2 are located at EQUI 5. Additional requirements for DuctBurner (Combustion Turbine #2) are located at EQUI 6.

STRU 20(SV007)

1 The Permittee shall operate the combustion turbine generator/duct burner (CTG/DB; EQUI 16/EQUI 17) in amanner consistent with good combustion practices to restrict emissions of PM, PM10, NOx, CO, and VOC.

2

Operating Mode: Normal operating mode is all operation of EQUI 16 at 60% or greater of the CTG maximumpotential load based on ambient conditions at the time of operation when combusting natural gas. Limits applywhether or not the duct burners are operating.

For CO limit applicability, full load is all operation at 90% or greater of rated capacity for the ambient conditions,and less than full load is all operation greater than or equal to 60% load and less than 90% of rated capacity forthe ambient conditions.

The CEMS data acquisition and handling system monitors EQUI 16 load (using a CTG gross megawatt signalprovided by the CTG control system (not including steam turbine electrical output)) and indicates whether EQUI16 is operating in normal mode or startup/shutdown mode. The percent load signal is also used by the CEMS t..

3

The shakedown period for EQUI 16 is defined as the period of time commencing on the date of initial startup andterminating on the earlier of the following three dates:

1. 180 days after initial startup of EQUI 16, or2. 60 days after achieving maximum production of EQUI 16, or3. Submittal of successful compliance test and CEMS certification reports for EQUI 16.

4The Permittee shall limit Nitrogen Oxides <= 3.0 parts per million 3-hour rolling average by volume on a drybasis corrected to 15% O2 when EQUI 16 combusts natural gas. This limit does not apply during startup,shutdown, malfunction, or tuning. This limit does not apply until after the shakedown period ends.

5

The Permittee shall limit Carbon Monoxide <= 4.0 parts per million 3-hour rolling average by volume on a drybasis corrected to 15% O2. This limit applies at all times when EQUI 16 combusts natural gas and operates atfull load. This limit does not apply during startup, shutdown, malfunction, or tuning. This limit does not apply untilafter the shakedown period ends.

6

The Permittee shall limit Carbon Monoxide <= 4.7 parts per million 3-hour rolling average by volume on a drybasis corrected to 15% O2. This limit applies at all times when EQUI 16 combusts natural gas and operates atless than full load. This limit does not apply during startup, shutdown, malfunction, or tuning. This limit does notapply until after the shakedown period ends.

Minn. R. 7007.0800, subp. 2


Minn. R. 7007.0800, subp. 2


Title I Condition: 40 CFR52.21(j)(BACT) & Minn. R. 7007.3000,Title I Condition: 40 CFR 52.21(k)(1)(i)& Minn. R. 7007.3000






pp y p

7The Permittee shall limit Volatile Organic Compounds <= 3.4 parts per million 3-hour block average by volumeon a dry basis corrected to 15% O2 when EQUI 16 combusts natural gas. This limit does not apply duringstartup, shutdown, malfunction, or tuning. This limit does not apply until after the shakedown period ends.

8

The Permittee shall limit Total Particulate Matter <= 0.0098 pounds per million Btu heat input 3-hour blockaverage and not to exceed 11.9 lb/hr, also on a 3-hour block average, when combusting natural gas in EQUI 16.This limit applies at all times including during startup, shutdown, or malfunction. This limit does not apply untilafter the shakedown period ends.

9

The Permittee shall limit PM < 10 micron <= 0.0098 pounds per million Btu heat input 3-hour block average andnot to exceed 11.9 lb/hr, also on a 3-hour block average, when combusting natural gas in EQUI 16. This limitapplies at all times including during startup, shutdown, or malfunction. This limit does not apply until after theshakedown period ends.

10

The Permittee shall limit PM < 2.5 micron <= 0.0098 pounds per million Btu heat input 3-hour block average andnot to exceed 11.9 lb/hr, also on a 3-hour block average, when combusting natural gas in EQUI 16. This limitapplies at all times including during startup, shutdown, or malfunction. This limit does not apply until after theshakedown period ends.

11The Permittee shall limit Carbon Dioxide (Total) and Carbon Dioxide Equivalent <= 1000 pounds permegawatt-hour 12-month rolling average of gross energy output. This limit does not apply until after theshakedown period ends.

12

Startup and Shutdown Operating Mode is all operation of EQUI 16 at less than 60 percent of the CTG maximumpotential load based on ambient conditions at the time of operation when combusting natural gas.

Cold startup is when the Combustion Turbine #1 steam turbine was last online more than 48 hours prior to thestartup. Warm startup is any startup that occurs when the steam turbine was last online no more than 48 hoursprior to the startup. The steam turbine is online when any steam is fed to the steam turbine.

13 EQUI 16 Startup, Shutdown, and Malfunction: The terms "startup", "shutdown", and "malfunction" shall have thesame meanings as defined in 40 CFR Section 60.2.





40 CFR 60.5520(a), 40 CFR pt. 60,subp. TTTT(Table 2), Title I Condition:40 CFR 52.21(j)(BACT) & Minn. R.7007.3000






g

14 The Permittee shall restrict startup and shutdown operation for the CTG/DB (EQUI 16/EQUI 17) to the shortesttime period possible to restrict emissions of PM, PM10, NOx, CO, and VOC.

15Control Equipment Operation During Startup and Shutdown: Operation of TREA 10, TREA 11, and TREA 12 isnot required during EQUI 16 startup. During shutdown, control equipment operation shall continue as long as isphysically possible.

16

The Permittee shall limit Nitrogen Oxides <= 41.9 tons per year 12-month rolling sum during cold startups, warmstartups and shutdowns on natural gas. NOx is limited to 414 lbs per cold startup event, 220 lbs per warmstartup event, and 27 lbs per shutdown event on natural gas. This limit does not apply until after the shakedownperiod ends.

19

The Permittee shall limit Carbon Monoxide <= 666.63 tons per year 12-month rolling sum during cold startups,warm startups and shutdowns on natural gas. CO is limited to 5919 lbs per cold startup event, 3788 lbs perwarm startup event, and 301 lbs per shutdown event on natural gas. This limit does not apply until after theshakedown period ends.

22

The Permittee shall limit Volatile Organic Compounds <= 333.32 tons per year 12-month rolling sum during coldstartups, warm startups and shutdowns on natural gas. VOC is limited to 2959.5 lbs per cold startup event,1894.0 lbs per warm startup event, and 150.5 lbs per shutdown event on natural gas. This limit does not applyuntil after the shakedown period ends.

25HAP Emissions Monitoring: The Permittee shall determine STRU 20 formaldehyde, n-hexane, other singleHAPs, and total HAP emissions using daily heat input records, daily operating hours, and applicable emissionfactors as specified in this permit.

26

Daily Heat Input Monitoring: Once each calendar day, the Permittee shall calculate and record total EQUI 16heat input (in million Btus) for each of the three defined EQUI 16 operating levels (<60% load, 60% - <90% load,and 90% or greater load) during the previous operating day. If EQUI 17 is operated, the Permittee shall calculateand separately record EQUI 17 heat input (in million Btus) for the previous operating day.

EQUI 16 operating load is determined on an hourly basis according to the CTG operating capacity for theambient conditions at the time of operation.











p

27

Determination of Formaldehyde and n-Hexane Emission Factors For Emission Calculations:

1. The Permittee shall determine the load-dependent formaldehyde emission factors for calculatingformaldehyde emissions from combusting natural gas (NG) using the results from the most recentMPCA-approved and reviewed stack test as follows:

a. The NG formaldehyde factor for determining emissions from operation at less than 60 percent load shall bethe average of three test runs, or the maximum one hour test run as allowed by this permit, at 15 to 30 percentload;b. The NG formaldehyde factor for determining emissions from operation at 60 to less than 90 percent load shallbe the average of three test runs, or the maximum one hour test run as allowed by this permit, at 60 to 70 perc..

28

Monthly HAPs Emissions Monitoring and Recordkeeping:

By the last day of each month, the Permittee shall calculate and record monthly STRU 20 formaldehyde,n-hexane, and total HAP emissions for the previous calendar month.

NG HAP Emissions: Formaldehyde and n-hexane emissions from NG combustion are determined using dailyEQUI 16 and EQUI 17 heat input data and the applicable lb/mmBtu emission factor. For all other single HAPsfrom NG combustion, EQUI 16 and EQUI 17 single HAP emissions are determined for each emission unit usingeach unit's daily heat input records and applicable AP-42 emission factor.

Total HAP emissions are determined by summing all individual HAPs data for the previous calendar month...

29

Protocol for Re-Setting Emission Factors Used For Calculating Formaldehyde and n-Hexane Emissions FromNG Combustion: The Permittee shall conduct performance testing under conditions that produce:

1. The maximum formaldehyde emission rate for each of the three operating ranges (<60%, 60% - <90%, and90% or greater load (also referred to as 'full load')); and,

2. The maximum n-hexane emission rate at 90% or greater load.

The Permittee shall use U.S. EPA Reference Methods 323 and 18 to measure formaldehyde and n-hexaneemissions, respectively, as required elsewhere in this permit. The Permittee shall report each test result as alb/mmBtu emission factor in the performance test report required by Minn. R. 7017.2035, subp. 1...

30

Notwithstanding the Protocol detailed above, the MPCA reserves the right to set operational limits andrequirements as allowed under Minn. R. 7017.2025. If the MPCA sets limits, the new limits shall be implementedupon receipt of the NOC letter that notifies the Permittee of preliminary approval. The limits set according toMinn. R. 7017.2025 are final upon issuance of a permit amendment incorporating the change.

31The Permittee must apply for and obtain a major permit amendment if the Permittee wishes to deviate from theProtocol for Re-Setting Emission Factors Used For Calculating Formaldehyde and n-Hexane Emissions FromNatural Gas Combustion established by this permit.

32 See EQUI 21 for additional NOx CEMS requirements and EQUI 22 for additional CO CEMS requirements.

33 Emissions Monitoring: The Permittee shall measure or calculate SO2, NOx, and CO2 emission rates inaccordance with 40 CFR pt. 75.

Minn. R. 7007.0800, subp. 4

Minn. R. 7007.0800, subp. 4


Minn. R. 7017.2025

Minn. R. 7007.1500, subp. 1

Minn. R. 7007.0800, subp. 2

40 CFR 75.10, Minn. R. 7017.1020




p

34

Emissions Monitoring: The Permittee shall use a Continuous Emissions Monitoring System (CEMS) to measureNOx emissions, and measure or calculate SO2 and CO2 in accordance with 40 CFR pt. 75 for STRU 20. ThePermittee shall measure NOx emissions in ppmvd corrected to 15% oxygen and automatically calculate andrecord the 3-hour average NOx emission rate. NOx ppmvd emission data shall also be converted to lb/mmBtuas required by 40 CFR pt. 75.

35 Emissions Monitoring: The Permittee shall use a CEMS to measure CO emissions in ppmvd corrected to 15%oxygen. The Permittee shall automatically calculate and record the 3-hour average CO emission rate.

36

Operating Load and Operating Conditions Monitoring - The Permittee shall:

1. Continuously monitor, determine, and record the hourly heat input rate (mmBtu/hr) for EQUI 16/EQUI 17using the methods specified at 40 CFR pt. 75, Appendix D Section 3.4;2. Monitor and record the time and duration of each startup, shutdown, and malfunction;3. Record the start and stop time of each steam turbine-generator on-line and off-line period.4. Monitor and record the percent operating load (using the combustion turbine automated control system andthe CEMS data acquisition and handling system).

37 NOx CEMS Quality Assurance/Quality Control (QA/QC): The Permittee shall operate, calibrate, and maintain theNOx CEMS according to the QA/QC procedure in 40 CFR pt. 75, Appendix B, as amended.

38

NOx CEMS and CO CEMS Continuous Operation: The NOx CEMS and CO CEMS must be operated and datarecorded during all periods of emission unit operation including periods of emission unit start-up, shutdown, ormalfunction except for periods of acceptable monitor downtime. This requirement applies whether or not anumerical emission limit applies during these periods. The CEMS must not be bypassed except in emergencieswhere failure to bypass would endanger human health, safety, or plant equipment.

Acceptable CEM downtime includes reasonable periods as listed in items A, B, C and D of Minn. R. 7017.1090,subp. 2.

39 NOx and CO CAM Requirements: The Permittee shall use the NOx CEMS and CO CEMS to satisfy therequirements of 40 CFR pt. 64.

40

VOC CAM Requirements: The Permittee shall use the CO CEMS for VOC compliance assurance monitoring.Compliance with the CO limit indicated by the CO CEMS assures that VOC emissions are in compliance withthe VOC limit.

The Permittee shall demonstrate this correlation by recording and comparing CO CEMS emissions data duringSTRU 20 VOC performance testing, with results of the VOC testing. The correlation shall be valid only if testingdemonstrates that VOC emissions comply with the applicable VOC limit at the same time that CO emissions(measured by the CO CEMS) comply with the applicable CO limit, and the CO CEMS certification testing hasbeen satisfactorily completed.

40 CFR 75.10, Minn. R. 7017.1006,Title I Condition: 40 CFR52.21(j)(BACT) & Minn. R. 7007.3000


40 CFR 75.10, Minn. R. 7007.0800,subp. 4, Minn. R. 7011.7000, Minn. R.7017.1006, Title I Condition: 40 CFR52.21(j)(BACT) & Minn. R. 7007.3000,Title I Condition: Avoid major sourceunder 40 CFR 63.2

40 CFR 75.21

Minn. R. 7017.1090, subp. 1

40 CFR 64.3(d), Minn. R. 7017.0200

40 CFR 64.3(a), 40 CFR 64.6(b), Minn.R. 7017.0200




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41

Documentation of Need for Improved VOC Monitoring: If the Permittee fails to achieve compliance with the VOCemission limit when the CO CEMS did not provide an indication of a VOC emissions excursion or exceedancewhile the CO CEMS provided valid CO emissions data, or the results of VOC performance testing document aneed to modify the existing CO indicator of VOC emissions compliance, the Permittee shall promptly notify theMPCA and, if necessary, submit a permit amendment application to address the necessary monitoring changes.

42Recordkeeping: The Permittee must retain records of all CEMS monitoring data and support information for aperiod of five years from the date of the monitoring sample, measurement or report. Records shall be kept at thesource.

43

The Permittee shall limit Nitrogen Oxides <= 15 parts per million 30-day rolling average by volume at 15 percentO2 or 54 ng/J of useful output (0.43 lb/MWh) while combusting natural gas when the turbine is operating at orabove 75 percent of peak load and when operating at ambient temperatures of 0 degrees F or above. This limitapplies to EQUI 16 and EQUI 17.

44

The Permittee shall limit Nitrogen Oxides <= 96 parts per million 30-day rolling average by volume at 15 percentO2 or 590 ng/J of useful output (4.70 lb/MWh) while combusting natural gas and the turbine is operating at lessthan 75 percent of peak load or operating at ambient temperatures less than 0 degrees F. This limit applies toEQUI 16 and EQUI 17.

45 The Permittee shall limit Sulfur Dioxide <= 0.060 pounds per million Btu heat input (26 ng SO2/J).

46The Permittee must operate and maintain EQUI 16, EQUI 17, air pollution control equipment, and monitoringequipment in a manner consistent with good air pollution control practices for minimizing emissions at all timesincluding during startup, shutdown, and malfunction.

47

The Permittee shall either:

(1) Determine compliance with the applicable NOx emissions limits by measuring the emissions combined withthe emissions from the other unit(s) utilizing the common heat recovery unit; or(2) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioningthe combined gross energy output from the heat recovery unit for each of the affected combustion turbines. TheAdministrator may approve such demonstrated substitute methods for apportioning the combined gross energyoutput measured at the steam turbine whenever the demonstration ensures accurate estimation of emissionsrelated under this part.

40 CFR 64.7(e), Minn. R. 7017.0200

40 CFR 75.57, Minn. R. 7017.1130

40 CFR 60.4320(a), 40 CFR pt. 60,subp. KKKK(Table 1)

40 CFR 60.4320(a), 40 CFR pt. 60,subp. KKKK(Table 1)

40 CFR 60.4330(a)(2)

40 CFR 60.4333(a)

40 CFR 60.4333(b)




p

50

Each NOx diluent CEMS must be installed and certified according to Performance Specification 2 (PS 2) in 40CFR pt. 60, appendix B, except the 7-day calibration drift is based on unit operating days, not calendar days.With state approval, Procedure 1 in 40 CFR pt. 60, appendix F is not required. Alternatively, a NOx diluentCEMS that is installed and certified according to 40 CFR pt. 75, appendix A is acceptable for use under 40 CFRpt. 60, subp. KKKK. The relative accuracy test audit (RATA) of the CEMS shall be performed on a lb/MMBtubasis.

51

As specified in 40 CFR Section 60.13(e)(2), during each full unit operating hour, both the NOx monitor and thediluent monitor must complete a minimum of one cycle of operation (sampling, analyzing, and data recording) foreach 15-minute quadrant of the hour, to validate the hour. For partial unit operating hours, at least one valid datapoint must be obtained with each monitor for each quadrant of the hour in which the unit operates. For unitoperating hours in which required quality assurance and maintenance activities are performed on the CEMS, aminimum of two valid data points (one in each of two quadrants) are required for each monitor to validate theNOx emission rate for the hour.

52Each fuel flowmeter shall be installed, calibrated, maintained, and operated according to the manufacturer'sinstructions. Alternatively, with state approval, fuel flowmeters that meet the installation, certification, and qualityassurance requirements of 40 CFR pt. 75, appendix D are acceptable for use under 40 CFR pt. 60, subp. KKKK.

53 Each watt meter, steam flow meter, and each pressure or temperature measurement device shall be installed,calibrated, maintained, and operated according to manufacturer's instructions.

54

The Permittee shall develop and keep on-site a quality assurance (QA) plan for all of the continuous monitoringequipment described in 40 CFR Section 60.4345(a), (c), and (d). For the CEMS and fuel flow meters, thePermittee may, with state approval, satisfy the requirements of 40 CFR Section 60.4345(e) by implementing theQA program and plan described in 40 CFR pt. 75, appendix B, section 1.

55 All CEMS data must be reduced to hourly averages as specified in 40 CFR Section 60.13(h).

56

For each unit operating hour in which a valid hourly average, as described in 40 CFR Section 60.4345(b), isobtained for both NOx and diluent monitors, the data acquisition and handling system must calculate and recordthe hourly NOx emission rate in units of ppm or lb/MMBtu, using the appropriate equation from method 19 in 40CFR pt. 60, appendix A. For any hour in which the hourly average O2 concentration exceeds 19.0 percent O2(or the hourly average CO2 concentration is less than 1.0 percent CO2), a diluent cap value of 19.0 percent O2or 1.0 percent CO2 (as applicable) may be used in the emission calculations.

40 CFR 60.4345(a)

40 CFR 60.4345(b)

40 CFR 60.4345(c)

40 CFR 60.4345(d)

40 CFR 60.4345(e)

40 CFR 60.4350(a)

40 CFR 60.4350(b)




p ( pp ) y

57 Correction of measured NOx concentrations to 15 percent O2 is not allowed.

58

If the Permittee has installed and certified a NOx diluent CEMS to meet the requirements of 40 CFR pt. 75,states can approve that only quality assured data from the CEMS shall be used to identify excess emissionsunder 40 CFR pt. 60, subp. KKKK. Periods where the missing data substitution procedures in 40 CFR pt. 75,subpart D are applied are to be reported as monitor downtime in the excess emissions and monitoringperformance report required under 40 CFR Section 60.7(c).

59 All required fuel flow rate, steam flow rate, temperature, pressure, and megawatt data must be reduced to hourlyaverages.

60 Calculate the hourly average NOx emission rates, in units of the emission standards under 40 CFR Section60.4320, using ppm for units complying with the concentration limit.

62

The Permittee must monitor the total sulfur content of the fuel being fired in the turbine, except as provided in 40CFR Section 60.4365. The sulfur content of the fuel must be determined using total sulfur methods described in40 CFR Section 60.4415 or 40 CFR pt. 75. Alternatively, if the total sulfur content of the gaseous fuel during themost recent performance test was less than half the applicable limit, ASTM D4084, D4810, D5504, or D6228, orGas Processors Association Standard 2377 (all of which are incorporated by reference, see 40 CFR Section60.17), which measure the major sulfur compounds, may be used.

63

The Permittee may elect not to monitor the total sulfur content of the fuel combusted in the turbine, if the fuel isdemonstrated not to exceed potential sulfur emissions of 26 ng SO2/J (0.060 lb SO2/MMBtu) heat input for unitslocated in continental areas. The Permittee must use one of the following sources of information to make therequired demonstration:

(a) The fuel quality characteristics in a current, valid purchase contract, tariff sheet or transportation contract forthe fuel, specifying that the total sulfur content for natural gas use in continental areas is 20 grains of sulfur orless per 100 standard cubic feet, has potential sulfur emissions of less than less than 26 ng SO2/J (0.060 lbSO2/MMBtu) heat input for continental areas; or(b) Representative fuel sampling data which show that the sulfur content of the fuel does not exceed 26 ngSO2/J (0.060 lb SO2/MMBtu) heat input for continental areas. At a minimum, the amount of fuel sampling data ..

64

The frequency of determining the sulfur content of the fuel must be as follows:

(b) Gaseous fuel. If the Permittee elects not to demonstrate sulfur content using options in 40 CFR Section60.4365, and the fuel is supplied without intermediate bulk storage, the sulfur content value of the gaseous fuelmust be determined and recorded once per unit operating day.

(c) Custom schedules. Notwithstanding the requirements of 40 CFR Section 60.4370(b), operators or fuelvendors may develop custom schedules for determination of the total sulfur content of gaseous fuels, based onthe design and operation of the affected facility and the characteristics of the fuel supply. Except as provided in40 CFR Section 60.4370(c)(1) and (c)(2), custom schedules shall be substantiated with data and shall beapproved by the Administrator before they can be used to comply with the standard in 40 CFR Section 60.4330..

40 CFR 60.4350(c)

40 CFR 60.4350(d)

40 CFR 60.4350(e)

40 CFR 60.4350(f)

40 CFR 60.4360

40 CFR 60.4365

40 CFR 60.4370(b) - (c)(1)




65

(continued from above)(2) The Permittee may use the data collected from the 720-hour sulfur sampling demonstration described insection 2.3.6 of 40 CFR pt. 75, appendix D to determine a custom sulfur sampling schedule, as follows:

(i) If the maximum fuel sulfur content obtained from the 720 hourly samples does not exceed 20 grains/100 scf,no additional monitoring of the sulfur content of the gas is required, for the purposes of 40 CFR pt. 60, subp.KKKK.(ii) If the maximum fuel sulfur content obtained from any of the 720 hourly samples exceeds 20 grains/100 scf,but none of the sulfur content values (when converted to weight percent sulfur) exceeds half the applicable limit,then the minimum required sampling frequency shall be one sample at 12 month intervals.(iii) If any sample result exceeds half the applicable limit, but none exceeds the applicable limit, follow the provi..

66The Permittee must submit reports of excess emissions and monitor downtime, in accordance with 40 CFRSection 60.7(c). Excess emissions must be reported for all periods of unit operation, including start-up,shutdown, and malfunction.

67

For turbines using continuous emission monitoring, as described in 40 CFR Sections 60.4335(b) and 60.4345:An excess emissions is any unit operating period in which the 4-hour or 30-day rolling average NOx emissionrate exceeds the applicable emission limit in 40 CFR Section 60.4320. For the purposes of 40 CFR pt. 60, subp.KKKK, a 4-hour rolling average NOx emission rate is the arithmetic average of the average NOx emission rate inppm or ng/J (lb/MWh) measured by the continuous emission monitoring equipment for a given hour and thethree unit operating hour average NOx emission rates immediately preceding that unit operating hour. Calculatethe rolling average if a valid NOx emission rate is obtained for at least 3 of the 4 hours. For the purposes of 40CFR pt. 60, subp. KKKK, a 30-day rolling average NOx emission rate is the arithmetic average of all hourly NOxemission data in ppm or ng/J (lb/MWh) measured by the continuous emission monitoring equipment for a givenday and the twenty-nine unit operating days immediately preceding that unit operating day. A new 30-dayaverage is calculated each unit operating day as the average of all hourly NOx emissions rates for the precedin..

68

A period of monitor downtime is any unit operating hour in which the data for any of the following parameters areeither missing or invalid: NOx concentration, CO2 or O2 concentration, fuel flow rate, steam flow rate, steamtemperature, steam pressure, or megawatts. The steam flow rate, steam temperature, and steam pressure areonly required if the Permittee will use this information for compliance purposes.

69For operating periods during which multiple emissions standards apply, the applicable standard is the averageof the applicable standards during each hour. For hours with multiple emissions standards, the applicable limitfor that hour is determined based on the condition that corresponded to the highest emissions standard.

70

For turbines required to monitor combustion parameters or parameters that document proper operation of theNOx emission controls:An excess emission is a 4-hour rolling unit operating hour average in which any monitored parameter does notachieve the target value or is outside the acceptable range defined in the parameter monitoring plan for the unit.

71 A period of monitor downtime is a unit operating hour in which any of the required parametric data are either notrecorded or are invalid.

40 CFR 60.4370(c)(2)

40 CFR 60.4375(a)

40 CFR 60.4380(b)(1)

40 CFR 60.4380(b)(2)

40 CFR 60.4380(b)(3)

40 CFR 60.4380(c)(1)

40 CFR 60.4380(c)(2)




72

For samples of gaseous fuel obtained using daily sampling or flow proportional sampling, an excess emissionoccurs each unit operating hour included in the period beginning on the date and hour of any sample for whichthe sulfur content of the fuel being fired in the combustion turbine exceeds the applicable limit and ending on thedate and hour that a subsequent sample is taken that demonstrates compliance with the sulfur limit.

73A period of monitor downtime begins when a required sample is not taken by its due date. A period of monitordowntime also begins on the date and hour of a required sample, if invalid results are obtained. The period ofmonitor downtime ends on the date and hour of the next valid sample.

74 The Permittee shall submit a report : Due semiannually and each report must be postmarked by the 30th dayfollowing the end of each 6-month period as required under 40 CFR Section 60.7(c).

75Perform a minimum of nine RATA reference method runs, with a minimum time per run of 21 minutes, at asingle load level, within plus or minus 25 percent of 100 percent of peak load. The ambient temperature must begreater than 0 degrees F during the RATA runs.

76 For each RATA run, concurrently measure the heat input to the unit using a fuel flow meter (or flow meters) andmeasure the electrical and thermal output from the unit.

77Use the test data both to demonstrate compliance with the applicable NOx emission limit under 40 CFR Section60.4320 and to provide the required reference method data for the RATA of the CEMS described under 40 CFRSection 60.4335.

78Compliance with the applicable emission limit in 40 CFR Section 60.4320 is achieved if the arithmetic average ofall of the NOx emission rates for the RATA runs, expressed in units of ppm or lb/MWh, does not exceed theemission limit.

40 CFR 60.4385(a)

40 CFR 60.4385(c)

40 CFR 60.4395

40 CFR 60.4405(a)

40 CFR 60.4405(b)

40 CFR 60.4405(c)

40 CFR 60.4405(d)




79

When monitoring combustion parameters in accordance with 40 CFR Section 60.4340, the appropriateparameters must be continuously monitored and recorded during each run of the initial performance test, toestablish acceptable operating ranges, for purposes of the parameter monitoring plan for the affected unit, asspecified in 40 CFR Section 60.4355.

80

The Permittee must conduct an initial performance test, as required in 40 CFR Section 60.8. Subsequent SO2performance tests shall be conducted on an annual basis (no more than 14 calendar months following theprevious performance test). There are three methodologies that the Permittee may use to conduct theperformance tests.

(1) If the Permittee chooses to periodically determine the sulfur content of the fuel combusted in the turbine, arepresentative fuel sample would be collected following ASTM D5287 (incorporated by reference, see 40 CFRSection 60.17) for natural gas. The fuel analyses of this section may be performed either by the Permittee, aservice contractor retained by the Permittee, the fuel vendor, or any other qualified agency. Analyze the samplesfor the total sulfur content of the fuel using:..

81

Use methods in 40 CFR pt. 98, subp. C including flow monitoring of fuel usage and fuel gas analysis. Calculateemissions following procedures specified in 40 CFR pt. 98, subp. C with a conversion from metric tons to shorttons. The Permittee shall calculate and record the 12-month rolling average of gross energy output (net) ofCO2e emissions by the 15th day of each month for the 12-month rolling average periods ending on the last dayof the preceding month.

82

Except as specified in 40 CFR Section 60.5520(c) and (d), the Permittee must comply with the applicable grossenergy output standard, and the operating permit must include monitoring, recordkeeping, and reportingmethodologies based on the applicable gross energy output standard. For the remainder of this subpart (forsources that do not qualify under 40 CFR Section 60.5520(c) and (d)), where the term “gross or net energyoutput” is used, the term that applies is “gross energy output.”.

83For each affected EGU subject to a CO2 emissions standard based on a 12-operating-month rolling average,the Permittee must determine compliance monthly by calculating the average CO2 emissions rate for theaffected EGU at the end of the initial and each subsequent 12-operating-month period.

84

At all times the Permittee must operate and maintain each affected EGU, including associated equipment andmonitors, in a manner consistent with safety and good air pollution control practice. The Administrator willdetermine if the Permittee is using consistent operation and maintenance procedures based on informationavailable to the Administrator that may include, but is not limited to, fuel use records, monitoring results, reviewof operation and maintenance procedures and records, review of reports required by 40 CFR pt. 60, subp.TTTT, and inspection of the EGU.

85

Within 30 days after the end of the initial compliance period (i.e., no more than 30 days after the first12-operating-month compliance period), the Permittee must make an initial compliance determination for theaffected EGU(s) with respect to the applicable emissions standard in 40 CFR pt. 60, subp. TTTT table 1 or 2, inaccordance with the requirements in this subpart. The first operating month included in the initial12-operating-month compliance period shall be determined as follows:

(1) For an affected EGU that commences commercial operation (as defined in 40 CFR Section 72.2) on or afterOctober 23, 2015, the first month of the initial compliance period shall be the first operating month (as defined in40 CFR Section 60.5580) after the calendar month in which emissions reporting is required to begin under 40CFR Section 63.5555(c)(3)(i), for units subject to the Acid Rain Program.

40 CFR 60.4410

40 CFR 60.4415(a)(1) - (3)

40 CFR 60.5520(a), 40 CFR pt. 60,subp. TTTT(Table 2), 40 CFR pt. 98,subp. C, Title I Condition: 40 CFR52.21(j)(BACT) & Minn. R. 7007.3000

40 CFR 60.5520(b)

40 CFR 60.5525(a)(1)

40 CFR 60.5525(b)

40 CFR 60.5525(c)(1)(i)




( )( )( ) j g

86

The Permittee must prepare a monitoring plan to quantify the hourly CO2 mass emission rate (tons/h), inaccordance with the applicable provisions in 40 CFR Section 75.53(g) and (h). The electronic portion of themonitoring plan must be submitted using the ECMPS Client Tool and must be in place prior to reportingemissions data and/or the results of monitoring system certification tests under 40 CFR pt. 60, subp. TTTT. Themonitoring plan must be updated as necessary. Monitoring plan submittals must be made by the DesignatedRepresentative (DR), the Alternate DR, or a delegated agent of the DR (see 40 CFR Section 60.5555(c)).

87

The Permittee may determine the hourly CO2 mass emissions according to 40 CFR Section 60.5535(c)(1)through (4).

(1) The Permittee must implement the applicable procedures in 40 CFR pt. 75, appendix D to determine hourlyEGU heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations ofthe gross calorific value (GCV) of each fuel combusted.

(2) For each measured hourly heat input rate, use Equation G-4 in 40 CFR pt. 75, appendix G to calculate thehourly CO2 mass emission rate (tons/h). The Permittee may determine site-specific carbon-based F-factors (Fc)using Equation F-7b in 40 CFR pt. 75, appendix F section 3.3.6, and the Permittee may use these Fc values inthe emissions calculations instead of using the default Fc values in the Equation G-4 nomenclature...

88

The Permittee must install, calibrate, maintain, and operate a sufficient number of watt meters to continuouslymeasure and record the hourly gross electric output, as applicable, from the affected EGU(s). Thesemeasurements must be performed using 0.2 class electricity metering instrumentation and calibrationprocedures as specified under ANSI Standards No. C12.20 (incorporated by reference, see 40 CFR Section60.17). The plan shall ensure that you install, calibrate, maintain, and operate meters to record each componentof the determination, hour-by-hour.

89

For the initial and each subsequent 12-operating-month rolling average compliance period, the Permittee mustfollow the procedures in 40 CFR Section 60.5540(a)(1) through (7) to calculate the CO2 mass emissions rate forthe affected EGU(s) in units of the applicable emissions standard (i.e., either kg/MWh or lb/MMBtu). ThePermittee must use the hourly CO2 mass emissions calculated under 40 CFR Section 60.5535(b) or (c), asapplicable, and either the generating load data from 40 CFR Section 60.5535(d)(1) for output-basedcalculations.

(1) Each compliance period shall include only "valid operating hours" in the compliance period, i.e., operatinghours for which:

(i) "Valid data" (as defined in 40 CFR Section 60.5580) are obtained for all of the parameters used to determine..

90

(continued from above)Pgross/net = [(Pe)ST + (Pe)CT + (Pe)IE - (Pe)FW - (Pe)A]/TDF + [(Pt)PS + (Pt)HR + (Pt)IE]

Where:

Pgross/net = In accordance with 40 CFR Section 60.5520, gross or net energy output of the affected EGU foreach valid operating hour (as defined in 40 CFR Section 60.5540(a)(1)) in MWh.

(Pe)ST = Electric energy output plus mechanical energy output (if any) of steam turbines in MWh.

(Pe)CT = Electric energy output plus mechanical energy output (if any) of stationary combustion turbine(s) in M..

91

In accordance with 40 CFR Section 60.5520, to demonstrate compliance with the applicable CO2 emissionstandard, for the initial and each subsequent 12-operating-month compliance period, the CO2 mass emissionsrate for the affected EGU must be determined according to the procedures specified in 40 CFR Section60.5540(a)(1) through (7) and must be less than or equal to the applicable CO2 emissions standard in 40 CFRpt. 60, subp. TTTT table 1 or 2, or the emissions standard calculated in accordance with 40 CFR Section60.5525(a)(2).

92 The Permittee must prepare and submit the notifications specified in 40 CFR Section 60.7(a)(1) and (a)(3) and40 CFR Section 60.19, as applicable to the affected EGU(s) (see 40 CFR pt. 60, subp. TTTT table 3).

40 CFR 60.5535(a)

40 CFR 60.5535(c)(1) - (4)

40 CFR 60.5535(d)(1)

40 CFR 60.5540(a)(1) - (5)

40 CFR 60.5540(a)(5) - (7)

40 CFR 60.5540(b)

40 CFR 60.5550(a)




pp ( ) ( p p )

93 The Permittee must prepare and submit notifications specified in 40 CFR Section 75.61, as applicable to theaffected EGU(s).

94

The Permittee shall submit a report : Due by the end of each calendar quarter after accumulating the first12-operating months for the affected EGU, for the calendar quarter that includes the twelfth operating month nolater than 30 days after the end of that quarter. Thereafter, the Permittee must submit a report for eachsubsequent calendar quarter, no later than 30 days after the end of the quarter.

95

In each quarterly report the Permittee must include the following information, as applicable:

(i) Each rolling average CO2 mass emissions rate for which the last (twelfth) operating month in a12-operating-month compliance period falls within the calendar quarter. The Permittee must calculate eachaverage CO2 mass emissions rate for the compliance period according to the procedures in 40 CFR Section60.5540. The Permittee must report the dates (month and year) of the first and twelfth operating months in eachcompliance period for which the Permittee performed a CO2 mass emissions rate calculation. If there are nocompliance periods that end in the quarter, the Permittee must include a statement to that effect;(ii) If one or more compliance periods end in the quarter, the Permittee must identify each operating month in thecalendar quarter where the EGU violated the applicable CO2 emission standard;(iii) If one or more compliance periods end in the quarter and there are no violations for the affected EGU, the P..

96

In the final quarterly report of each calendar year, the Permittee must include the following:

(i) Consistent with 40 CFR Section 60.5520, gross energy output or net energy output sold to an electric grid, asapplicable to the units of your emission standard, over the four quarters of the calendar year; and(ii) The potential electric output of the EGU.

97The Permittee must submit all electronic reports required under 40 CFR Section 60.5555(a) using the EmissionsCollection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in theOffice of Atmospheric Programs of EPA.

98 The Permittee must meet all applicable reporting requirements and submit reports as required under 40 CFR pt.75, subpart G.

99

The Permittee must begin submitting the quarterly electronic emissions reports described in 40 CFR Section60.5555(c)(1) in accordance with 40 CFR Section 75.64(a), i.e., beginning with data recorded on and after theearlier of:

(A) The date of provisional certification, as defined in 40 CFR Section 75.20(a)(3); or(B) 180 days after the date on which the EGU commences commercial operation (as defined in 40 CFR Section72.2).

40 CFR 60.5550(b)

40 CFR 60.5555(a)(1)

40 CFR 60.5555(a)(2)(i) - (vi)

40 CFR 60.5555(a)(3)(i) - (ii)

40 CFR 60.5555(b)

40 CFR 60.5555(c)(1)

40 CFR 60.5555(c)(3)(i)(A) - (B)




)

100

The reports required under 40 CFR Section 60.5555(a) and (c)(1) shall be submitted by:

(1) The person appointed as the Designated Representative (DR) under 40 CFR Section 72.20; or(2) The person appointed as the Alternate Designated Representative (ADR) under 40 CFR Section 72.22; or(3) A person (or persons) authorized by the DR or ADR under 40 CFR Section 72.26 to make the requiredsubmissions.

101

The Permittee must maintain records of the information used to demonstrate compliance with 40 CFR pt. 60,subp. TTTT as specified in 40 CFR Section 60.7(b) and (f).

(b)(1) The Permittee must follow the applicable recordkeeping requirements and maintain records as requiredunder 40 CFR pt. 75, subpart F.(f) The Permittee must keep records of the calculations performed to assess compliance with each applicableCO2 mass emissions standard in 40 CFR pt. 60, subp. TTTT Table 1 or 2.

102Consistent with 40 CFR Section 60.5520, the Permittee must keep records of the applicable data recorded andcalculations performed that were used to determine the affected EGU's gross or net energy output for eachoperating month.

103 The Permittee must keep records of the calculations performed to determine the percentage of valid CO2 massemission rates in each compliance period.

104 Records must be in a form suitable and readily available for expeditious review.

105 The Permittee must maintain each record for 3 years after the date of conclusion of each compliance period.

106

The Permittee must maintain each record on site for at least 2 years after the date of each occurrence,measurement, maintenance, corrective action, report, or record, according to 40 CFR Section 60.7. Records thatare accessible from a central location by a computer or other means that instantly provide access at the sitemeet this requirement. The Permittee may maintain the records off site for the remaining year(s) as required by40 CFR pt. 60, subp. TTTT.

40 CFR 60.5555(d)(1) - (3)

40 CFR 60.5560(a)(b)(1) & (f)

40 CFR 60.5560(d)

40 CFR 60.5560(e)

40 CFR 60.5565(a)

40 CFR 60.5565(b)

40 CFR 60.5565(c)




p p

107 Notwithstanding any other provision of this chapter, certain parts of the general provisions in 40 CFR Sections60.1 through 60.19, listed in 40 CFR pt. 60, subp. TTTT table 3, do not apply to the affected EGU.

108

Except as provided in subparts B and C, the provisions of this part apply to the owner or operator of anystationary source which contains an affected facility, the construction or modification of which is commencedafter the date of publication in this part of any standard (or, if earlier, the date of publication of any proposedstandard) applicable to that facility.

109

Any new or revised standard of performance promulgated pursuant to section 111(b) of the Act shall apply to theowner or operator of any stationary source which contains an affected facility, the construction or modification ofwhich is commenced after the date of publication in this part of such new or revised standard (or, if earlier, thedate of publication of any proposed standard) applicable to that facility.

110

In addition to complying with the provisions of this part, the owner or operator of an affected facility may berequired to obtain an operating permit issued to stationary sources by an authorized State air pollution controlagency or by the Administrator of the U.S. Environmental Protection Agency (EPA) pursuant to Title V of theClean Air Act (Act) as amended November 15, 1990 (42 U.S.C. 7661). For more information about obtaining anoperating permit see 40 CFR pt. 70.

111

The Permittee shall submit a notification of the date construction began : Due 30 calendar days after Date ofConstruction Start (or reconstruction as defined under 40 CFR Section 60.15) of an affected facility. Thenotification shall be postmarked no later than 30 days after such date. This requirement shall not apply in thecase of mass-produced facilities which are purchased in completed form.

112 The Permittee shall submit a notification of the actual date of initial startup : Due 15 calendar days after InitialStartup Date.

113

The Permittee shall submit a notification of any physical or operational change to an existing facility which mayincrease the emission rate of any air pollutant to which a standard applies, unless that change is specificallyexempted under an applicable subpart or in 40 CFR Section 60.14(e). This notice shall be postmarked 60 daysor as soon as practicable before the change is commenced and shall include information describing the precisenature of the change, present and proposed emission control systems, productive capacity of the facility beforeand after the change, and the expected completion date of the change. The Administrator may requestadditional relevant information subsequent to this notice.

40 CFR 60.5570

40 CFR 60.1(a), Minn. R. 7011.0050

40 CFR 60.1(b), Minn. R. 7011.0050

40 CFR 60.1(c), Minn. R. 7011.0050

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

40 CFR 60.7(a)(3), Minn. R.7019.0100, subp. 1

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




q

114 The Permittee shall submit a notification : Due 30 calendar days before Initial Startup Date of the continuousmonitoring system (CMS) in accordance with 40 CFR Section 60.13(c).

116The Permittee shall submit a notification : Due 30 calendar days before Opacity Observation Date required by40 CFR Section 60.11(e)(1). The notification shall also include, if appropriate, a request for the Administrator toprovide a visible emissions reader during a performance test.

117Recordkeeping: The Permittee shall maintain records of the occurrence and duration of any startup, shutdown,or malfunction in the operation of an affected facility; any malfunction of the air pollution control equipment; orany periods during which a continuous monitoring system or monitoring device is inoperative.

118

The Permittee shall submit excess emission/downtime report : Due by the end of each calendar half-year,except when: more frequent reporting is specifically required by an applicable subpart; or the Administrator, on acase-by-case basis, determines that more frequent reporting is necessary to accurately assess the compliancestatus of the source. All reports shall be postmarked by the 30th day following the end of each six-month periodand include the information in 40 CFR Section 60.7(c)(1) through (4).

119

The summary report form shall contain the information and be in the format shown in figure 1 of 40 CFR Section60.7 unless otherwise specified by the Administrator. One summary report form shall be submitted for eachpollutant monitored at each affected facility.

(1) If the total duration of excess emissions for the reporting period is less than 1 percent of the total operatingtime for the reporting period and CMS downtime for the reporting period is less than 5 percent of the totaloperating time for the reporting period, only the summary report form shall be submitted and the excessemission report described in 40 CFR Section 60.7(c) need not be submitted unless requested by theAdministrator.(2) If the total duration of excess emissions for the reporting period is 1 percent or greater of the total operatingtime for the reporting period or the total CMS downtime for the reporting period is 5 percent or greater of the tot..

120

Notwithstanding the frequency of reporting requirements specified in 40 CFR Section 60.7(c), a Permittee who isrequired by an applicable subpart to submit excess emissions and monitoring systems performance reports (andsummary reports) on a quarterly (or more frequent) basis may reduce the frequency of reporting for thatstandard to semiannual if the following conditions are met:

(i) For 1 full year (e.g., 4 quarterly or 12 monthly reporting periods) the affected facility's excess emissions andmonitoring systems reports submitted to comply with a standard under this part continually demonstrate that thefacility is in compliance with the applicable standard;(ii) The Permittee continues to comply with all recordkeeping and monitoring requirements specified in thissubpart and the applicable standard; and(iii) The Administrator does not object to a reduced frequency of reporting for the affected facility, as provided in..

121

The frequency of reporting of excess emissions and monitoring systems performance (and summary) reportsmay be reduced only after the Permittee notifies the Administrator in writing of his or her intention to make sucha change and the Administrator does not object to the intended change. In deciding whether to approve areduced frequency of reporting, the Administrator may review information concerning the source's entireprevious performance history during the required recordkeeping period prior to the intended change, includingperformance test results, monitoring data, and evaluations of a Permittee's conformance with operation andmaintenance requirements. Such information may be used by the Administrator to make a judgment about thesource's potential for noncompliance in the future. If the Administrator disapproves the Permittee's request toreduce the frequency of reporting, the Administrator will notify the Permittee in writing within 45 days afterreceiving notice of the Permittee's intention. The notification from the Administrator to the Permittee will specifythe grounds on which the disapproval is based. In the absence of a notice of disapproval within 45 days, appro..

40 CFR 60.13(c), 40 CFR 60.7(a)(5),Minn. R. 7019.0100, subp. 1

40 CFR 60.7(a)(6), Minn. R.7019.0100, subp. 1

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

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

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

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

40 CFR 60.7(e)(2), Minn. R.7019.0100, subp. 1




122

As soon as monitoring data indicate that the affected facility is not in compliance with any emission limitation oroperating parameter specified in the applicable standard, the frequency of reporting shall revert to the frequencyspecified in the applicable standard, and the Permittee shall submit an excess emissions and monitoringsystems performance report (and summary report, if required) at the next appropriate reporting period followingthe noncomplying event. After demonstrating compliance with the applicable standard for another full year, thePermittee may again request approval from the Administrator to reduce the frequency of reporting for thatstandard as provided for in 40 CFR Section 60.7(e)(1) and (e)(2).

123 Recordkeeping: Maintain a file of all measurements, maintenance, reports and records for at least five years. 40CFR Section 60.7(f) specifies two years.

124If notification substantially similar to that in 40 CFR Section 60.7(a) is required by any other State or localagency, sending the Administrator a copy of that notification will satisfy the requirements of 40 CFR Section60.7(a).

125 Individual subparts of this part may include specific provisions which clarify or make inapplicable the provisionsset forth in this section.

126

The availability to the public of information provided to, or otherwise obtained by, the Administrator under thispart shall be governed by 40 CFR pt. 2. (Information submitted voluntarily to the Administrator for the purposesof 40 CFR Sections 60.5 and 60.6 is governed by 40 CFR Sections 2.201 through 2.213 and not by 40 CFRSection 2.301.).

127

The provisions of this part shall not be construed in any manner to preclude any State or political subdivisionthereof from:

(a) Adopting and enforcing any emission standard or limitation applicable to an affected facility, provided thatsuch emission standard or limitation is not less stringent than the standard applicable to such facility.(b) Requiring the Permittee to obtain permits, licenses, or approvals prior to initiating construction, modification,or operation of such facility.

128 Compliance with standards in this part, other than opacity standards, shall be determined in accordance withperformance tests established by 40 CFR Section 60.8, unless otherwise specified in the applicable standard.

40 CFR 60.7(e)(3), Minn. R.7019.0100, subp. 1

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

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

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

40 CFR 60.9

40 CFR 60.10

40 CFR 60.11(a), Minn. R. 7017.2015




p y p pp

129

Compliance with opacity standards in this part shall be determined by conducting observations in accordancewith Method 9 in 40 CFR pt. 60, appendix A, any alternative method that is approved by the Administrator, or asprovided in 40 CFR Section 60.11(e)(5). For purposes of determining initial compliance, the minimum total timeof observations shall be 3 hours (30 6-minute averages) for the performance test or other set of observations(meaning those fugitive-type emission sources subject only to an opacity standard).

130 The opacity standards set forth in this part shall apply at all times except during periods of startup, shutdown,malfunction, and as otherwise provided in the applicable standard.

131

At all times, including periods of startup, shutdown, and malfunction, the Permittee shall, to the extentpracticable, maintain and operate any affected facility including associated air pollution control equipment in amanner consistent with good air pollution control practice for minimizing emissions. Determination of whetheracceptable operating and maintenance procedures are being used will be based on information available to theAdministrator which may include, but is not limited to, monitoring results, opacity observations, review ofoperating and maintenance procedures, and inspection of the source.

132For the purpose of demonstrating initial compliance, conduct opacity observations concurrently with the initialperformance test required in 40 CFR Section 60.8 and include the results in the test report, pursuant to theconditions described in 40 CFR Section 60.11(e)(1)-(8).

133 Special provisions set forth under an applicable subpart shall supersede any conflicting provisions in 40 CFRSection 60.11(a) through (e).

134

For the purpose of submitting compliance certifications or establishing whether or not a person has violated or isin violation of any standard in this part, nothing in this part shall preclude the use, including the exclusive use, ofany credible evidence or information, relevant to whether a source would have been in compliance withapplicable requirements if the appropriate performance or compliance test or procedure had been performed.

135 No 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.

40 CFR 60.11(b), Minn. R. 7017.2015

40 CFR 60.11(c), Minn. R. 7017.2015

40 CFR 60.11(d), Minn. R. 7017.2015

40 CFR 60.11(e), Minn. R. 7017.2015

40 CFR 60.11(f), Minn. R. 7017.2015

40 CFR 60.11(g), Minn. R. 7017.2015

40 CFR 60.12, Minn. R. 7011.0050




pp

136


137 All continuous monitoring systems and monitoring devices required under 40 CFR 60, including CEMS andCOMS shall be installed and operational prior to conducting performance tests under 40 CFR Section 60.8.

138

The Permittee shall conduct a performance evaluation of the CEMS during any performance test required under40 CFR Section 60.8 or within 30 days thereafter in accordance with the applicable performance specification in40 CFR pt. 60, appendix B. The Permittee shall conduct CEMS performance evaluations at such other times asmay be required by the Administrator under section 114 of the Act.

140

The Permittee must check the zero (or low level value between 0 and 20 percent of span value) and span (50 to100 percent of span value) calibration drifts at least once each operating day in accordance with a writtenprocedure. The zero and span must, at a minimum, be adjusted whenever either the 24-hour zero drift or the24-hour span drift exceeds two times the limit of the applicable performance specification in 40 CFR pt. 60,appendix B. The system must allow the amount of the excess zero and span drift to be recorded and quantifiedwhenever specified. The Permittee must check the zero and upscale (span) calibration drifts at least once daily.For a particular COMS, the acceptable range of zero and upscale calibration materials is defined in theapplicable version of PS-1 in 40 CFR pt. 60, appendix B. For a COMS, the optical surfaces, exposed to theeffluent gases, must be cleaned before performing the zero and upscale drift adjustments, except for systemsusing automatic zero adjustments. The optical surfaces must be cleaned when the cumulative automatic zerocompensation exceeds 4 percent opacity.

141

Except for system breakdowns, repairs, calibration checks, and zero and span adjustments required under 40CFR Section 60.13(d), all continuous monitoring systems shall be in continuous operation and shall meetminimum frequency of operation requirements as follows:

All continuous monitoring systems referenced by 40 CFR Section 60.13(c) for measuring emissions, exceptopacity, shall complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for eachsuccessive 15-minute period.

142

All continuous monitoring systems or monitoring devices shall be installed such that representativemeasurements of emissions or process parameters from the affected facility are obtained. Additional proceduresfor location of continuous monitoring systems contained in the applicable Performance Specifications of 40 CFRpt. 60, appendix B shall be used.

143

When the effluents from a single affected facility or two or more affected facilities subject to the same emissionstandards are combined before being released to the atmosphere, the Permittee may install applicablecontinuous monitoring systems on each effluent or on the combined effluent. When the affected facilities are notsubject to the same emission standards, separate continuous monitoring systems shall be installed on eacheffluent. When the effluent from one affected facility is released to the atmosphere through more than one point,the Permittee shall install an applicable continuous monitoring system on each separate effluent unless theinstallation of fewer systems is approved by the Administrator. When more than one continuous monitoringsystem is used to measure the emissions from one affected facility (e.g., multiple breechings, multiple outlets),the Permittee shall report the results as required from each continuous monitoring system.

40 CFR 60.13(a), 40 CFR pt. 60,Appendix F, Minn. R. 7017.1010

40 CFR 60.13(b), Minn. R. 7017.1010

40 CFR 60.13(c), Minn. R. 7017.1010

40 CFR 60.13(d)(1), Minn. R.7017.1010

40 CFR 60.13(e), Minn. R. 7017.1010

40 CFR 60.13(f), Minn. R. 7017.1010

40 CFR 60.13(g), Minn. R. 7017.1010




p q g y

144

For continuous monitoring systems other than opacity, 1-hour averages shall be computed as specified in 40CFR Section 60.13(h)(2)(i) through (ix), except that the provisions pertaining to the validation of partial operatinghours are only applicable for affected facilities that are required by the applicable subpart to include partial hoursin the emission calculations.

145All excess emissions shall be converted into units of the standard using the applicable conversion proceduresspecified in the applicable subpart. After conversion into units of the standard, the data may be rounded to thesame number of significant digits used in the applicable subpart to specify the emission limit.

146After receipt and consideration of written application, the Administrator may approve alternatives to anymonitoring procedures or requirements of this part including, but not limited to the requirements listed at 40 CFRSection 60.13(i)(1) through (9).

147 An alternative to the relative accuracy (RA) test specified in Performance Specification 2 of 40 CFR pt. 60,appendix B may be requested as described in 40 CFR Section 60.13(j)(1) and (j)(2).

148

Except as provided under 40 CFR Section 60.14(e) and (f), any physical or operational change to an existingfacility which results in an increase in the emission rate to the atmosphere of any pollutant to which a standardapplies shall be considered a modification within the meaning of section 111 of the Act. Upon modification, anexisting facility shall become an affected facility for each pollutant to which a standard applies and for whichthere is an increase in the emission rate to the atmosphere.

150 The addition of an affected facility to a stationary source as an expansion to that source or as a replacement foran existing facility shall not by itself bring within the applicability of this part any other facility within that source.

151

The following shall not, by themselves, be considered modifications under this part:

(1) Maintenance, repair, and replacement which the Administrator determines to be routine for a sourcecategory, subject to the provisions of 40 CFR Section 60.14(c) and 40 CFR Section 60.15.(2) An increase in production rate of an existing facility, if that increase can be accomplished without a capitalexpenditure on that facility.(3) An increase in the hours of operation.(4) Use of an alternative fuel or raw material if, prior to the date any standard under this part becomes applicableto that source type, as provided by 40 CFR Section 60.1, the existing facility was designed to accommodate thatalternative use. A facility shall be considered to be designed to accommodate an alternative fuel or raw materialif that use could be accomplished under the facility's construction specifications as amended prior to the chang..

40 CFR 60.13(h)(2), Minn. R.7017.1010

40 CFR 60.13(h)(3), Minn. R.7017.1010

40 CFR 60.13(i), Minn. R. 7017.1010

40 CFR 60.13(j), Minn. R. 7017.1010

40 CFR 60.14(a), Minn. R. 7011.0050

40 CFR 60.14(c), Minn. R. 7011.0050

40 CFR 60.14(e), Minn. R. 7011.0050




152 Special provisions set forth under an applicable subpart of this part shall supersede any conflicting provisions ofthis section.

153 Within 180 days of the completion of any physical or operational change subject to the control measuresspecified in 40 CFR Section 60.14(a), compliance with all applicable standards must be achieved.

154

No physical change, or change in the method of operation, at an existing electric utility steam generating unitshall be treated as a modification for the purposes of this section provided that such change does not increasethe maximum hourly emissions of any pollutant regulated under this section above the maximum hourlyemissions achievable at that unit during the 5 years prior to the change.

155

Repowering projects that are awarded funding from the Department of Energy as permanent clean coaltechnology demonstration projects (or similar projects funded by EPA) are exempt from the requirements of thissection provided that such change does not increase the maximum hourly emissions of any pollutant regulatedunder this section above the maximum hourly emissions achievable at that unit during the five years prior to thechange.

156

Repowering projects that qualify for an extension under section 409(b) of the Clean Air Act are exempt from therequirements of this section, provided that such change does not increase the actual hourly emissions of anypollutant regulated under this section above the actual hourly emissions achievable at that unit during the 5years prior to the change.This exemption shall not apply to any new unit that:

(i) Is designated as a replacement for an existing unit;(ii) Qualifies under section 409(b) of the Clean Air Act for an extension of an emission limitation compliance dateunder section 405 of the Clean Air Act; and(iii) Is located at a different site than the existing unit.

157

The installation, operation, cessation, or removal of a temporary clean coal technology demonstration project isexempt from the requirements of this section. A temporary clean coal control technology demonstration project,for the purposes of this section is a clean coal technology demonstration project that is operated for a period of 5years or less, and which complies with the State implementation plan for the State in which the project is locatedand other requirements necessary to attain and maintain the national ambient air quality standards during theproject and after it is terminated.

158 The reactivation of a very clean coal-fired electric utility steam generating unit is exempt from the requirementsof this section.

40 CFR 60.14(f), Minn. R. 7011.0050

40 CFR 60.14(g), Minn. R. 7011.0050

40 CFR 60.14(h), Minn. R. 7011.0050

40 CFR 60.14(i), Minn. R. 7011.0050

40 CFR 60.14(j), Minn. R. 7011.0050

40 CFR 60.14(k), Minn. R. 7011.0050

40 CFR 60.14(l), Minn. R. 7011.0050




159 An existing facility, upon reconstruction, becomes an affected facility, irrespective of any change in emissionrate.

160

Reconstruction means the replacement of components of an existing facility to such an extent that:

(1) The fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would berequired to construct a comparable entirely new facility, and(2) It is technologically and economically feasible to meet the applicable standards set forth in this part.

161 Fixed capital cost means the capital needed to provide all the depreciable components.

168

If a Permittee proposes to replace components, and the fixed capital cost of the new components exceeds 50percent of the fixed capital cost that would be required to construct a comparable entirely new facility, thePermittee shall notify the Administrator of the proposed replacements. The notice must be postmarked 60 days(or as soon as practicable) before construction of the replacements is commenced and must include thefollowing information:

(1) Name and address of the owner or operator.(2) The location of the existing facility.(3) A brief description of the existing facility and the components which are to be replaced.(4) A description of the existing air pollution control equipment and the proposed air pollution control equipment.(5) An estimate of the fixed capital cost of the replacements and of constructing a comparable entirely new facil..

169

PM < 10 micron : The Permittee shall conduct an initial performance test : Due 180 calendar days after InitialStartup Date to measure emissions at base load with duct burners. The performance test shall be conducted atworst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 201A and 202,or other method approved by MPCA in the performance test plan approval.

170

PM < 2.5 micron : The Permittee shall conduct an initial performance test : Due 180 calendar days after InitialStartup Date to measure emissions at base load with duct burners. The performance test shall be conducted atworst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 201A and 202,or other method approved by MPCA in the performance test plan approval.

171

Total Particulate Matter : The Permittee shall conduct an initial performance test : Due 180 calendar days afterInitial Startup Date to measure emissions at base load with duct burners. The performance test shall beconducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 5and 202, or other method approved by MPCA in the performance test plan approval.

40 CFR 60.15(a), Minn. R. 7011.0050

40 CFR 60.15(b), Minn. R. 7011.0050

40 CFR 60.15(c), Minn. R. 7011.0050

40 CFR 60.15(d), Minn. R. 7011.0050







pp y p p pp

172

Volatile Organic Compounds : The Permittee shall conduct an initial performance test : Due 180 calendar daysafter Initial Startup Date to measure emissions. The performance test shall be conducted at worst caseconditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 25A, or other methodapproved by MPCA in the performance test plan approval.

175

Hexane : The Permittee shall conduct an initial performance test : Due 180 calendar days after Initial StartupDate to verify the emission factor of hexane (in lb/mmBtu). The performance test shall be conducted at worstcase conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 18, 320, or othermethod approved by MPCA in the performance test plan approval. Tests shall be conducted while combustingnatural gas at 90 to 100 percent load (base load with EQUI 17).

176

Formaldehyde : The Permittee shall conduct an initial performance test : Due 180 calendar days after InitialStartup Date to verify the emission factor of formaldehyde (in lb/mmBtu). The performance test shall beconducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method18, 320, or other method approved by MPCA in the performance test plan approval. The tests shall beconducted while combusting natural gas under the following conditions:

1. 15 to 30 percent load;2. 60 to 70 percent load;3. 90 to 100 percent load (base load with EQUI 17).

177

PM < 10 micron : The Permittee shall submit a test frequency plan : Due 60 calendar days after InitialPerformance Test Date for PM10 emissions. The plan shall specify a testing frequency based on the test dataand MPCA guidance. Future performance tests based on 12-month, 36-month, or 60-month intervals, or asapplicable, shall be required upon written approval of the MPCA.

178

PM < 2.5 micron : The Permittee shall submit a test frequency plan : Due 60 calendar days after InitialPerformance Test Date for PM2.5 emissions. The plan shall specify a testing frequency based on the test dataand MPCA guidance. Future performance tests based on 12-month, 36-month, or 60-month intervals, or asapplicable, shall be required upon written approval of the MPCA.

179

Total Particulate Matter : The Permittee shall submit a test frequency plan : Due 60 calendar days after InitialPerformance Test Date for PM emissions. The plan shall specify a testing frequency based on the test data andMPCA guidance. Future performance tests based on 12-month, 36-month, or 60-month intervals, or asapplicable, shall be required upon written approval of the MPCA.

180

Volatile Organic Compounds : The Permittee shall submit a test frequency plan : Due 60 calendar days afterInitial Performance Test Date for VOC emissions. The plan shall specify a testing frequency based on the testdata and MPCA guidance. Future performance tests based on 12-month, 36-month, or 60-month intervals, or asapplicable, shall be required upon written approval of the MPCA.











pp q p pp

182

Hexane : The Permittee shall submit a test frequency plan : Due 60 calendar days after Initial Performance TestDate for hexane emission factor. The plan shall specify a testing frequency based on the test data and MPCAguidance. Future performance tests based on 12-month, 36-month, or 60-month intervals, or as applicable, shallbe required upon written approval of the MPCA.

183

Formaldehyde : The Permittee shall submit a test frequency plan : Due 60 calendar days after InitialPerformance Test Date for formaldehyde emission factor. The plan shall specify a testing frequency based onthe test data and MPCA guidance. Future performance tests based on 12-month, 36-month, or 60-monthintervals, or as applicable, shall be required upon written approval of the MPCA.

184

The Permittee shall submit a notification : Due within 30 days of the end of the shakedown period for EQUI 16.The shakedown period shall be the earlier of 180 days after initial startup of EQUI 16, or 60 days after achievingmaximum production of EQUI 16, or submittal of successful compliance test and CEMS certification reports forEQUI 16.

19670 Additional requirements for Combustion Turbine #1 are located at EQUI 16. Additional requirements for DuctBurners (Combustion Turbine #1) are located at EQUI 17.



Minn. R. 7007.0800, subp. 2

Minn. R. 7007.0800, subp. 2



Attachment 3: Subject Item Inventory/Details

Subject ItemCategory Description Subject Item Type DescriptionActivity Insignificant Air Emissions Activity

Agency Interest Conventional Site

Component Group Air Component Group

Equipment Aboveground Storage Tank

Boiler

Continuous Emission Monitor

Data Acquisition System

Duct Burner

Reciprocating IC Engine

Turbine

Fugitive Cooling Tower

Equipment Leaks

Structure Building

Stack/Vent

Total Facility Air Quality Total Facility

Treatment 028-Steam or Water Injection

099-Other

109-Catalytic Oxidizer

139-SCR (Selective Catalytic Reduction)

205-Low Nox Burners

1

1

2

2

2

2

2

4

2

2

2

1

6

13

1

1

2

2

1

1

Overview of SI's (count) by type

Agency Interest: Mankato Energy Center LLCAgency Interest ID: NoneActivity: IND20150001 (None)

Details for:SI Category: AllSI Type: All

Agency Interest Name Subject Item ID Subject Item .. Subject Item DescriptionMankato Energy CenterLLC

ACTV3 Null All IAs

AISI95792 Null Null

COMG5 Null Formaldehyde, n-Hexane, and Total HAPs

COMG6 Null Combustion Turbines and Duct Burners (SV002 & SV007)

EQUI2 DA002 CT #2 CEMS

EQUI3 MR003 NOx CEM for CT #2

EQUI4 MR004 CO CEM for CT #2

EQUI5 EU002 Combustion Turbine #2

EQUI6 EU004 Duct Burner (Combustion Turbine #2)

EQUI7 EU005 Auxiliary Boiler

EQUI11 EU007 Fire Pump Engine

EQUI16 EU008 Combustion Turbine #1

EQUI17 EU009 Duct Burners (Combustion Turbine #1)

EQUI18 EU010 Diesel Fired Emergency Generator

EQUI19 EU011 Bath Heater

EQUI20 DA003 CT #1 CEMS

EQUI21 MR005 NOx CEM for CT #1

EQUI22 MR006 CO CEM for CT #1

EQUI23 Null Diesel Fired Emergency Generator Tank

EQUI24 Null Natural Gas Condensate Tank - Plant

FUGI1 FS001 Cooling Tower

FUGI2 FS002 Natural Gas Fugitives

FUGI3 FS003 Breaker Fugitives

STRU1 BG001 Administration / Warehouse Building (SPF: 14)

STRU2 BG002 Water Treatment/ Electrical Control Building(13)

STRU3 BG003 Fire Pump House (Site Plan Reference: 52)

STRU4 BG004 Cooling Tower (Site Plan Reference: 20)

STRU5 BG005 Cooling Tower Chemical Feed Building (28)

STRU6 BG006 Heat Recovery Steam Generator #2 (SPF: 4)

STRU7 BG007 Steam Turbine Generator Building (SPF: 56)

STRU8 BG008 Combustion Turbine #2 (Site Plan Reference:2)

STRU9 BG009 Auxiliary Boiler (Site Plan Reference: 53)

STRU10 BG010 Demineralized Water Storage Tank (SPF: 24)

STRU11 BG011 Fuel Oil Storage Tank (Site Plan Reference: 58)

STRU12 BG012 Raw Water Storage Tank (Site Plan Refere:23)

STRU13 BG013 Existing Warehouse Building (Site Plan Ref:15)

STRU14 SV002 Combustion Turbine #2 & Duct Burners #2 Stack

STRU17 SV003 Auxiliary Boiler Stack

STRU18 SV005 Fire Pump Engine Stack

STRU20 SV007 Combustion Turbine #1 & Duct Burners #1 Stack

STRU21 SV008 Diesel Fired Emergency Generator Stack

STRU22 SV009 Bath Heater Stack

TFAC1 01300098 Mankato Energy Center LLC

TREA4 CE004 Steam or Water Injection for CT #2

List of SIs

Agency Interest: Mankato Energy Center LLCAgency Interest ID: 95792Activity: IND20150001 (Major Amendment)

Details for:SI Category: NoneSI Type: All

Agency Interest Name Subject Item ID Subject Item .. Subject Item DescriptionMankato Energy CenterLLC

jTREA5 CE006 SCR (Selective Catalytic Reduction) for CT #2

TREA6 CE008 Catalytic Oxidizer for CT #2

TREA7 CE009 Low NOx Burners for EQUI 7

TREA9 CE002 Lean Pre-mix DLN Combustion for CT #2

TREA11 CE011 SCR (Selective Catalytic Reduction) for CT #1

TREA12 CE012 Catalytic Oxidizer for CT #1

List of SIs


Details for:SI Category: NoneSI Type: All

Subject ItemCategoryDescription

Subject ItemTypeDescription Subject Item ID

Subject ItemDesignation Pollutant

Pote

ntia

l (lb

s/hr

)

Unr

estr

icte

d Po

tent

ial

(tons

/yr)

Pote

ntia

l Lim

ited

(tons

/yr)

Act

ual E

mis

sion

s(to

ns/y

r)

Equipment AbovegroundStorage Tank

EQUI23 Null Volatile Organic Compounds

EQUI24 Null Volatile Organic Compounds

Boiler EQUI7 EU005 1,4-Dichlorobenzene (para-)

Arsenic compounds

Benzene

Beryllium

Cadmium compounds

Carbon Dioxide

Carbon Dioxide Equivalent

Carbon Monoxide

Chromium compounds

Cobalt compounds

Formaldehyde

HAPs - Total

Hexane

Lead

Manganese compounds

Mercury

Methane

Naphthalene

Nickel compounds

Nitrogen Oxides

Nitrous Oxide

PM < 2.5 micron

PM < 10 micron

Polycyclic organic matter

Selenium compounds

Sulfur Dioxide

Sulfuric Acid Mist

Toluene

Total Particulate Matter

Volatile Organic Compounds

EQUI19 EU011 1,4-Dichlorobenzene (para-)

Arsenic compounds

Benzene

Beryllium

Cadmium compounds

Carbon Dioxide


Carbon Monoxide

0.0002750.0002756.28e-050.050.050.01

2.152.45

0.001020.0490.31

7.21e-060.00021

2.452.450.07

11.040.0006310.000183

0.687.82e-050.000114

0.000150.5410.568

0.02252.52e-050.000421

18.435,90235,865

0.0003313.61e-060.0006316.01e-050.000361

2.152.45

0.001020.0490.31

7.21e-060.00021

2.452.450.07

11.040.0006310.000183

0.687.82e-050.000114

0.000150.5410.568

0.02252.52e-050.000421

18.435,90235,865

0.0003313.61e-060.0006316.01e-050.000361

0.490.56

0.0002330.0112

0.071.65e-064.79e-05

0.560.560.022.52

0.0001444.19e-05

0.151.78e-052.61e-053.43e-05

0.1240.13

0.005155.76e-069.61e-05

4.28,1978,188

7.55e-058.24e-070.0001441.37e-058.24e-05

1.041,4721,470

1.36e-051.48e-072.59e-052.46e-061.48e-05

1.041,4721,470

1.36e-051.48e-072.59e-052.46e-061.48e-05

0.24336336

3.1e-063.38e-085.91e-065.63e-073.38e-06

PTE by subject item






Pote

ntia

l (lb

s/hr

)

Unr

estr

icte

d Po

tent

ial

(tons

/yr)

Pote

ntia

l Lim

ited

(tons

/yr)

Act

ual E

mis

sion

s(to

ns/y

r)

Equipment Boiler EQUI19 EU011 Chromium compounds

Cobalt compounds

Formaldehyde

HAPs - Total

Hexane

Lead

Manganese compounds

Mercury

Methane

Naphthalene

Nickel compounds

Nitrogen Oxides

Nitrous Oxide

PM < 2.5 micron

PM < 10 micron


Selenium compounds

Sulfur Dioxide

Toluene



ReciprocatingIC Engine

EQUI11 EU007 1,3-Butadiene

Acetaldehyde

Acrolein

Benzene

Carbon Dioxide


Carbon Monoxide

Formaldehyde

HAPs - Total

Methane

Naphthalene

Nitrogen Oxides

Nitrous Oxide

PM < 2.5 micron

PM < 10 micron

Sulfur Dioxide

Sulfuric Acid Mist

Toluene


0.070.09

4.19e-050.00739

2.96e-078.6e-06

0.090.09

0.0002771.23

2.59e-057.52e-060.002773.2e-06

4.68e-066.16e-06

0.02220.0233

0.0009241.04e-061.73e-05

0.070.09

4.19e-050.00739

2.96e-078.6e-06

0.090.09

0.0002771.23

2.59e-057.52e-060.002773.2e-06

4.68e-066.16e-06

0.02220.0233

0.0009241.04e-061.73e-05

0.020.02

9.57e-060.00169

6.75e-081.96e-06

0.020.02

0.0006330.28

5.91e-061.72e-060.00633

7.32e-071.07e-061.41e-060.005060.00531

0.0002112.36e-073.94e-06

0.0045.01e-050.000722

0.0060.0040.004

0.0001620.169

1.04e-050.00081

0.0004750.000145

0.0242020

0.0001141.13e-059.4e-05

4.79e-06

0.0045.01e-050.00361

0.0060.0040.004

0.0001620.169

1.04e-050.00081

0.0004750.000145

0.0242020

0.0001141.13e-059.4e-05

4.79e-06

0.080.001

0.01440.120.080.08

0.003243.37

0.0002080.0162

0.009490.00289

0.48401399

0.002290.000227

0.001889.58e-05

PTE by subject item






Pote

ntia

l (lb

s/hr

)

Unr

estr

icte

d Po

tent

ial

(tons

/yr)

Pote

ntia

l Lim

ited

(tons

/yr)

Act

ual E

mis

sion

s(to

ns/y

r)

Equipment ReciprocatingIC Engine

EQUI11 EU007 Total Polycyclic aromatic hydr..


Xylenes, Total

EQUI18 EU010 1,3-Butadiene

Acetaldehyde

Acrolein

Benzene

Carbon Dioxide


Carbon Monoxide

Formaldehyde

HAPs - Total

Methane

Naphthalene

Nitrogen Oxides

Nitrous Oxide

PM < 2.5 micron

PM < 10 micron

Sulfur Dioxide

Toluene


Total Polycyclic aromatic hydr..


Xylenes, Total

Fugitive Cooling Tower FUGI1 FS001 PM < 2.5 micron

PM < 10 micron


EquipmentLeaks

FUGI2 FS002 Carbon Dioxide


Methane

FUGI3 FS003 Carbon Dioxide Equivalent

Sulfur Hexafluoride

Structure Stack/Vent STRU14 SV002 1,3-Butadiene

1,4-Dichlorobenzene (para-)

Acetaldehyde

Acrolein

Arsenic compounds

Benzene

Beryllium

Cadmium compounds

3.49e-050.008

2.06e-05

3.49e-050.008

2.06e-05

0.0006980.15

0.000412

0.0002450.04

0.000270.01

0.0003570.260.010.01

0.001680.66

0.0001650.008410.002050.0001

0.66207.4207.4

0.0009871e-05

3.21e-054.97e-05

0.001230.18

0.001350.04

0.001791.280.040.04

0.008413.32

0.0008270.04210.0103

0.0005023.32

1,040.51,036.90.00493

5.01e-050.00016

0.000249

0.004910.72

0.005390.15

0.007155.130.150.15

0.033613.27

0.003310.1680.041

0.0020113.274,1624,148

0.01970.0002

0.0006410.000995

15.872.7

0.0212

15.872.7

0.0212

3.620.62

0.00484

266.76,669

2.8

266.76,669

2.8

60.91,523

0.6

0.0014333

0.0014333

0.0003277

0.008490.000345

0.1590.109

0.05840.365

0.004120.0192

0.050980.00309

0.5470.109

0.05840.365

0.004120.157

0.011660.0007044

0.1250.02480.01330.0833

0.0009410.0359

PTE by subject item






Pote

ntia

l (lb

s/hr

)

Unr

estr

icte

d Po

tent

ial

(tons

/yr)

Pote

ntia

l Lim

ited

(tons

/yr)

Act

ual E

mis

sion

s(to

ns/y

r)

Structure Stack/Vent STRU14 SV002p

Carbon Dioxide


Carbon Monoxide

Chromium compounds

Cobalt compounds

Ethylbenzene

Formaldehyde

HAPs - Total

Hexane

Lead

Manganese compounds

Mercury

Methane

Naphthalene

Nickel compounds

Nitrogen Oxides

Nitrous Oxide

PM < 2.5 micron

PM < 10 micron


Propylene oxide

Selenium compounds

Sulfur Dioxide

Sulfuric Acid Mist

Toluene




Xylenes, Total

STRU20 SV007 1,3-Butadiene

1,4-Dichlorobenzene (para-)

Acetaldehyde

Acrolein

Arsenic compounds

Benzene

Beryllium

Cadmium compounds

Carbon Dioxide


Carbon Monoxide

0.584262

0.0573118.5

1.210.2967.8

0.02460.264

0.0024118.5118.52.78

174.130.01170.047127.82

0.01270.7810.02

922.5

90.292

0.0002890.0156477.94

1,478,1321,476,608

0.584185.390.393

317.991.2

64.34423.860.2460.264

0.0024317.99317.9913.77

1,672.640.05240.34672.7

0.01277.76

0.1384.29

39.6535.220.292

0.0002890.113

1,145.182,017,6842,011,764

0.13325.4

0.089772.6

0.27314.6996.77

0.05610.0604

0.00054872.672.63.15

63.120.011950.07898

16.590.002894

1.770.0314

0.989.058.04

0.06666.59e-05

0.025826.15

460,659459,307

767.981,578,1451,576,517

0.003894.24e-05

0.1250.000707

0.06320.395

0.004240.00423

1,288.11,578,1451,576,517

0.003894.24e-05

0.1250.000707

0.06320.395

0.004240.00423

27.64360,307359,935

0.0008889.69e-06

0.02870.000162

0.01440.0901

0.0009690.000967

PTE by subject item






Pote

ntia

l (lb

s/hr

)

Unr

estr

icte

d Po

tent

ial

(tons

/yr)

Pote

ntia

l Lim

ited

(tons

/yr)

Act

ual E

mis

sion

s(to

ns/y

r)

Structure Stack/Vent STRU20 SV007 Chromium compounds

Cobalt compounds

Ethylbenzene

Formaldehyde

HAPs - Total

Hexane

Lead

Manganese compounds

Mercury

Methane

Naphthalene

Nickel compounds

Nitrogen Oxides

Nitrous Oxide

PM < 2.5 micron

PM < 10 micron


Propylene oxide

Selenium compounds

Sulfur Dioxide

Sulfuric Acid Mist

Toluene




Xylenes, Total 0.63382.540.021752.121.294.5830.2

8.49e-050.286

0.0024752.1252.122.97

166.780.00743

0.01529.71

0.000920.001340.00661

922.5

90.316

0.0002970.00495

0.63425.5

0.021752.121.294.5830.2

8.49e-050.286

0.0024752.1252.122.97

1,198.770.00743

0.01529.71

0.000920.001340.00661

4.5842.1937.6

0.3160.000297

0.00495

0.1413.42

0.0049611.9

0.2931.056.9

1.94e-050.0653

0.00056411.911.90.68

34.050.0017

0.003426.78

0.000210.000307

0.001511.059.638.58

0.07216.78e-050.00113

PTE by subject item




Subject Item TypeDescription Subject Item ID

Subject ItemDesignation Subject Item Description

Relationship(F/R)

Related Subject ItemID

Related Subject Item TypeDescription

Start Date(Subject ItemRelated)

End Date(Subject ItemRelated)

ConfidentialityFlag

Equipment Boiler EQUI7 EU005 Auxiliary Boiler is controlled .. TREA0000000007 205-Low Nox Burners 9/29/2004 Null Null

sends to STRU0000000017 Stack/Vent 9/29/2004 Null Null

EQUI19 EU011 Bath Heater sends to STRU0000000022 Stack/Vent 10/31/2006 Null Not Confidential

Continuous EmissionMonitor

EQUI3 MR003 NOx CEM for CT #2 sends to EQUI0000000002 Data Acquisition System 8/18/2009 Null Null

EQUI4 MR004 CO CEM for CT #2 sends to EQUI0000000002 Data Acquisition System 8/18/2009 Null Null

EQUI21 MR005 NOx CEM for CT #1 sends to EQUI0000000020 Data Acquisition System 4/1/2016 Null Not Confidential

EQUI22 MR006 CO CEM for CT #1 sends to EQUI0000000020 Data Acquisition System 4/1/2016 Null Not Confidential

Duct Burner EQUI6 EU004 Duct Burner (CombustionTurbine #2)

is controlledby

TREA0000000005 139-SCR (Selective Catalyti.. 9/29/2004 Null Null

TREA0000000006 109-Catalytic Oxidizer 9/29/2004 Null Null

sends to STRU0000000014 Stack/Vent 9/29/2004 Null Null

EQUI17 EU009 Duct Burners (CombustionTurbine #1)

is controlledby

TREA0000000011 139-SCR (Selective Catalyti.. 4/1/2016 Null Not Confidential

TREA0000000012 109-Catalytic Oxidizer 4/1/2016 Null Not Confidential

sends to STRU0000000020 Stack/Vent 4/1/2016 Null Not Confidential

Reciprocating ICEngine

EQUI11 EU007 Fire Pump Engine sends to STRU0000000018 Stack/Vent 9/29/2004 Null Null

EQUI18 EU010 Diesel Fired Emergency Gene.. sends to STRU0000000021 Stack/Vent 4/1/2016 Null Not Confidential

Turbine EQUI5 EU002 Combustion Turbine #2 is controlledby

TREA0000000004 028-Steam or Water Injection 9/29/2004 Null Null

TREA0000000005 139-SCR (Selective Catalyti.. 9/29/2004 Null Null

TREA0000000006 109-Catalytic Oxidizer 9/29/2004 Null Null

TREA0000000009 099-Other 9/29/2004 Null Null

is monitoredby

EQUI0000000003 Continuous Emission Monitor 8/18/2009 Null Null

EQUI0000000004 Continuous Emission Monitor 8/18/2009 Null Null

sends to EQUI0000000002 Data Acquisition System 8/18/2009 Null Null

STRU0000000014 Stack/Vent 9/29/2004 Null Null

EQUI16 EU008 Combustion Turbine #1 is controlledby



is monitoredby

EQUI0000000021 Continuous Emission Monitor 4/1/2016 Null Not Confidential

EQUI0000000022 Continuous Emission Monitor 4/1/2016 Null Not Confidential

sends to EQUI0000000020 Data Acquisition System 4/1/2016 Null Not Confidential

STRU0000000020 Stack/Vent 4/1/2016 Null Not Confidential

Treatment 099-Other TREA9 CE002 Lean Pre-mix DLN Combustionfor CT #2

is controlled inseries by

TREA0000000004 028-Steam or Water Injection 9/29/2004 Null Not Confidential



109-Catalytic Oxidiz.. TREA12 CE012 Catalytic Oxidizer for CT #1 is controlled i.. TREA0000000011 139-SCR (Selective Catalyti.. 4/1/2016 Null Not Confidential

SI - SI relationships




Capacity(gal) AST Substance Stored

ColumnDiameter(ft)

ColumnCount Deck Type

InteriorDiameter(ft)

InteriorHeight(ft)

MaximumTrueVaporPressure(psia)

ConstructionType Seal Type Support Type

ConfidentialityFlag

AbovegroundStorage Tank

EQUI23 Null Null Null Null Null 7 16 Null Fixed Roof Null Null Not Confidential

EQUI24 Null Null Null Null Null 10 11 0.87 Fixed Roof Null Null Not Confidential

Aboveground Storage Tanks, General


Details for:SI Category: EquipmentSI Type: Aboveground Storage Tank


Subject ItemDesignation Manufacturer Model

Max DesignCapacity

Max DesignCapacityUnits(numerator)

Max DesignCapacityUnits(denominator) Material

ConstructionStart Date

OperationStart Date

Modification Date

ConfidentialityFlag

Turbine EQUI5 EU002 Siemens-Westinghouse 501F-D2 375 megawatts hours Electrical Energy 11/1/2004 7/1/2006 Null Null

EQUI16 EU008 TBD TBD 2253.3 million British.. hours Energy Null Null Null Not Confidential

Emission Units 1


Details for:SI Category: EquipmentSI Type: Turbine

Boiler EQUI7 Nebraska Boiler DS-57-SH-AL 50000 pounds hours Steam 11/1/2004 7/1/2006 Null Not coal burni.. Null Null

EQUI19 Parsons 15197 2.87 million British thermal units hours Heat 5/18/2005 10/31/2006 Null Not coal burni.. Null Null

Duct Burner EQUI6 Coen custom 1000000 pounds hours Steam 11/1/2004 7/1/2006 Null Not coal burni.. Null Null

EQUI17 TBD TBD 823.7 million British thermal units hours Energy Null Null Null Not coal burni.. Null Null

Reciprocating IC Engine EQUI11 Peerless 8AEFZOG 350 horsepower hours Diesel Fuel 11/1/2004 7/1/2006 Null CI Emergency/blackstart 8100

EQUI18 TBD TBD 2500 kilowatts hours Energy Null Null Null CI Emergency/blackstart 78080

Emission Units 2


Details for:SI Category: EquipmentSI Type: Boiler, Duct Burner, Reciprocating IC Engine

Subject ItemTypeDescription Subject Item ID Manufacturer Model Serial Number

ParameterMonitored(continuousmonitors)

Primary orbackupmonitor?

Em BypassCapability?

MonitorInstall Date

CertificationDate

CertificationBasis Em Span

System FullScale Value

Optical PathLength

ConfidentialityFlag

ContinuousEmissionMonitor

EQUI3 Teledyne Instruments M200EM NO459 Nitrogen Oxides P N 8/18/2009 9/23/2009 40 CFR Pt 75 200 200 Null Null

EQUI4 Teledyne Instruments M300EM CO332 Carbon Monoxide P N 8/18/2009 9/23/2009 40 CFR Pt 60 3000 5000 1.19 Null

EQUI21 Null Null Null Nitrogen Oxides P N Null Null 40 CFR Pt 75 Null Null Null Not Confidential

EQUI22 Null Null Null Carbon Monoxide P N Null Null 40 CFR Pt 60 Null Null Null Not Confidential

CEMs/COM, General


Details for:SI Category: EquipmentSI Type: Continuous Emission Monitor

Subject Item ID Manufacturer Model Serial NumberPrimary orbackup DAS?

Das InstallDate

Confidentiality Flag

EQUI2 General Electric GE NetDAHS n/a P 6/1/2006 Null

EQUI20 Null Null Null P Null Null

Data Acquisition System, General


Details for:SI Category: EquipmentSI Type: Data Acquisition System

Subject ItemTypeDescription Subject Item ID Install Year

Parameter Monitored(fugitive)

ConfidentialityFlag

CoolingTower

FUGI1 2006 PM < 2.5 micron Null

PM < 10 micron Null

Total Particulate Matter Null

EquipmentLeaks

FUGI2 Null Carbon Dioxide Not Confidential

Methane Not Confidential

FUGI3 Null Sulfur Hexafluoride Not Confidential

Fugitive Sources


Details for:SI Category: FugitiveSI Type: Cooling Tower & Equipment Leaks

Subject ItemTypeDescription Subject Item ID Height Units (height) Length Units (length) Width Units (width)

ConfidentialityFlag

Building STRU1 25 feet 230 feet 60 feet Not Confidential

STRU2 25 feet 185 feet 75 feet Not Confidential








STRU10 30 feet 37.37 feet 40 feet Not Confidential




Buildings, General


Details for:SI Category: StructureSI Type: Building


Stack Height(feet)

StackDiameter(feet)

Stack Length(feet)

Stack Width(feet)

Stack FlowRate (cubicft/min)

DischargeTemp (°F)

Info SourceDesc Discharge Direction

ConfidentialityFlag

Stack/Vent STRU14 200 19 Null Null 684892 160 Manufacturer Upwards with no cap on stack/vent Not Confidential

STRU17 100 4 Null Null 24150 325 Manufacturer Upwards with no cap on stack/vent Not Confidential

STRU18 15 0.6 Null Null 663 829 Manufacturer Upwards with no cap on stack/vent Not Confidential

STRU20 200 19 Null Null 668591 160 Manufacturer Upwards with no cap on stack/vent Not Confidential

STRU21 13 0.67 Null Null 19582 915.3 Manufacturer Upwards with no cap on stack/vent Not Confidential

STRU22 25 1.67 Null Null 1507.66 913 Manufacturer Upwards with no cap on stack/vent Not Confidential

Stack/Vent, General


Details for:SI Category: StructureSI Type: Stack/Vent

Subject Item TypeDescription Subject Item ID Manufacturer Model

Install StartDate

PollutantControlled(treatment)

CaptureEfficiency (%)

Destruction/CollectionEfficiency (%)

Subject toCAM? Large PSEU? Efficiency Basis

Other operating parameters?

Other operatingparametersdescription

ConfidentialityFlag

099-Other TREA9 Siemens-Westin.. Null 6/1/2006 Nitrogen Oxides 100 Null N Null Mfr/Vendor data N Null Not Confidential

139-SCR (SelectiveCatalytic Reduction)

TREA5 Nooter-Eriksen/P.. custom 6/1/2006 Nitrogen Oxides 100 80 Y Y Mfr/Vendor data Y Minimum design tem.. Not Confidential

TREA11 Null Null Null Nitrogen Oxides 100 80 Y Y Mfr/Vendor data Y Minimum design tem.. Not Confidential

205-Low Nox Burners TREA7 NATCOM P-66-G-1.. 6/1/2006 Nitrogen Oxides 100 50 N Null Mfr/Vendor data N Null Not Confidential

Other Control Equipment


Details for:SI Category: TreatmentSI Type: 099-Other, 139-SCR (Selective Catalytic Reduction), 205-Low Nox Burners

The view is broken down by Subject Item Type Description, Subject Item ID, Manufacturer, Model, Install Start Date, Pollutant Controlled (treatment), Capture Efficiency (%), Destruction/Collection Efficiency (%), Subject to CAM?, Large PSEU?,Efficiency Basis, Other operating parameters?, Other operating parameters description and Confidentiality Flag. Details are shown for Agency Interest ID and Activity Type Label. The data is filtered on Agency Interest Name, Subject Item Cate-gory Description, Activity ID and Effective Flag. The Agency Interest Name filter keeps Mankato Energy Center LLC. The Subject Item Category Description filter keeps Treatment. The Activity ID filter keeps IND20150001. The Effective Flag filterkeeps Other permit activities. The view is filtered on Subject Item Type Description, which keeps 38 of 235 members.

Subject ItemTypeDescription Subject Item ID Manufacturer Model

Install StartDate


CaptureEfficiency (%)


Subject toCAM? Large PSEU? Efficiency Basis

Catalyst BedReactivity(kat)

BurnerCapacity(MMBTU/hr)

CatatlyticOxidizer InletTemperature(°F)

OutletTemperature(°F)

ConfidentialityFlag

109-CatalyticOxidizer

TREA6 Englehard custom 6/1/2006 Carbon Monoxide 100 90 Y Y Mfr/Vendor data Null Null 651 651 Not Confidential

Volatile Organic C.. 100 40 Y Y Mfr/Vendor data Null Null 651 651 Not Confidential

TREA12 Null Null Null Carbon Monoxide 100 90 Y Y Mfr/Vendor data Null Null Null Null Not Confidential

Volatile Organic C.. 100 40 Y Y Mfr/Vendor data Null Null Null Null Not Confidential

Catalytic Oxidizers, General


Details for:SI Category: TreatmentSI Type: 109-Catalytic Oxidizer

Subject Item ID Manufacturer ModelInstall StartDate


CaptureEfficiency(%)


Subject toCAM? Large PSEU?

EfficiencyBasis

Injection SystemMaterial Injected

InjectionSystemMaximumInjection Rate

Injection SystemMaximum UnitsDescription

InjectionSystemMinimumInjection Rate

Injection SystemMinimum UnitsDescription

ConfidentialityFlag

..ater Injection, TREA4 Siemens-Westin.. custom 6/1/2006 Nitrogen Oxid.. 100 82 N Null Mfr/Vendor d.. Steam or Water 5520 gallons per hour 3774 gallons per hour Not Confidential

Injections Systems, General


Details for:SI Category: TreatmentSI Type: 028-Steam or Water Injection

Attachment 4: CAM Plans

COMPLIANCE ASSURANCE MONITORING CATALYTIC OXIDATION SYSTEM FOR VOC CONTROL:

MANKATO ENERGY CENTER, COMBUSTION TURBINE NO. 1 AND DUCT BURNER

I. Background A. Emissions Unit

Description: Combustion Turbine #1; Duct Burner #1

Emission Unit ID: EQUI16 and EQUI17

Control Equipment ID: TREA12 Facility: Mankato Energy Center Mankato, MN

B. Applicable Regulation, Emissions Limit, and Monitoring Requirements Regulation: Permit and State Regulation

Emission Limits: VOC: Normal Operations Less than or equal to 3.4 ppm VOC using a 3-hour block average by volume on a dry basis corrected to 15% O2. This limit applies at all times when EQUI16 combusts natural gas except during startup and shutdown events, malfunction, tuning and roll back periods. (40 CFR Section 52.21(j) BACT limit) Start-up/Shutdown (SUSD) Less than or equal to 333.32 tons per year using a 12-month rolling sum during COLD and WARM startups and shutdowns.

Proposed Monitoring: The combustion turbine/duct burner stack will be

equipped with a Continuous Emission Monitor for CO. Requirements: A Continuous Emission Monitoring System (CEMS) for CO

is required by the permit, with a regulatory basis of Minn. R. 7017.1006 and 7017.1090, Subp. 1

C. Control Technology: Oxidation Catalyst

II. Monitoring Approach A. Indicator(s) Continuous Emission Monitoring System (CEMS) for CO,

if the CO concentration is 4.0 ppm or less on a 3-hour rolling average basis when EQUI16 combusts natural gas and operates at full load (i.e. greater than 90% load), then the facility is in compliance with the VOC limit.

CEMS for CO, if the CO concentration is 4.7 ppm or less on a 3-hour rolling average basis when EQUI16 combusts natural gas and operates between 60 to 90% load, then the facility is in compliance with the VOC limit.

CEMS for CO, if the CO for SUSD is less than or equal to 666.63 tons per year using a 12-month rolling sum during COLD and WARM startups and shutdowns; then the facility is in compliance with the VOC SUSD limit.

If the CO concentration exceeds any of the limits above, then the Permittee shall perform an inspection of the oxidation catalyst system to determine whether there is a CAM exceedance.

Measurement approach: The CEMS will provide the combustion turbine operators

with stack CO emission readings, indicating the overall performance of the oxidation catalyst system. CO is a product of incomplete combustion and indicates combustion efficiency.

Compliance with CO limits will demonstrate compliance with VOC limits.

B. Indicator Range(s) Indicator ranges will be the same as those specified in 40 CFR Part 60, Appendix B, Performance Specification 4.

C. Performance Criteria 1. Data

Representativeness The CO CEMS will be installed in a USEPA Performance Specification 4 (PS 4)-compliant location. This will ensure that the CEMS will be a reliable indicator of overall oxidation catalyst performance.

2. Verification of Operational Status

The CO CEMS will provide a continuous reading of stack CO emissions. The verification of this signal will be tested via quarterly QA/QC requirements according to PS 4 and 40 CFR Part 60, Appendix F.

3. QA/QC Practices In lieu of meeting PS 4 and Appendix F QA/QC requirements, the CO CEMS will meet 40 CFR Part 75 QA/QC procedures.

4. Monitoring Frequency

CO CEMS – continuous.

5. Data Collection Procedures

Data from the CO monitor will be recorded by the continuous monitoring system.

6. Averaging Period The CO CEMS will reduce data to that dictated by the applicable standard.

III. Monitoring Approach Justification

A. Background a. The CAM-affected “pollutant specific emission unit” (PSEU) is Combustion

Turbine #1 and duct burner. b. The PSEU is subject to a BACT limit under 40 CFR 52.21.

B. Rationale for Selection of Performance Indicators

a. Compliance with the VOC limit will be monitored using the CO CEMS as discussed in Section II. Previous stack testing on STRU14 for natural gas showed CO and VOC emissions well below the applicable permit limits. For natural gas combustion, stack tests on STRU14 in 2011 showed the VOC/CO ratio based on corrected ppmvd at 68% load was approximately 0.15; and at full load with duct burners the VOC/CO ratio was approximately 0.35. For start-up events, stack tests results for another Calpine Facility with similar SW 501F turbines showed a VOC/CO ratio of approximately 0.01 – 0.02 for all three units.

b. An inspection and maintenance program was selected because a systematic approach to investigating problems and conducting routine maintenance is the best possible means of minimizing excess emissions from the oxidation catalyst.

C. Rationale for Selection of Indicator Ranges

a. The CEMS monitored range is set in accordance with PS 4.

D. Control Device Operating Parameter Data Collected to Justify the Proposed Indicator Range

a. Not applicable.

E. Test Plan & Schedule for Obtaining Data if Performance Test Data Are Not Available a. Not applicable.

F. Implementation Plan

a. The CO CEMS system for the combustion turbine/duct burner stack will be operational after the shakedown period described in the facility’s air permit.

COMPLIANCE ASSURANCE MONITORING CATALYTIC OXIDATION SYSTEM FOR CO CONTROL:

MANKATO ENERGY CENTER, COMBUSTION TURBINE NO. 1 AND DUCT BURNER

I. Background A. Emissions Unit


Emission Unit ID: EQUI16; EQUI17 Control Equipment ID: TREA12 Facility: Mankato Energy Center Mankato, MN

B. Applicable Regulation, Emissions Limit, and Monitoring Requirements Regulation: Permit and State Regulation

Emission Limits: CO:

Normal Operations Less than or equal to 4.0 ppm CO using a 3-hour rolling average by volume on a dry basis corrected to 15% O2. This limit applies at all times when EQUI16 combusts natural gas and operates at full load (i.e. greater than 90% load). Limit does not apply during startup and shutdown events, malfunction, tuning, and roll back periods. (40 CFR Section 52.21(j) BACT limit) Less than or equal to 4.7 ppm CO using a 3-hour rolling average by volume on a dry basis corrected to 15% O2. This limit applies at all times when EQUI16 combusts natural gas and operates between 60 to 90% load. Limit does not apply during startup and shutdown events, malfunction, tuning, and roll back periods. (40 CFR Section 52.21(j) BACT limit)

Start-up/Shutdown (SUSD) Less than or equal to 666.63 tons per year using a 12-month rolling sum during COLD and WARM startups and shutdowns.

Proposed Monitoring The combustion turbine/duct burner stack will be

equipped with a Continuous Emission Monitor for CO. Requirements A Continuous Emission Monitoring System (CEMS) for CO

is required by the permit, with a regulatory basis of Minn. R. 7017.1006 and 7017.1090, Subp. 1

C. Control Technology: Oxidation Catalyst II. Monitoring Approach A. Indicator(s) Continuous Emission Monitoring System (CEMS) for CO Continuous Emission Monitoring System (CEMS) for CO, if

the CO concentration is 4.0 ppm or less on a 3-hour rolling average basis when EQUI16 combusts natural gas and operates at full load (i.e. greater than 90% load), then the facility is in compliance with the CO limit.

CEMS for CO, if the CO concentration is 4.7 ppm or less on a 3-hour rolling average basis when EQUI16 combusts natural gas and operates between 60 to 90% load, then the facility is in compliance with the CO limit.

CEMS for CO, if the CO for SUSD is less than or equal to 666.63 tons per year using a 12-month rolling sum during COLD and WARM startups and shutdowns; then the facility is in compliance with the CO SUSD limit.

If the CO concentration exceeds any of the limits above, then the Permittee shall perform an inspection of the oxidation catalyst system to determine whether there is a CAM exceedance.

Measurement approach: The CEMS will provide the combustion turbine operators

with stack CO emission readings, indicating the overall performance of the oxidation catalyst system. CO is a product of incomplete combustion and indicates combustion efficiency.

B. Indicator Range(s) Indicator ranges will the same as those specified in 40 CFR Part 60, Appendix B, Performance Specification 4.

C. Performance Criteria

1. Data Representativeness

The CO CEMS will be installed in a USEPA Performance Specification 4 (PS 4)-compliant location. This will ensure that the CEMS will be a reliable indicator of overall oxidation catalyst performance.


The CO CEMS will provide a continuous reading of stack CO emissions. The verification of this signal will be tested via quarterly QA/QC requirements according to PS 4 and 40 CFR Part 60, Appendix F.

3. QA/QC Practices In lieu of meeting PS 4 and Appendix F QA/QC requirements, the CO CEMS will meet 40 CFR Part 75 QA/QC procedures.

4. Monitoring Frequency CO CEMS – continuous. 5. Data Collection

Procedures Data from the CO monitor will be recorded by the continuous monitoring system.

6. Averaging Period The CO CEMS will reduce data to that dictated by the applicable standard.


A. Background a. The CAM-affected “pollutant specific emission unit” (PSEU) is Combustion

Turbine #1 and duct burner. b. The PSEU is subject to a BACT limit under 40 CFR 52.21.

B. Rationale for Selection of Performance Indicators

a. Use of a CEMS or PEMS meets the requirements of CAM as indicated by 40 CFR 64.3(d).

b. An inspection and maintenance program was selected because a systematic approach to investigating problems and conducting routine maintenance is the best possible means of minimizing excess emissions from the oxidation catalyst.

C. Rationale for Selection of Indicator Ranges

a. The CEMS monitored range is set in accordance with PS 4.


a. Not applicable.



a. The CO CEMS system for the combustion turbine/duct burner stack will be operational after the shakedown period described in the facility’s air permit.

COMPLIANCE ASSURANCE MONITORING

SELECTIVE CATALYTIC REDUCTION SYSTEM FOR NOX CONTROL: MANKATO ENERGY CENTER, COMBUSTION TURBINE NO. 1 AND DUCT BURNER

I. Background

A. Emissions Unit


Emission Unit ID: EQUI16; EQUI17 Control Equipment ID: TREA11

Facility: Mankato Energy Center

Mankato, MN

B. Applicable Regulation, Emissions Limit, and Monitoring Requirements

Regulation: Permit and State Regulation

Emission Limits: NOx:

Normal Operations Less than or equal to 3.0 ppm NOx using a 1-hour or 3-hour rolling average (which ever averaging period is included in the final permit) by volume on a dry basis corrected to 15% O2

when EQUI16 combusts natural gas except during startup and shutdown events, malfunction, tuning, and roll back periods. (40 CFR Section 52.21(j) BACT limit) Start-up/Shutdown (SUSD) Less than or equal to 41.9 tons per year using a 12-month rolling sum during COLD and WARM startups and shutdowns.

Proposed Monitoring: The combustion turbine/duct burner stack will be equipped with a Continuous Emission Monitor for NOx.

Requirements:

A Continuous Emissions Monitoring System (CEMS) for NOx is required by the permit, with a regulatory basis of 40 CFR pt. 75.

C.

Control Technology:

Selective Catalytic Reduction II. Monitoring Approach

A. Indicator(s) Continuous Emission Monitoring System (CEMS) for NOx • Continuous Emission Monitoring System (CEMS) for NOx, if

the NOx concentration is 3.0 ppm or less on a 1-hour or 3-hour rolling average (which ever averaging period is included in the final permit) average basis when EQUI16 combusts natural gas, then the facility is in compliance with the NOx limit.

• CEMS for NOx, if the NOx for SUSD is less than or equal to 41.9 tons per year using a 12-month rolling sum during COLD and WARM startups and shutdowns; then the facility is in compliance with the NOx SUSD limit.

• If the NOx concentration exceeds any of the limits above, then the Permittee shall perform an inspection of the selective catalytic reduction system to determine whether there is a CAM exceedance.

Measurement approach: • The CEMS will provide the combustion turbine/duct burner

operators with stack NOx emission readings, indicating the overall performance of the selective catalytic reduction system.

B. Indicator Range(s) Indicator ranges will the same as those specified in 40 CFR pt. 75 Appendix A & B.

C. Performance Criteria

1. Data Representativeness

The NOx CEMS is installed in a USEPA Performance Specification 2 (PS 2) -compliant location. This will ensure that the CEMS will be a reliable indicator of overall selective catalytic reduction system performance.


The NOx CEMS provides a continuous reading of stack NOx emissions. The verification of this signal will be tested via quarterly QA/QC requirements according to 40 CFR pt. 75 Appendix A and B.

3. QA/QC Practices In lieu of meeting PS 4 and Appendix F QA/QC requirements, the NOx CEMS will meet 40 CFR Part 75 QA/QC procedures.

4. Monitoring Frequency NOx CEMS – continuous. 5. Data Collection

Procedures Data from the NOx CEMS will also be recorded by the continuous monitoring system.

6. Averaging Period The NOx CEMS will reduce NOx data to that dictated by the applicable standard.


A. Background

a. The CAM-affected “pollutant specific emission unit” (PSEU) is Combustion Turbine #1 and duct burner.

b. The PSEU is subject to a BACT limit under 40 CFR § 52.21.

B. Rationale for Selection of Performance Indicators a. Use of a CEMS or PEMS meets the requirements of CAM as indicated under

40 CFR § 64.3(d).

C. Rationale for Selection of Indicator Ranges a. The CEMS monitored range is set in accordance with PS 2. b. There is no “range” proposed for the inspection and maintenance program. c. Conditions found will dictate necessary corrective actions, in accordance with

vendor specifications.


a. Not applicable.



a. The NOx CEMS system for the combustion turbine/duct burner stack will be operational after the shakedown period described in the facility’s air permit

Attachment 5: Risk Assessment Screening Spreadsheet

Summary

RASS version number = 201405- 25 stacksNo Inputs Allowed on this Page

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

Acute SubchronicNoncancer

ChronicNoncancer Cancer Farmer

NoncancerFarmerCancer

UrbanGardener

Noncancer

UrbanGardenerCancer

ResidentNoncancer

ResidentCancer

FarmerNoncancer

FarmerCancer

Urban Gardener Noncancer

UrbanGardenerCancer

ResidentNoncancer

ResidentCancer

8.E-01 2.E-02 2.E-01 3.E-06 5.E-01 6.E-06 1.E-01 2.E-06 2.E-02 1.E-07 6.E-01 9.E-06 3.E-01 4.E-06 2.E-01 3.E-06 Rounded value for final reporting

1.E+00 1.E+00 1.E+00 1.E-05 1.E+00 1.E-05 1.E+00 1.E-05 1.E+00 1.E-05 1.E+00 1.E-05 1.E+00 1.E-05 1.E+00 1.E-05 <<<GuidanceLevel

OK OK OK OK OK OK OK OK OK OK OK OK OK OK OK OK <<<OK or REFINE?

8.2E-01 2.5E-02 1.5E-01 2.8E-06 4.5E-01 5.9E-06 1.0E-01 1.7E-06 1.7E-02 1.3E-07 6.1E-01 8.7E-06 2.5E-01 4.5E-06 1.7E-01 2.9E-06 Calculated value for transparency and further calculation

Endpoint Acute SubchronicNoncancer

ChronicNoncancer

Respiratory 7.5E-01 2.1E-02 1.3E-01

Reproductive/developmental/endocrine/fetotoxicity

6.8E-02 2.6E-03 4.6E-03

Blood/hematological 0.0E+00 5.8E-05 1.1E-02

Neurological 6.7E-02 2.8E-03 2.0E-02

Eyes 6.9E-02 0.0E+00

Digestive 0.0E+00 4.9E-06

Bone & teeth 0.0E+00

Cardiovascular 7.4E-02 2.6E-03 4.6E-03

Kidney 0.0E+00 4.5E-03

Liver 0.0E+00 3.0E-07 9.7E-08

Skin 0.0E+00 3.7E-03

Ethanol specific 0.0E+00 0.0E+00

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

Level

OK OK OK <<<OK or REFINE?

Benzene noBromopropane, 1- no

Butadiene, 1,3- no

Carbon disulfide noCellosolve Acetate noChloroform no2-ethoxyethanol noEthylbenzene noEthyl chloride no2-methoxyethanol noTrichloroethylene noArsenic noCarbon tetrachloride noMercury noPropylene oxide no

Ceiling Values Exceeded?

Total Inhalation Screening Hazard Indices and Cancer Risks

Limited PTE

Total Indirect Pathway Screening Hazard Indices and Cancer Risks

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

Air Toxics Screen

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

Air Toxics Endpoint Refinement

Total Inhalation Screening Hazard Indices and Cancer Risks

Total Multipathway Screening Hazard Indices and Cancer Risks

Emissions type (PTE, Future Actual):

Mankato, MN

4911

6/12/201513000984198Mankato Energy Center

N:\Technical\1294 Calpine\35 - MEC Expansion\Phase 4c - Air Emissions Risk Analysis\RASS\Calpine_MEC_aq9-22.xlsm 1 of 14 10/23/2015 5:47 PM

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\Cal

pine

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C_a

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of 1

410

/23/

2015

5:

47 P

M

Em

issi

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ts m

ay b

e m

ade

in y

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on n

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Fac

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ID N

o.:

AQ

File

No.

:Fa

cilit

y N

ame:

Faci

lity

Loc

atio

n:SI

C C

ode

(Req

uire

d):

Em

issi

ons t

ype

(PT

E, F

utur

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Em

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002

SV00

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Man

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4198

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122-

66-7

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00

106-

89-8

Epi

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YE

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0000

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6-88

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0000

0014

0-88

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thyl

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0000

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0-41

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ben

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YE

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6076

360.

0721

056

0.31

5822

528

0.06

6624

0.29

1813

120

00

051

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6E

thyl

car

bam

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than

e)Y

ES

0.00

0000

75-0

0-3

Eth

yl c

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ide

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oroe

than

e)Y

ES

0.00

0000

97-6

3-2

E

thyl

Met

hacr

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NO

0.00

0000

106-

93-4

Eth

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0000

00

107-

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Eth

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0.00

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107-

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YE

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0000

0075

-21-

8E

thyl

ene

oxid

eY

ES

0.00

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96-4

5-7

Eth

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e th

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ES

0.00

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75-3

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YE

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6-44

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neY

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0.00

7550

0.00

0673

781

0.00

2951

160.

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70.

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9930

7

1101

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ydro

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0.00

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0-0

Form

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0051

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0002

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0009

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964

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6

Form

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1-30

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luta

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01-2

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col e

ther

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76-4

4-8

Hep

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lor

YE

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0010

24-5

7-3

Hep

tach

lor e

poxi

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00

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8-5

Hep

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47 P

M

Em

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ts m

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ate:

AQ

Fac

ility

ID N

o.:

AQ

File

No.

:Fa

cilit

y N

ame:

Faci

lity

Loc

atio

n:SI

C C

ode

(Req

uire

d):

Em

issi

ons t

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(PT

E, F

utur

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5

Man

kato

, MN

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Man

kato

Ene

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Cen

ter

4198

4911

1300

098

6756

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benz

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6,7,

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ES

0.00

0000

5567

3-89

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00

3582

2-46

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0.00

0000

118-

74-1

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achl

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0.00

0000

87-6

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608-

73-1

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chni

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319-

84-6

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achl

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00

319-

85-7

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achl

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ne, b

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0.00

0000

77-4

7-4

Hex

achl

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yclo

pent

adie

neY

ES

0.00

0000

00-0

8-3

Hex

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ll Is

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ES

0.00

0000

7064

8-26

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n,1,

2,3,

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0.00

0000

5711

7-44

-9H

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fura

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2,3,

6,7,

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ES

0.00

0000

7291

8-21

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exac

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ES

0.00

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6085

1-34

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ES

0.00

0000

00-0

8-2

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YE

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0000

00

3922

7-28

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exac

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4,7,

8-Y

ES

0.00

0000

5765

3-85

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exac

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odib

enzo

-p-d

ioxi

n,1,

2,3,

6,7,

8-Y

ES

0.00

0000

1940

8-74

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exac

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odib

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n,1,

2,3,

7,8,

9-Y

ES

0.00

0000

67-7

2-1

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achl

oroe

than

eY

ES

0.00

0000

822-

06-0

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amet

hyle

ne-1

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diis

ocya

nate

YE

S0.

0000

0011

0-54

-3H

exan

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5632

421.

0461

84.

50.

9798

84.

50.

1235

2941

20.

5410

5882

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1-78

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N:\T

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RA

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pine

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C_a

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2015

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47 P

M

Em

issi

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ts m

ay b

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on n

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5 st

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Scre

enin

g D

ate:

AQ

Fac

ility

ID N

o.:

AQ

File

No.

:Fa

cilit

y N

ame:

Faci

lity

Loc

atio

n:SI

C C

ode

(Req

uire

d):

Em

issi

ons t

ype

(PT

E, F

utur

e A

ctua

l):

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r)

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6/12

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5

Man

kato

, MN

Lim

ited

PTE

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kato

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Cen

ter

4198

4911

1300

098

302-

01-2

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razi

neY

ES

0.00

0000

1003

4-93

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7647

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0.00

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74-9

0-8

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7664

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ac

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0000

0077

83-0

7-5

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83-0

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n su

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0000

193-

39-5

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no(1

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neY

ES

0.00

4520

0.00

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1296

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4902

557

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3223

212

78-5

9-1

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3-0

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7439

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6243

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1508

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6606

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0317

9415

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0194

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0001

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7-6

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0058

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9Li

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0.00

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7-8

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YE

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0074

39-9

6-5

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gane

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ES

0.77

8005

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869

0.00

1344

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0074

39-9

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0009

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70.

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20.

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7075

11.

7843

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8152

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3156

9E-0

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ES

0.00

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126-

98-7

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NO

0.00

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67-5

6-1

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hano

lY

ES

0.00

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109-

86-4

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nol,

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onom

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0.00

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96-3

3-3

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74-8

3-9

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0-49

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71-5

5-6

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ES

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78-9

3-3

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C_a

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of 1

410

/23/

2015

5:

47 P

M

Em

issi

ons

Inpu

ts m

ay b

e m

ade

in y

ello

w c

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RA

SS v

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on n

umbe

r = 2

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5 st

acks

Scre

enin

g D

ate:

AQ

Fac

ility

ID N

o.:

AQ

File

No.

:Fa

cilit

y N

ame:

Faci

lity

Loc

atio

n:SI

C C

ode

(Req

uire

d):

Em

issi

ons t

ype

(PT

E, F

utur

e A

ctua

l):

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r)

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Em

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Em

issi

ons (

tpy)

SV00

7SV

002

SV00

3SV

009

Stac

k(s)

#1St

ack(

s)#2

Stac

k(s)

#3St

ack(

s)#4

6/12

/201

5

Man

kato

, MN

Lim

ited

PTE

Man

kato

Ene

rgy

Cen

ter

4198

4911

1300

098

108-

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Met

hyl i

sobu

tyl k

eton

e (H

exon

e)Y

ES

0.00

0000

624-

83-9

Met

hyl i

socy

anat

eY

ES

0.00

0000

80-6

2-6

Met

hyl m

etha

cryl

ate

YE

S0.

0000

0016

34-0

4-4

Met

hyl t

ert b

utyl

eth

erY

ES

0.00

0000

56-4

9-5

Met

hylc

hola

nthr

ene,

3-

YE

S0.

0000

0036

97-2

4-3

Met

hylc

hrys

ene,

5-

YE

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0000

00

101-

14-4

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hyle

ne b

is(2

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nilin

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4,4-

YE

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0000

0074

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Bro

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00

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Met

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ne c

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ide

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hlor

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ES

0.00

0000

101-

68-8

Met

hyle

ne d

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diis

ocya

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(MD

I)Y

ES

0.00

0000

101-

77-9

Met

hyle

nedi

anili

ne, 4

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YE

S0.

0000

0090

-94-

8M

ichl

er's

ket

one

NO

0.00

0000

1059

5-95

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- Nitr

osom

ethy

leth

ylam

ine

NO

0.00

0000

6472

4-95

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apht

ha, H

igh

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h A

rom

atic

(H

FAN

)

NO

0.00

0000

91-2

0-3

Nap

htha

lene

YE

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0622

910.

0034

2189

50.

0149

879

0.07

8983

431

0.04

7112

237

4.18

627E

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0.00

0183

359

1.71

637E

-06

7.51

771E

-06

193-

09-9

Nap

htho

[2,3

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yren

eY

ES

0.00

0000

7440

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0N

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lY

ES

0.01

9813

0.00

1695

853

0.00

7427

836

0.01

1964

859

0.01

1728

155

0.00

0144

118

0.00

0631

235

5.90

882E

-06

2.58

806E

-05

0-01

-5N

icke

l Com

poun

dsY

ES

0.00

0000

1313

-99-

1N

icke

l oxi

deY

ES

0.00

0000

0-02

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l ref

iner

y du

st fr

om th

e p y

rom

etal

lurg

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0000

0012

035-

72-2

Nic

kel s

ulfid

e (N

I3S

2)Y

ES

0.00

0000

7697

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2N

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0000

0060

2-87

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itroa

cena

phth

ene,

5-

YE

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0000

0010

0-01

-6

Nitr

oani

line,

4-

N

O0.

0000

0098

-95-

3N

itrob

enze

neY

ES

0.00

0000

7496

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8N

itroc

hrys

ene,

6-

YE

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0000

0060

7-57

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itrof

luor

ene,

2-

YE

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0000

0010

102-

44-0

Nitr

ogen

oxi

de (N

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NO

353.

1764

1034

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7589

416

6.78

1158

463

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6271

417

4.12

5239

42.

5211

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60.

2813

7254

91.

2324

1176

575

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5N

itrom

etha

neN

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0000

0079

-46-

9N

itrop

ropa

ne, 2

-N

O0.

0000

0055

22-4

3-0

Nitr

opyr

ene,

1-

YE

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0000

0057

835-

92-4

Nitr

opyr

ene,

4-

YE

S0.

0000

0015

6-10

-5N

itros

odip

heny

lam

ine,

p-

NO

0.00

0000

55-1

8-5

N-N

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odie

thyl

amin

eN

O0.

0000

00

N:\T

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Em

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Fac

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ID N

o.:

AQ

File

No.

:Fa

cilit

y N

ame:

Faci

lity

Loc

atio

n:SI

C C

ode

(Req

uire

d):

Em

issi

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(PT

E, F

utur

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S #

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Ann

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Em

issi

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tpy)

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Ann

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Em

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Em

issi

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tpy)

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SV00

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5

Man

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Lim

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PTE

Man

kato

Ene

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Cen

ter

4198

4911

1300

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62-7

5-9

N-N

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YE

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0000

0092

4-16

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0062

1-64

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lam

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NO

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0000

86-3

0-6

N-N

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lam

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NO

0.00

0000

59-8

9-2

N-N

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phol

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YE

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0000

0010

0-75

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idin

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0000

0011

1-84

-2N

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ane

NO

0.00

0000

3900

1-02

-0O

ctac

hlor

odib

enzo

fura

n,1,

2,3,

4,6,

7,8,

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0.00

0000

3268

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9O

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1002

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ll Is

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0000

5711

7-41

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5711

7-31

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0.00

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00-0

9-0

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ll Is

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sY

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0.00

0000

4032

1-76

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chlo

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0.00

0000

87-8

6-5

Pen

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phen

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0.00

0000

109-

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Pen

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00

00-0

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Pet

role

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lipha

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0.00

0000

85-0

1-8

Phe

nant

hren

eY

ES

0.05

5949

0.00

5191

426

0.02

2738

448

0.03

2683

714

0.03

3210

3710

8-95

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lY

ES

0.00

0000

75-4

4-5

Pho

sgen

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0000

7803

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2P

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0076

64-3

8-2

Pho

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0000

85-4

4-9

Pht

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0000

1336

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0000

00

3259

8-13

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77

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ES

0.00

0000

7036

2-50

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81

(3,4

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Te

trach

loro

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enyl

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ES

0.00

0000

3259

8-14

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105

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tach

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biph

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ES

0.00

0000

N:\T

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AQ

Fac

ility

ID N

o.:

AQ

File

No.

:Fa

cilit

y N

ame:

Faci

lity

Loc

atio

n:SI

C C

ode

(Req

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Em

issi

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Em

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Em

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SV00

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Man

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, MN

Lim

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Man

kato

Ene

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ter

4198

4911

1300

098

7447

2-37

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114

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Pen

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biph

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ES

0.00

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3150

8-00

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118

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Pen

tach

loro

biph

enyl

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ES

0.00

0000

6551

0-44

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123

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Pen

tach

loro

biph

enyl

)Y

ES

0.00

0000

5746

5-28

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CB

126

(3,3

,4,4

,5

Pen

tach

loro

biph

enyl

)Y

ES

0.00

0000

3838

0-08

04P

CB

156

(2,3

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H

exac

hlor

obip

hen y

l)Y

ES

0.00

0000

6978

2-90

-7P

CB

157

(2,3

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H

exac

hlor

obip

hen y

l)Y

ES

0.00

0000

5266

3-72

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167

(2,3

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H

exac

hlor

obip

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l)Y

ES

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0000

3277

4-16

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169

(3,3

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H

exac

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l) Y

ES

0.00

0000

3963

5-31

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189

(2,3

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Hep

tach

loro

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ES

0.00

0000

00-0

5-0

Pol

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0.00

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5-1

Pol

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8-0

Pol

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98-2

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Pol

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ES

0.00

0000

9016

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9P

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0077

58-0

1-2

Pot

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NO

0.00

0000

1120

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4P

ropa

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YE

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3-38

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ES

0.00

0000

115-

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Pro

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19.3

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2352

941

17.8

8070

588

78-8

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5345

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47 P

M

Em

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Scre

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ate:

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Fac

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ID N

o.:

AQ

File

No.

:Fa

cilit

y N

ame:

Faci

lity

Loc

atio

n:SI

C C

ode

(Req

uire

d):

Em

issi

ons t

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(PT

E, F

utur

e A

ctua

l):

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S #

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Em

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5

Man

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, MN

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Man

kato

Ene

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Cen

ter

4198

4911

1300

098

7782

-49-

2S

elen

ium

Y

ES

0.02

4700

1.93

812E

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8.48

896E

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0.05

6093

824

0.02

4615

266.

7529

4E-0

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Sel

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YE

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7631

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3-2

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0077

89-0

6-2

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0.00

0000

100-

42-5

Sty

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YE

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808-

79-8

Sul

fate

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0000

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6-33

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NO

0.00

0000

7664

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9S

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8014

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7S

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46-0

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176

6.89

5249

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396

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1688

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00

5120

7-31

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trach

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0.00

0000

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8-6

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1746

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6Te

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20-6

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127-

18-4

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ES

0.00

0000

811-

97-2

Tetra

fluor

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9-99

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trahy

drof

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NO

0.00

0000

62-5

5-5

Thio

acet

amid

eN

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0010

8-88

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luen

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2.49

3290

0.29

5674

667

1.29

5055

040.

2733

2666

71.

1971

708

0.00

0233

333

0.00

1022

9.56

667E

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Inputs may be made in yellow cells*RASS version number = 201405- 25 stacks

Screening Date:AQ Facility ID No.:AQ File No.:Facility Name:Facility Location:SIC Code (Required):Emissions type (PTE, Future

SV007 SV002 SV003 SV009

Lookup table notes Stack(s)#1 Stack(s)#2 Stack(s)#3 Stack(s)#4

Stack height (m) required for lookup (1-99 m) 60.96 60.96 30.48 4.572

Distance to property line or receptor (m) required for lookup (10-10000m) 54.46 98.7 123 126.3

1-hr dispersion value from Table automatic lookup 1.94156 3.916 75.81 6848.52446




Monthly dispersion value from Table automatic lookup 0.18179 0.34166 7.18641 57.36056

Annual dispersion value from Table automatic lookup 0.03462 0.1385 2.97885 27.46707

Batch Process (or other) notes Stack(s)#1 Stack(s)#2 Stack(s)#3 Stack(s)#4

1-hr dispersion value from batch process or other air dispersion modeling enter dispersion values manually 1.94 3.92 75.81 6848.52




Monthly dispersion value from batch process or other air dispersion modeling enter dispersion values manually 0.18 0.34 7.19 57.36

Annual dispersion value from batch processor other air dispersion modeling enter dispersion values manually 0.03 0.14 2.98 27.47

If the the batch process cells are filled in they are used preferentially over the lookup table values.

*Batch process (i.e., "Disperse") or other screening or refined air dispersion modeling is run separately and dispersion values are entered manually.

Limited PTE

Mankato, MN4911

6/12/201513000984198Mankato Energy Center

N:\Technical\1294 Calpine\35 - MEC Expansion\Phase 4c - Air Emissions Risk Analysis\RASS\Calpine_MEC_aq9-22.xlsm 14 of 14 10/23/2015 5:47 PM

Attachment 6: MPCA Mercury Risk Estimation

Method Spreadsheet

aq9-17.xls

MMREM: Minnesota Mercury Risk Estimation MethodCalculation of Local Mercury Hazard Quotients (HQ), due to fish contamination, from Mercury Emissions from a project.version 2.0 November 24, 2008 Direct any comments to Ed Swain [email protected]

Inputs are in blue and bold Calculated Outputs are in yellow Fixed assumptions are not colored

Facility Name:

Information on the water body for which these calculations are made:

Water body name County Name

MN DNR lake # (if available) (xx-yyyy)

Existing Ambient Fish

Concentration (mg/kg Hg)

Area of fishable waterbody (acres)

Area of rest of watershed

(acres)

Minnesota River Blue Earth NA 0.21 840 6,993 2

Mercury calculations for the increment due to the project:

Hg Species

Modeled Increment to

Mean Air Conc. μg/m3

Percent of each Mercury species

(%)Dep Velocity

(cm/sec)

Calculated Deposition Rate (flux) μg/m2-yr Area (acres)

Conversion factor (m2 / acre)

Annual Mass deposited (μg)

Annual Mass deposited (grams)

Fraction Reaching

Waterbody

Annual Mass reaching

waterbody (grams)

Average concentration over the lakeHg(II) 2.67E-07 30.0% 1.10 0.1 840 4046.9 3.1E+05 0.31 1.00 0.31Hg(0) 4.45E-07 50.0% 0.01 0.0 840 4046.9 4.8E+03 0.00 1.00 0.00Hg-p 1.78E-07 20.0% 0.05 0.0 840 4046.9 9.5E+03 0.01 1.00 0.01Total 8.90E-07 100.0% 0.1

Average concentration over the rest of the watershed (excluding the lake)Hg(II) 2.67E-07 30.0% 1.10 0.1 6,993 4046.9 2.6E+06 2.62 0.26 0.68Hg(0) 4.45E-07 50.0% 0.01 0.0 6,993 4046.9 4.0E+04 0.04 0.26 0.01Hg-p 1.78E-07 20.0% 0.05 0.0 6,993 4046.9 7.9E+04 0.08 0.26 0.02Total 8.90E-07 100.0% 0.1

Total Hg Mass Modeled to the Waterbody from Project Air Concentrations (Direct to Waterbody, plus 26% from Rest-of-Watershed) = 1.04

Mercury calculations for ambient condition (background), assuming no significant local source*:

Deposition rate (flux) μg/m2-yr Area (acres)


Annual mass deposited (μg)

Annual mass deposited (grams)

Fraction reaching

waterbody

Annual mass reaching

waterbody (grams)

Total deposition for the fishable waterbody12.5 840 4046.9 4.2E+07 42.49 1.00 42.49

Total deposition for the rest of the watershed12.5 6,993 4046.9 3.5E+08 353.75 0.26 91.97

Total Hg Mass Modeled to the Waterbody from Ambient Air Concentrations (Direct to Waterbody, plus 26% from Rest-of-Watershed) = 134.47

Fish Increment

Grams Hg to water body from project

Grams Hg to water body from

background

Incremental Hg in fish from project

(mg/kg)

Ratio of: Ambient fish Hg conc.

relative to WQ STD (0.2 mg/kg)

Ratio of: Incremental fish Hg conc. from project relative

to WQ STD

1.0 134.5 0.00 1.1 0.0

Subsistence Fisher Methylmercury Intake Calculations

Assumed daily fish consumed (kg)

Incremental daily Hg consumed

(mg)

Incremental daily HgCH3

consumed (mg) Body weight (kg)

Ambient HgCH3

Exposure mg/kg BW-day

Incremental HgCH3 Exposure mg/kg BW-day

RfD (mg HgCH3/kg bw-day)

Ambient Subsistence Fisher HQ

Incremental Subsistence Fisher HQ

0.142 0.0002 0.0002 70 4.58E-04 3.55E-06 1.00E-04 4.6 0.0

Recreational Fisher Methylmercury Intake Calculations



(mg)



Ambient HgCH3




Ambient Recreational Fisher HQ

Incremental Recreational Fisher HQ

0.03 0.0000 0.0001 70 9.67E-05 7.49E-07 1.00E-04 1.0 0.0

*The ambient condition is assumed to result from the following background air concentrations and deposition velocities:

Hg Species




(%)Dep Velocity

(cm/sec)

Calculated Deposition Rate (flux) μg/m2-yr

Fishable WaterbodyHg(II) 2.00E-05 1.2% 1.10 6.9Hg(0) 1.65E-03 97.6% 0.01 5.2Hg-p 2.00E-05 1.2% 0.05 0.3Total 1.69E-03 100.0% 12.5

Rest-of-Watershed (excluding waterbody)Hg(II) 2.00E-05 1.2% 1.10 6.9Hg(0) 1.65E-03 97.6% 0.01 5.2Hg-p 2.00E-05 1.2% 0.05 0.3Total 1.69E-03 100.0% 12.5

Recreational Fisher Hazard Quotient

Mankato Energy Center

Mercury Loading SummaryWater Quality Standard

Comparison

Subsistence Fisher Hazard Quotient

aq9-17.xls

MMREM: Minnesota Mercury Risk Estimation MethodCalculation of Local Mercury Hazard Quotients (HQ), due to fish contamination, from Mercury Emissions from a project.version 2.0 November 24, 2008 Direct any comments to Ed Swain [email protected]

Inputs are in blue and bold Calculated Outputs are in yellow Fixed assumptions are not colored

Facility Name:

Information on the water body for which these calculations are made:

Water body name County Name

MN DNR lake # (if available) (xx-yyyy)

Existing Ambient Fish

Concentration (mg/kg Hg)

Area of fishable waterbody (acres)

Area of rest of watershed

(acres)Total Mercury Conc

Hiniker Lake Blue Earth 07-014700 0.26 18 180 8.90E-07

Mercury calculations for the increment due to the project:

Hg Species




(%)Dep Velocity

(cm/sec)

Calculated Deposition Rate (flux) μg/m2-yr Area (acres)


Annual Mass deposited (μg)

Annual Mass deposited (grams)

Fraction Reaching

Waterbody

Annual Mass reaching

waterbody (grams)

Average concentration over the lakeHg(II) 2.67E-07 30.0% 1.10 0.1 18 4046.9 6.8E+03 0.01 1.00 0.01Hg(0) 4.45E-07 50.0% 0.01 0.0 18 4046.9 1.0E+02 0.00 1.00 0.00Hg-p 1.78E-07 20.0% 0.05 0.0 18 4046.9 2.1E+02 0.00 1.00 0.00Total 8.90E-07 100.0% 0.1

Average concentration over the rest of the watershed (excluding the lake)Hg(II) 2.67E-07 30.0% 1.10 0.1 180 4046.9 6.7E+04 0.07 0.26 0.02Hg(0) 4.45E-07 50.0% 0.01 0.0 180 4046.9 1.0E+03 0.00 0.26 0.00Hg-p 1.78E-07 20.0% 0.05 0.0 180 4046.9 2.0E+03 0.00 0.26 0.00Total 8.90E-07 100.0% 0.1

Total Hg Mass Modeled to the Waterbody from Project Air Concentrations (Direct to Waterbody, plus 26% from Rest-of-Watershed) = 0.03

Mercury calculations for ambient condition (background), assuming no significant local source*:

Deposition rate (flux) μg/m2-yr Area (acres)


Annual mass deposited (μg)

Annual mass deposited (grams)

Fraction reaching

waterbody

Annual mass reaching

waterbody (grams)

Total deposition for the fishable waterbody12.5 18 4046.9 9.2E+05 0.92 1.00 0.92

Total deposition for the rest of the watershed12.5 180 4046.9 9.1E+06 9.11 0.26 2.37

Total Hg Mass Modeled to the Waterbody from Ambient Air Concentrations (Direct to Waterbody, plus 26% from Rest-of-Watershed) = 3.28

Fish Increment

Grams Hg to water body from project

Grams Hg to water body from

background

Incremental Hg in fish from project

(mg/kg)

Ratio of: Ambient fish Hg conc.

relative to WQ STD (0.2 mg/kg)

Ratio of: Incremental fish Hg conc. from project relative

to WQ STD

0.0 3.3 0.00 1.3 0.0

Subsistence Fisher Methylmercury Intake Calculations



(mg)



Ambient HgCH3




Ambient Subsistence Fisher HQ

Incremental Subsistence Fisher HQ

0.142 0.0003 0.0003 70 5.56E-04 4.31E-06 1.00E-04 5.6 0.0

Recreational Fisher Methylmercury Intake Calculations



(mg)



Ambient HgCH3




Ambient Recreational Fisher HQ

Incremental Recreational Fisher HQ

0.03 0.0001 0.0001 70 1.17E-04 9.10E-07 1.00E-04 1.2 0.0

*The ambient condition is assumed to result from the following background air concentrations and deposition velocities:

Hg Species




(%)Dep Velocity

(cm/sec)

Calculated Deposition Rate (flux) μg/m2-yr

Fishable WaterbodyHg(II) 2.00E-05 1.2% 1.10 6.9Hg(0) 1.65E-03 97.6% 0.01 5.2Hg-p 2.00E-05 1.2% 0.05 0.3Total 1.69E-03 100.0% 12.5

Rest-of-Watershed (excluding waterbody)Hg(II) 2.00E-05 1.2% 1.10 6.9Hg(0) 1.65E-03 97.6% 0.01 5.2Hg-p 2.00E-05 1.2% 0.05 0.3Total 1.69E-03 100.0% 12.5

Mankato Energy Center

Mercury Loading SummaryWater Quality Standard

Comparison

Subsistence Fisher Hazard Quotient

Recreational Fisher Hazard Quotient

Attachment 7: ESA & NHPA Response Email from

U.S. EPA Region 5

1

Hanafy, Tarik (MPCA)

From: Kathryn S. Anderson <[email protected]>Sent: Tuesday, May 17, 2016 10:43 AMTo: Hanafy, Tarik (MPCA); Heidi WhiddenSubject: FW: Message from "R5-18-34"

Hi Tarik‐ Please find below the determinations from EPA Region 5 on the ESA and NHPA consultations. Jennifer Darrow from Region 5 determined below that no further action is needed on either assessment. Please let me know if you need anything further from us. Take care‐ Kathryn Anderson Principal / Air Quality Scientist [email protected] | D 651.294.4593 | C 651.324.8053 1802 Wooddale Drive | Woodbury, MN 55125 ‐‐‐‐‐Original Message‐‐‐‐‐ From: Darrow, Jennifer [mailto:[email protected]] Sent: Tuesday, May 17, 2016 10:27 AM To: Kathryn S. Anderson Subject: RE: Message from "R5‐18‐34" ESA : For this permit action, a response from a threatened or endangered species to an environmental stressor is unlikely. Therefore, no further consultation is necessary under Section 7 of the Endangered Species Act. NHPA: Section 106 of the National Historic Preservation Act allows the Federal Agency initiating the action to determine if an undertaking is likely to affect historic properties. If the undertaking is not the type of activity likely to affect historic properties, then the responsible Federal agency has no further obligation under Section 106. For this permit action, US EPA has determined that the undertaking is not likely to affect historic properties and no further action is required under Section 106 of the NHPA. If there are any questions regarding these determinations, please let me know. Jennifer Darrow ‐‐‐‐‐Original Message‐‐‐‐‐ From: Kathryn S. Anderson [mailto:[email protected]] Sent: Monday, May 16, 2016 10:32 AM To: Darrow, Jennifer <[email protected]> Subject: RE: Message from "R5‐18‐34" Hi Jennifer‐

2

I just wanted to check in on the streamlined bat consultation for Mankato Energy Center. I believe you indicated that was a 30 day review from your colleague. I apologize if I have that timing incorrect. I was also checking on the National Historical Preservation Act review. Thank you for all of your help! Take care‐ Kathryn Anderson Principal / Air Quality Scientist [email protected] | D 651.294.4593 | C 651.324.8053 1802 Wooddale Drive | Woodbury, MN 55125 ‐‐‐‐‐Original Message‐‐‐‐‐ From: Darrow, Jennifer [mailto:[email protected]] Sent: Thursday, April 14, 2016 1:05 PM To: Horton, Andrew Cc: Kathryn S. Anderson Subject: FW: Message from "R5‐18‐34" Andrew ‐ Please see the attached streamlined bat consultation form for a proposed project in Mankato, Minnesota. If you have any questions or concerns please let me know. Jennifer Darrow Air Permits Section Air and Radiation Division US EPA, Region 5 ‐‐‐‐‐Original Message‐‐‐‐‐ From: R5‐18‐[email protected] [mailto:R5‐18‐[email protected]] Sent: Thursday, April 14, 2016 12:40 PM To: Darrow, Jennifer <[email protected]> Subject: Message from "R5‐18‐34" This E‐mail was sent from "R5‐18‐34" (Aficio MP 6001). Scan Date: 04.14.2016 13:40:20 (‐0400) Queries to: R5‐18‐[email protected]

Attachment 8: BACT Analysis

November 2015 3-1 \\woodbury-dc1\woodbury\Technical\1294 Calpine\35 - MEC Expansion\Phase 2a - Prepare Air Permit Amendment\Air Permit Application\Text\MEC II Air Emissions Permit Major Amendment App Text 11 02 15.docx

3.0 Best Available Control Technology Determination

The Expansion Project is subject to PSD review for emissions of NOx, CO, PM/PM10/PM2.5, VOC and GHG. These regulations require MEC II to complete a case-by-case BACT determination for each piece of equipment associated with the Expansion Project that has the potential to emit air pollutants subject to PSD. This section documents the BACT determination for each piece of equipment associated with the Expansion Project that has the potential to emit NOx, CO, PM/PM10/PM2.5, VOC and GHG. 3.1 BACT DEFINITION BACT is defined in 40 CFR 52.21(j) BACT as follows:

“an emission limitation (including a visible emission standard) based on the maximum degree of reduction of each air pollutant subject to regulation under the Clean Air Act which would be emitted from any proposed major stationary source or major modification which the Administrator, on a case-by-case basis, taking into account energy, environmental and economic impacts, and other costs, determines is achievable for such source or modification through application of production processes or available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of such pollutant…”

BACT has been determined using Environmental Protection Agency’s (EPA’s) top-down approach. Following the top-down approach, progressively less stringent control technologies are analyzed until a level of control considered BACT is reached on the basis of environmental, energy, and economic impacts. The steps involved, include:

Step 1 - Identify applicable options; Step 2 - Eliminate technically infeasible options; Step 3 - Rank remaining alternatives by control effectiveness; Step 4 - Evaluate most effective controls; and Step 5 - Select BACT

In determining BACT for the emission units included this project, information from the following sources were evaluated:

On-line EPA RACT/BACT/LAER Clearinghouse (RBLC) System and other state BACT control technology databases; EPA/State/Local Air Quality Permits and Applications; Control Technology Vendors; AP-42-Section 3.1 Stationary Gas Turbines for Electricity Generation; and Alternative Control Techniques Document – NOx emissions form Stationary Gas Turbines EPA-453/R-93-007.

The following sections outline the results of the evaluations to determine BACT for the various emissions units associated with the Expansion Project.


3.2 BACT DETERMINATION FOR COMBINED CYCLE COMBUSTION TURBINE/HRSG OPERATION The Expansion Project will install an additional natural gas fired combustion turbine equipped with DLN burners. The turbine will exhaust to a separate HRSG which is equipped with an 824 MMBtu/hr natural gas only duct burner. MEC II is proposing to install downstream from the HRSG an SCR system to reduce NOx emissions, and a catalytic oxidizer to reduce CO and VOC emissions. A summary of recent BACT determinations, including those for ancillary equipment, is included in Appendix B.

3.2.1 Control of Oxides of NOx Emissions A top-down evaluation of NOx control technologies revealed that DLN burners and SCR are equivalent to the best available control alternatives for natural gas-fired combined cycle units. Both of these technologies will be applied to the proposed expansion at MEC II. The proposed NOx emission performance levels are as follows:

3.0 ppmvd @ 15% O2 for natural gas combustion with DLN burner technology, low-NOx duct burners and SCR technology.

The operating temperatures within combustion turbine burner systems result in the formation of NOx emissions. Thermal NOx and fuel NOx are the two primary NOx formation mechanisms in combustion turbines. Thermal NOx is formed by the dissociation of atmospheric nitrogen and oxygen in the turbine combustor and the subsequent formation of NOx. When fuels containing nitrogen are combusted this additional source of nitrogen results in fuel NOx formation. Thermal NOx is the dominant mechanism for NOx emissions for the proposed turbine because natural gas fuel contains little or no nitrogen. The formation rate of thermal NOx increases exponentially with an increase in temperature. The following technologies were identified as potentially able to control NOx emissions from stationary combined-cycle combustion turbines:

DLN burner technology; Wet controls – water and steam injection; Rich/Quench/Lean (RQL) combustion; SCR; Selective Non-catalytic reduction (SNCR); EMx, formerly SCONOXTM catalytic oxidation/absorption; and Catalytic combustion – XONONTM

3.2.1.1 Technical Feasibility of NOx Control Alternatives The previously referenced information resources were consulted to determine the extent of applicability or each identified control alternative. Combustion Turbine DLN Burner Technology DLN burners use an advanced combustion design to suppress NOx formation and/or promote CO burnout while firing natural gas. The technology can include a lower combustion temperature with lean mixtures of air and fuel, staged premix combustion, or decreased residence time. For turbines such as those proposed for the Expansion Project, DLN burners can achieve 25 ppm NOx without the addition of any further controls. As


discussed earlier, MEC II is proposing a turbine equipped with the DLN burner technology, which will be utilized while firing natural gas. Wet Combustion – Water or Steam Injection Water or steam injection into the flame area of the turbine combustor lowers the flame temperature and reduces the formation of thermal NOx. A water injection system consists of a water treatment system, pump(s), water metering valves and instrumentation, turbine-mounted injection nozzles, and piping. Water or steam injection can control NOx concentrations to 25 ppm at 15 percent O2 for natural gas combustion and 42 ppm for distillate fuel oil combustion. The water-to-fuel ratio (WFR) is the most important factor affecting performance of this control technology and varies by manufacturer and model. Because the proposed turbine will be equipped with DLN burners that generate NOx levels equivalent to what is attainable with wet control, this control technology will be eliminated from further consideration in the BACT determination for natural gas firing. The existing combustion turbine utilizes water injection to control NOx emissions when combusting distillate fuel oil. Because the proposed turbine will only fire natural gas, water injection is not required and would not provide any additional control. Rich/Quench/Lean (RQL) Combustion RQL combustors burn fuel-rich in the primary zone and fuel-lean in the secondary zone. Incomplete combustion under fuel-rich conditions in the primary zone produces an atmosphere with a high concentration of CO and hydrogen. The CO and hydrogen replace some of the oxygen normally available for NOx formation and also act as reducing agents for any NOx formed in the primary zone. Thus fuel nitrogen is released with minimal conversion to NOx. The lower peak flame temperatures due to partial combustion also reduce the formation of thermal NOx. As the combustion products leave the primary zone, they are cooled through rapid dilution and combustion is completed under fuel-lean conditions. Thermal NOx is minimized during lean combustion because of the low flame temperature. As indicated in the Alternative Control Techniques (ACT) document, RQL combustors are not commercially available for most turbine designs. Therefore because it is not technically feasible, this control alternative utilizing RQL combustion is eliminated from further consideration in this BACT determination. Selective Catalytic Reduction (SCR) SCR can be installed in HRSGs to control NOx emissions from the combustion turbines and duct burners. Anhydrous ammonia is injected into the flue gas stream, upstream of the SCR catalyst bed, where it mixes with the NOx to form molecular nitrogen and water. The reactions take place on the surface of the catalyst. The function of the catalyst is to effectively lower the activation energy required for the NOx decomposition reactions. Depending on system design and the inlet NOx level, NOx removal of up to 70-90 percent is achievable at optimum theoretical conditions. Depending on the catalyst, NOx reduction occurs within a reaction window of 400 to 1100 degrees Fahrenheit. The design of the HRSG allows for catalyst installation in the optimum temperature zone. As stated earlier MEC II is proposing to install SCR to reduce NOx emissions from the combustion turbine and duct burner system. Selective Non-Catalytic Reduction (SNCR) SNCR technology involves using ammonia or urea injection similar to SCR technology but at a higher temperature window of 1600 to 2200 degrees Fahrenheit, without the use of a


catalyst. In certain applications the low end of the operating temperature window can be reduced from 1600 to 1300 degrees Fahrenheit. However, outside of the temperature limits the ammonia can be converted to NOx, resulting in an increase in NOx emissions. Because the exhaust temperatures in combustion turbines typically do not exceed 1250 degrees Fahrenheit, the operative temperature window of this control alternative is not technically feasible in this application. The exhaust temperature is typically around 1150 degrees Fahrenheit at the combustion turbine exit during steady state conditions and 200 degrees Fahrenheit at the exhaust stack, which is less than the acceptable range for SNCR application. Additionally, this technology requires a residence time of approximately 100 milliseconds. This is relatively slow for exhaust gas operating velocities. Thus there may not be adequate residence time for the NOx destruction chemical reaction. Furthermore, a review of the RBLC database for recent BACT/Lowest Achievable Emission Rate (LAER) determinations did not indicate that SNCR systems have been successfully installed for NOx control for similar combined-cycle units. For the above reasons, SNCR will no longer be considered for this analysis because it is not technically feasible for the size of the proposed unit. EMx (Formerly SCONOx ) Catalytic Oxidation/Absorption EMx is a trade name for a proprietary experimental NOx control technology being marketed by EmeraChem, LLC (formerly Goal Line Technologies). EMx guarantees NOx emission concentration of 2 ppmv based on an inlet NOx concentration of 25 ppm. The technology works by allowing the exhaust gases to react with potassium carbonate that is coated on a platinum catalyst surface. The CO is oxidized to CO2 and exhausted out the stack. The NO is oxidized to NO2 and then reacts with the potassium carbonate absorber coating on the catalyst to form potassium nitrites and nitrates at the catalyst surface until the catalyst requires regeneration. The EPA Region IX issued a letter dated March 23, 1998, indicating that emissions data from Sunlaw’s Federal Cogeneration facility in Vernon, California has “demonstrated in practice” NOx emissions at or below 2.0 ppm (3-hour average) using SCONOx . Although this letter is not a Federal LAER determination, the letter does state that future projects subject to LAER should evaluate this technology for feasibility of application. The South Coast Air Quality Management District (SCAQMD) of California also adopted (effective June 12, 1998) a “BACT” guideline for gas turbines less than 50 MW equal to 2.5 ppm at 15 percent O2 (1-hour average corrected for efficiency) based on SCONOx technology. However in Appendix B of a document titled Supporting Material for BACT Review for Electrical Generation Technologies (July 23, 2001), SCAQMD recognized that this technology has not been applied to larger turbines such as those proposed by MEC II when the agency stated the following:

“Because the technology has not been demonstrated for all sizes of turbines, the ARB staff is not considering the SCONOx technology for the purposes of establishing guideline levels”.

In preparation of the Existing Facility 2004 PSD application, ABB Alstom Power was contacted as the license holder of this technology for turbines of similar size to those proposed for the Expansion Project. According to Noel Kuch of ABB Alstom, the largest turbine that this technology has been commercially installed on is 43 MW.


In addition to the scale-up concern, there is also significant energy impacts associated with this application of EMx

TM technology. There is a power output penalty, and a fuel penalty associated with the use of the catalyst. The increased backpressure in the turbine from the catalyst installation increases the heat input required and reduces the power output of the turbine. EMx technology has been used to define LAER in non-attainment areas in smaller (32 MW systems). EMx can match the performance of SCR without the ammonia slip; however, catalyst must be regenerated periodically while online using hydrogen produced by a natural gas reforming unit, making this technology not cost effective when compared to SCR. No RBLC entries for permits issued after 2006 have listed SCONOx as BACT. The proposed unit will be equipped with a combination DLN Combustor technology as well as SCR (equivalent control technology) which is capable of reducing emissions to an equivalent level; therefore EMx will be eliminated from consideration in the BACT analysis. Catalytic Combustion – XONONTM

Another new NOx control technology being developed is catalytic combustion. Catalytic combustion minimizes peak temperatures and NOx formation. The XONONTM system is being developed for commercial application by Catalytic Combustion Systems to utilize this technology. Their system includes a pre-burner, a fuel injection and mixing system, a flameless catalyst module and a flameless burnout zone. The pre-burner starts the turbine and a fuel injection system provides a uniform fuel and air mixture to the catalyst, where a portion of the fuel is combusted at reduced temperature to reduce thermal NOx emissions. The remainder of the fuel is combusted in the burnout zone with minimal NOx emissions. The technology has only been tested in small turbines (less than 10 MW) and it is not commercially available for the proposed turbine size. Although the vendor is in the process of developing the technology for larger units, the complete application is believed to be years away from development. Until such time that the technology is commercially available, catalytic combustors are not considered technically feasible. In view of this limitation, utilizing catalytic combustor control is eliminated from further consideration in this BACT determination. 3.2.1.2 Proposal for NOx BACT for the Combustion Turbine/HRSG Various control alternatives were reviewed for technical feasibility in controlling NOx emissions from the proposed combustion turbine/HRSG train. Combustion control utilizing the DLN combustor technology based on lean premix combustion controls and SCR (both of which are proposed for implementation) is equivalent to the highest ranking control technology. As stated previously, the existing technology for MEC I is a Siemens Westinghouse FD-2 combustion turbine which is no longer a standard offering from the manufacturer. It is preferable that the Expansion Project use a gas turbine technology with similar performance and exhaust gas characteristics to provide stable and reliable combined cycle operation, since the existing and new combustion turbine/HRSG trains will be operating in parallel to supply steam to the existing steam turbine. In order to provide a combustion turbine with comparable operating characteristics, MEC II has the following procurement options:

a unit from the gray market, an original manufacturer equipment (OEM) off-market unit built from spare components, or a newer unit, slightly de-rated to the match the performance of the existing unit.


Each of these options has long term reliability concerns which could affect the emissions performance. A combustion gas turbine with latest available technology could offer lower emissions, supporting a BACT limit of 2 ppm NOx at the stack. However, the turbine would have to be significantly de-rated to match the existing equipment, negating the performance and efficiency benefits that would otherwise justify its purchase. In addition, operating a modern combustion turbine at a significant de-rating could cause stability and reliability issues when in parallel with the existing combustion turbine/HRSG train. Calpine believes that using a combustion turbine technology similar to the existing equipment for the new expansion is an economically viable option that will provide reliable operation over the life of the plant. In conclusion, BACT for the proposed natural gas-fired combustion turbine/HRSG is the following:

3.0 ppmvd using a 3-hour block average @ 15% O2 for natural gas combustion with DLN burner technology, low NOx duct burners, and SCR technology. This limit does not apply during startup, shutdown, malfunction, tuning, and combustion turbine shakedown

MEC II is proposing BACT limits that apply during startup and shutdown operation. These limits are described in further detail in Section 4. Definitions for combustion turbine shakedown and tuning are also provided in Section 4. 3.2.2 Control of CO Emissions MEC II proposes to install a catalytic oxidizer to decrease CO emissions. The proposed CO emission rates for the combustion turbine/HRSG emission source including the duct burner are as follows:

4 ppmvd using a 3-hour block average @ 15% O2 (while operating at normal turbine base load capacity) and 4.7 ppmvd using a 3-hour block average @ 15% O2 (while operating at load conditions less than the turbine base load capacity) for natural gas combustion with DLN burner technology, low NOx duct burners, and catalytic oxidizer.

Normal turbine base load capacity is defined as 90% or greater of capacity for the ambient conditions. Less than turbine base load capacity is defined as greater than or equal to 60% capacity to less than 90% of rated capacity for the ambient conditions. CO emissions from any combustion process are formed due to incomplete combustion of the fuel. Typically, CO emissions from combustion sources depend on the oxidation efficiency of the fuel. By controlling the combustion process carefully, CO emissions can be minimized. The DLN system used during natural gas firing achieves low NOx emissions at high efficiency and with no water consumption by optimizing the combustion to produce a lower flame temperature. CO emissions are also reduced through more thorough mixing of fuel and air in the DLN burner, which promotes more complete combustion. Additionally, the HRSG duct burners employ good combustion practices to further minimize the formation of CO emissions.


A review of the RBLC database shows that two types of CO control technologies have been proposed for combined-cycle applications. The technologies available include the following:

Combustion control, and Catalytic oxidizer.

3.2.2.1 Technical Feasibility of CO Control Alternatives Combustion Control CO is formed due to incomplete combustion or inefficient combustion of the fuel. Improperly tuned turbines operating at off-design levels decrease combustion efficiency, increasing CO emissions. By controlling the combustion process carefully, the generation of CO emissions can be minimized. Improved mixing of fuel and air in the proposed DLN combustors and HRSG duct burners promotes complete combustion of the fuel, which minimizes CO emissions. Catalytic Oxidizer In addition to good combustion control the proposed HRSG will be equipped with a catalytic oxidizer. A catalytic oxidizer removes CO from the combustion turbine and duct burner exhaust gas. The technology does not require introduction of additional chemicals for the reaction to proceed. The oxidation of CO to CO2 uses the excess air present in the turbine exhaust and the activation energy required for the reaction to proceed is lowered in the presence of the catalyst. The catalytic oxidizer is considered the most stringent level of control for combustion turbines similar to the proposed MEC II turbine—capable of oxidizing 80 to 90 percent of the inlet CO concentration. 3.2.2.2 Proposal for CO BACT for the Combustion Turbine/HRSG Both of the available alternatives for controlling CO emissions will be applied to the proposed combustion turbine/HRSG train. The catalytic oxidizer represents the most effective level of control. Furthermore, it will not result in any significant impacts of unregulated air pollutants or unreasonable impacts in other media. Because MEC II is proposing to install a catalytic oxidizer to control CO emissions from the combustion turbine and duct burner, and a catalytic oxidizer results in the greatest control effectiveness, no further analysis is required under a top down BACT analysis. BACT for controlling CO emissions is proposed as follows:

4 ppmvd using a 3-hour block average @15% O2 (while operating at normal base load conditions) and 4.7 ppmvd using a 3-hour block average @ 15% O2 (while operating at load conditions less than the turbine base load capacity) for natural gas combustion with DLN technology, low NOx duct burners, and catalytic oxidizer. This limit does not apply during startup, shutdown, malfunction, tuning, and combustion turbine shakedown.

MEC II is proposing BACT limits that apply during startup and shutdown operation. These limits are described in further detail in Section 4. Similar to the discussion in the NOX BACT section above, the existing technology for MEC I is a Siemens Westinghouse FD-2 combustion turbine which is no longer a standard offering from the manufacturer. It is preferable that the Expansion Project use a gas turbine technology with similar performance and exhaust gas characteristics to provide stable and reliable combined cycle operation, since the existing and new combustion turbine/ HRSG trains will be operating in parallel to supply steam to the existing steam turbine.


A combustion gas turbine with latest available technology could offer lower emissions, supporting a lower BACT limit at the stack. However, the turbine would have to be significantly de-rated to match the existing equipment, negating the performance and efficiency benefits that would otherwise justify its purchase. In addition, operating a modern combustion turbine at a significant de-rating could cause stability and reliability issues when in parallel with the existing combustion turbine/HRSG train. 3.2.3 Control of VOC Emissions Similar to CO emissions, VOC emissions are formed in any combustion process due to incomplete combustion of the fuel. The VOCs may consist of a wide spectrum of volatile and semi-volatile organic compounds. By controlling the combustion process carefully, VOC emissions can be minimized. As stated earlier, MEC II is proposing to install a catalytic oxidizer to reduce CO emissions from the turbines. These systems will also reduce VOC emissions from the turbine. The proposed VOC emission rates for the turbine/HRSG emission source are as follows:

3.4 ppmvd using a 3-hour block average @ 15% O2 for natural gas combustion with DLN burner technology, low NOx duct burners, and catalytic oxidizer.

Based on a review of the RBLC database, it was shown that two types of VOC control technologies have been proposed for combined-cycle applications. The technologies available include the following:

Combustion control, and Catalytic oxidizer.

3.2.3.1 Technical Feasibility of VOC Control Alternatives Combustion Control VOCs are formed due to incomplete combustion or inefficient combustion of the fuel. Improperly tuned turbines operating at off-design levels decrease combustion efficiency, increasing VOC emissions. By controlling the combustion process carefully, the generation VOC emissions can be minimized. Catalytic Oxidizer In addition to good combustion control the proposed turbines will be equipped with a catalytic oxidizer. A catalytic oxidizer serves to remove VOCs from the combustion turbine/duct burner exhaust gas. The technology does not require introduction of additional chemicals for the reaction to proceed. The oxidation of VOCs uses the excess air present in the turbine exhaust and the activation energy required for the reaction to proceed is lowered in the presence of the catalyst. The catalytic oxidizer is considered the most stringent level of control for turbines similar to the proposed MEC II turbine. 3.2.3.2 Proposal for VOC BACT for the Combustion Turbine/HRSG Both of the available control alternatives for controlling VOC emissions will be applied to the proposed combustion turbine/HRSG train. The catalytic oxidizer represents the most effective level of control. Furthermore, it will not result in any significant impacts of unregulated air pollutants or unreasonable impacts in other media. Because MEC II is proposing to install a catalytic oxidizer to control CO and VOC emissions from the new


combustion turbine and duct burner, and an oxidation catalyst systems results in the greatest control effectiveness, no further analysis is required under a top down BACT analysis. BACT for controlling VOC emissions is proposed as:

3.4 ppmvd using a 3-hour block average @ 15% O2 for natural gas combustion with DLN burner technology, low NOx duct burners, and catalytic oxidizer. This limit does not apply during startup, shutdown, malfunction, tuning, and combustion turbine shakedown.

MEC II is proposing BACT limits that apply during startup and shutdown operation. These limits are described in further detail in Section 4. 3.2.4 Control of PM/PM10/PM2.5 Emissions PM may be formed from non-combustible constituents in fuel or combustion air, from products of incomplete combustion, or from post-combustion formation of ammonium sulfates in units with an SCR. All of the particulate emissions from the combustion turbine are assumed be in the form of PM10 and PM2.5. The proposed PM emission limits are based on vendor data and operating experience at MEC and other units in Calpine’s fleet. Good combustion control is regarded as BACT for PM/PM10/PM2.5. Add-on controls are technically and economically infeasible due to the high flow rates, very low concentrations of PM/PM10/PM2.5, and the extremely small particle diameters. Mankato Energy is not aware of any combined cycle project that has been required to install add-on PM/PM10/PM2.5 controls. The proposed PM/PM10/PM2.5 emission rate for the proposed combustion turbine/HRSG emission source is 11.9 lb/hr using a 3-hour block average for natural gas firing. Potential Combined Cycle Unit PM/PM10/PM2.5 Control Alternatives Based on a review of the RBLC database and the references listed earlier the following PM/PM10/PM2.5 control technologies are available to potentially control emissions from combined cycle units:

Fuel specifications: clean burning fuel; Good combustion practices/combustion control; and Low-sulfur fuel.

3.2.4.1 Technical Feasibility of PM/PM10/PM2.5 Control Alternatives Fuel Specifications: Clean Burn Fuel MEC II is proposing to burn pipeline-quality natural gas. Among traditional fuels natural gas is considered a clean burning fuel since it has a very low potential for generating particulates. The RBLC database indicates that pipeline-quality natural gas is the clean burning fuel of choice for similar combined cycle applications. Good Combustion Practice/Combustion Control Based upon a review of the RBLC, good combustion practice is listed as a control alternative for many similar combined cycle applications. MEC II will maintain the combustion turbines in good working order in accordance with manufacturers’ guidance and implement good combustion practices to minimize particulate emissions. As discussed earlier, the proposed


combustion turbine will be equipped with DLN burners that will also contribute towards good combustion practice and further help lower particulate emissions. The Expansion Project’s combustion turbine will burn natural gas only. The sulfur content of natural gas will not exceed 0.8 grains per 100 standard cubic feet of gas. 3.2.4.2 Proposed PM/PM10/PM2.5 BACT for the Combustion Turbine/HRSG Various control alternatives were reviewed for technical feasibility in controlling PM/PM10/PM2.5 emissions from the proposed turbine/HRSG. The proposed combustion turbine will use a combination of all of the above control alternatives in order to provide the best available particulate control. In conclusion, BACT for controlling PM/PM10/PM2.5 emissions from the proposed turbine is proposed as the maintenance of the turbine/HRSGs in good working order, implementation of good combustion practices with DLN burner technology, and use of clean-burning natural gas fuel as the only fuel to meet a PM/PM10/PM2.5 emission rate of 11.9 lb/hr using a 3 hour block average. This limit will apply at all times including during startup, shutdown, or malfunction. This limit will not apply prior to combustion turbine shakedown which is further defined in Section 4. 3.2.5 Control of Greenhouse Gas (GHG) Emissions

3.2.5.1 Available GHG Control Technologies Inherently Lower-Emitting Processes/Practices/Designs

MEC II performed a search of the EPA’s RACT/BACT/LAER Clearinghouse for natural gas fired combustion turbine generators in combined cycle operation and found no entries which address BACT for GHG emissions. Calpine has permitted several units under GHG BACT regulations. Those analyses determined that BACT for GHG emissions was maintenance of the high energy efficiency that is inherent with natural gas fired combined cycle power plants. GHG BACT permit conditions were established which set an efficiency limit (also referred to as heat rate) appropriate for each particular combination of gas turbine, heat recovery steam generator, and steam turbine model. The net heat rate was based on a design base load rate, without duct firing with factors added to account for a design margin and degradation. A summary of available, lower greenhouse gas emitting processes, practices, and designs for combined cycle units is presented below. 3.2.5.1.1 Combined Cycle Energy Efficiency Processes, Practices, and Combustion Turbine Design CO2 is a product of combustion of fuels containing carbon, which is inherent in any power generation technology using fossil fuel. It is not possible to reduce the amount of CO2 generated from combustion, as CO2 is the essential product of the chemical reaction between the fuel and the oxygen in which it burns, not a byproduct caused by imperfect combustion. As such, there is no technology available that can effectively reduce CO2 generation by adjusting the conditions in which combustion takes place.


The only effective means to reduce the amount of CO2 generated by a fuel-burning power plant is to generate as much electric power as possible from the combustion, thereby reducing the amount of fuel needed to meet the plant’s required power output. This result is obtained by using the most efficient generating technologies available, so that as much of the energy content of the fuel as possible goes into generating power. The most efficient way to generate electricity from a natural gas fuel source is the use of a combined cycle design. For fossil fuel technologies, efficiency ranges from approximately 30-50% (higher heating value [HHV]). A typical coal-fired Rankine cycle power plant has a base load efficiency of approximately 30% (HHV), while a modern F-Class natural gas fired combined cycle unit operating under optimal conditions has a baseload efficiency of approximately 50% (HHV). Combined cycle units operate based on a combination of two thermodynamic cycles: the Brayton and the Rankine cycles. A combustion turbine operates on the Brayton cycle and the HRSG and steam turbine operate on the Rankine cycle. The combination of the two thermodynamic cycles allows for the high efficiency associated with combined cycle plants. The technology proposed for the additional combustion turbine at MEC II has not been chosen but will be ”F” Class combustion turbine technology. In addition to the high-efficiency primary components of the turbine, there are a number of other design features employed within the combustion turbine that can improve the overall efficiency of the machine. These additional features include those summarized below. Periodic Burner Tuning Modern F-Class combustion turbines have regularly scheduled maintenance programs. These maintenance programs are important for the reliable operation of the unit, as well as to maintain optimal efficiency. As the combustion turbine is operated, the unit experiences degradation and loss in performance. The combustion turbine maintenance program helps restore the recoverable lost performance. The maintenance program schedule is determined by the number of hours of operation and/or turbine starts. There are three basic maintenance levels, commonly referred to as combustion inspections, hot gas path inspections, and major overhauls. Combustion inspections are the most frequent of the maintenance cycles. As part of this maintenance activity, the combustors are tuned to restore highly efficient low-emission operation. Reduction in Heat Loss Modern F-Class combustion turbines have high operating temperatures. The high operating temperatures are a result of the heat of compression in the compressor along with the fuel combustion in the burners. To minimize heat loss from the combustion turbine and protect the personnel and equipment around the machine, insulation blankets are applied to the combustion turbine casing. These blankets minimize the heat loss through the combustion turbine shell and help improve the overall efficiency of the machine. Instrumentation and Controls Modern F-Class combustion turbines have sophisticated instrumentation and controls to automatically control the operation of the combustion turbine. The control system is a digital type and is supplied with the combustion turbine. The distributed control system (DCS) controls all aspects of the turbine’s operation, including the fuel feed and burner operations, to achieve efficient low-NOX combustion. The control system monitors the operation of the unit and modulates the fuel flow and turbine operation to achieve optimal high-efficiency low-emission performance for full-load and part-load conditions.


3.2.5.2 Heat Recovery Steam Generator Energy Efficiency Processes, Practices, and Designs

The HRSG takes waste heat from the combustion turbine exhaust and uses it to convert boiler feed water to steam. Duct burning involves burning additional natural gas in the ducts to the heat recovery boiler, which increases the temperature of the exhaust coming from the combustion turbines and thereby creates additional steam for the steam turbine. The modern F-Class combustion turbine-based combined cycle HRSG is generally a horizontal natural circulation drum-type heat exchanger designed with three pressure levels of steam generation, reheat, split superheater sections with interstage attemperation, post-combustion emissions control equipment, and condensate recirculation. The HRSG is designed to maximize the conversion of the combustion turbine exhaust gas waste heat to steam for all plant ambient and load conditions. Maximizing steam generation will increase the steam turbine’s power generation, which maximizes plant efficiency. Heat Exchanger Design Considerations HRSGs are heat exchangers designed to capture as much thermal energy as possible from the combustion turbine exhaust gases. This is performed at multiple pressure levels. For a drum type configuration, each pressure level incorporates an economizer section(s), evaporator section, and superheater section(s). These heat transfer sections are made up of many thin walled tubes to provide surface area to maximize the transfer of heat to the working fluid. Most of the tubes also include extended surfaces (e.g., fins). The extended surface optimizes the heat transfer, while minimizing the overall size of the HRSG. Additionally, flow guides are used to distribute the flow evenly through the HRSG to allow for efficient use of the heat transfer surfaces and post-combustion emissions control components. Low-temperature economizer sections employ recirculation systems to minimize cold-end corrosion, and stack dampers are used for cycling operation to conserve the thermal energy within the HRSG when the unit is off line. Insulation HRSGs take waste heat from the combustion turbine exhaust gas and uses that waste heat to convert boiler feed water to steam. As such, the temperatures inside the HRSG are nearly equivalent to the exhaust gas temperatures of the turbine. For F-Class combustion turbines, these temperatures can approach 1250°F. HRSGs are designed to maximize the conversion of the waste heat to steam. One aspect of the HRSG design in maximizing this waste heat conversion is the use of insulation. Insulation minimizes heat loss to the surroundings, thereby improving the overall efficiency of the HRSG. Insulation is applied to the HRSG panels that make up the shell of the unit, to the high-temperature steam and water lines, and typically to the bottom portion of the stack. Minimizing Fouling of Heat Exchange Surfaces HRSGs are made up of a number of tubes within the shell of the unit that are used to generate steam from the combustion turbine exhaust gas waste heat. To maximize this heat transfer, the tubes and their extended surfaces need to be as clean as possible. Fouling of the tube surfaces impedes the transfer of heat. Fouling occurs from the constituents within the exhaust gas stream. To minimize fouling, filtration of the inlet air to the combustion turbine is performed. Additionally, cleaning of the tubes is performed during periodic outages. By reducing the fouling, the efficiency of the unit is maintained.


Minimizing Vented Steam and Repair of Steam Leaks As with all steam-generated power facilities, minimization of steam vents and repair of steam leaks is important in maintaining the plant’s efficiency. A combined cycle facility has just a few locations where steam is vented from the system, blowdown tank vents and vacuum pumps/steam jet air ejectors. These vents are necessary to improve the overall heat transfer within the HRSG and condenser by removing solids and air that potentially blankets the heat transfer surfaces lowering the equipment’s performance. Additionally, power plant operators are concerned with overall efficiency of their facilities. Therefore, steam leaks are repaired as soon as possible to maintain facility performance. Minimization of vented steam and repair of steam leaks will be performed for this project. 3.2.5.2.1 Plant-wide Energy Efficiency Processes, Practices, and Designs

There are a number of other components within the combined cycle plant that help improve overall efficiency, including:

Fuel gas preheating – The overall efficiency of the combustion turbine is increased with increased fuel inlet temperatures. For the F-Class combustion turbine based combined cycle unit, the fuel gas is generally heated with high temperature water from the HRSG. This improves the efficiency of the combustion turbine. Drain operation – Drains are required to allow for draining the equipment for maintenance (i.e., maintenance drains), and also to allow condensate to be removed from the steam piping and drains for operation (i.e., operation drains). Operation drains are generally controlled to minimize the loss of energy from the cycle. This is accomplished by closing the drains as soon as the appropriate steam conditions are achieved. Multiple combustion turbine/HRSG trains – Multiple combustion turbine/HRSG trains help with part-load operation. The multiple trains allow the unit to achieve higher overall plant part-load efficiency by shutting down trains operating at less efficient part-load conditions and ramping up the remaining train(s) to high-efficiency full-load operation. Boiler feed pump fluid drives – The boiler feed pumps are used as the means to impart high pressure on the working fluid. The pumps require considerable power. To minimize the power consumption at part-loads, the use of fluid drives or variable-frequency drives can be employed. For this project, fluid drives are being used to minimize power consumption at part-load, improving the facility’s overall efficiency.

3.2.5.2.2 Add-On Controls

In addition to power generation process technology options discussed above, it is appropriate to consider add-on technologies as possible ways to capture GHG emissions that are emitted from natural gas combustion in the proposed Expansion Project’s CTG/HRSG unit and to prevent them from entering the atmosphere. These emerging carbon capture and storage (CCS) technologies generally consist of processes that separate CO2 from combustion process flue gas, and then inject it into geologic formations such as oil and gas reservoirs, unmineable coal seams, and underground saline formations. Of the emerging CO2 capture technologies that have been identified, only amine absorption is currently commercially used for state-of-the-art CO2 separation processes. Amine absorption has been applied to processes in the petroleum refining and natural gas processing industries and for exhausts from gas-fired industrial boilers. Other potential absorption and membrane technologies are currently considered developmental.


The U.S. Department of Energy’s National Energy Technology Laboratory (DOE-NETL) provides the following brief description of state-of-the-art post-combustion CO2 capture technology and related implementation challenges:

…In the future, emerging R&D will provide numerous cost-effective technologies for capturing CO2 from power plants. At present, however, state-of-the-art technologies for existing power plants are essentially limited to amine absorbents. Such amines are used extensively in the petroleum refining and natural gas processing industries… Amine solvents are effective at absorbing CO2 from power plant exhaust streams—about 90 percent removal—but the highly energy-intensive process of regenerating the solvents decreases plant electricity output…1

The DOE-NETL adds:

…Separating CO2 from flue gas streams is challenging for several reasons: CO2 is present at dilute concentrations (13-15 volume percent in coal-fired systems and 3-4 volume percent in gas-fired turbines) and at low pressure (15-25 pounds per square inch absolute [psia]), which dictates that a high volume of gas be treated. Trace impurities (particulate matter, sulfur dioxide, nitrogen oxides) in the flue gas can degrade sorbents and reduce the effectiveness of certain CO2 capture processes. Compressing captured or separated CO2 from atmospheric pressure to pipeline pressure (about 2,000 psia) represents a large auxiliary power load on the overall power plant system…2

If CO2 capture can be achieved at a power plant, it would need to be routed to a geologic formation capable of long-term storage. The long-term storage potential for a formation is a function of the volumetric capacity of a geologic formation and CO2 trapping mechanisms within the formation, including dissolution in brine, reactions with minerals to form solid carbonates, and/or adsorption in porous rock. The DOE-NETL describes the geologic formations that could potentially serve as CO2 storage sites as follows: “Geologic carbon dioxide (CO2) storage involves the injection of supercritical CO2 into deep geologic formations (injection zones) overlain by competent sealing formations and geologic traps that will prevent the CO2 from escaping. Current research and field studies are focused on developing better understanding of 11 major types of geologic storage reservoir classes, each having their own unique opportunities and challenges. Understanding these different storage classes provides insight into how the systems influence fluids flow within these systems today, and how CO2 in geologic storage would be anticipated to flow in the future. The different storage formation classes include: deltaic, coal/shale, fluvial, alluvial, strandplain, turbidite, eolian, lacustrine, clastic shelf, carbonate shallow shelf, and reef.

1 DOE-NETL, Carbon Sequestration: FAQ Information Portal, http://extsearch1.netl.doe.gov/search?q=cache:e0yvzjAh22cJ:www.netl.doe.gov/technologies/carbon_seq/FAQs/te ch-status.html+emerging+R%26D&access=p&output=xml_no_dtd&ie=UTF-8&client=default_frontend&site=default_collection&proxystylesheet=default_frontend&oe=ISO-8859-1 (last visited Aug. 8, 2011). 2 Id.


Basaltic interflow zones are also being considered as potential reservoirs. These storage reservoirs contain fluids that may include natural gas, oil, or saline water; any of which may impact CO2 storage differently…”3 3.2.5.3 Step 2: Eliminate Technically Infeasible Options

In this section, Mankato Energy addresses the potential feasibility of implementing CCS technology as BACT for GHG emissions from the proposed project’s gas turbine/HRSG train. Each component of CCS technology (i.e., capture and compression, transport, and storage) is discussed separately.

3.2.5.3.1 CO2 Capture and Compression

Though amine absorption technology for CO2 capture has been applied to processes in the petroleum refining and natural gas processing industries and to exhausts from gas-fired industrial boilers, it is not yet commercially available for power plant gas turbine exhausts, which have considerably larger flow volumes and considerably lower CO2 concentrations. The Obama Administration’s Interagency Task Force on Carbon Capture and Storage confirms this in its recently completed report on the current status of development of CCS systems: “Current technologies could be used to capture CO2 from new and existing fossil energy power plants; however, they are not ready for widespread implementation primarily because they have not been demonstrated at the scale necessary to establish confidence for power plant application. Since the CO2 capture capacities used in current industrial processes are generally much smaller than the capacity required for the purposes of GHG emissions mitigation at a typical power plant, there is considerable uncertainty associated with capacities at volumes necessary for commercial deployment.”4 3.2.5.3.2 CO2 Transport

Even if it is assumed that CO2 capture and compression could feasibly be achieved for the proposed project, the high-volume CO2 stream generated would need to be transported to a facility capable of storing it. There are no potential geologic storage sites in in Minnesota or the Midwest to which CO2 could be transported if a pipeline was constructed. The current CO2 pipelines are shown in Figure 3-1 on the map found at the end of Section 3.5 Therefore, in order to access any potentially large-scale storage capacity site, assuming that it is eventually demonstrated to indefinitely store a substantial portion of the large volume of CO2 generated by the proposed project, a very long and sizable pipeline would need to be constructed to transport the large volume of high-pressure CO2 from the plant to the storage facility, thereby rendering implementation of a CO2 transport system infeasible.

3.2.5.3.3 CO2 Storage

Even if it is assumed that CO2 capture and compression could feasibly be achieved for the proposed project and that the CO2 could be transported economically, the feasibility of CCS technology would still depend on the availability of a suitable sequestration site. The 3 DOE-NETL, Carbon Sequestration: Geologic Storage Focus Area,http://www.netl.doe.gov/technologies/carbon_seq/corerd/storage.html (last visited Aug.8, 2011) 4 Report of the Interagency Task Force on Carbon Capture and Storage at 50 (Aug. 2010). 5 Denbury Resources, 2012, “CO2 Transportation,” Investor Slides, April, 2012, 25p.


suitability of potential storage sites is a function of volumetric capacity of their geologic formations, CO2 trapping mechanisms within formations (including dissolution in brine, reactions with minerals to form solid carbonates, and/or adsorption in porous rock), and potential environmental impacts resulting from injection of CO2 into the formations. Potential environmental impacts resulting from CO2 injection that still require assessment before CCS technology can be considered feasible include:

uncertainty concerning the significance of dissolution of CO2 into brine, risks of brine displacement resulting from large-scale CO2 injection, including a pressure leakage risk for brine into underground drinking water sources and/or surface water, risks to fresh water as a result of leakage of CO2, including the possibility for damage to the biosphere, underground drinking water sources, and/or surface water,6 and potential effects on wildlife.

Potentially suitable storage sites, including EOR sites and saline formations, exist in Iowa and Illinois. Figure 3-2 shows possible storage sites7. However, there are no pipelines that connect to these formations. Based on the reasons provided above, Calpine believes that CCS technology should be eliminated from further consideration as a potential feasible control technology for purposes of this BACT analysis. However, to answer possible questions that the public or the EPA may have concerning the relative costs of implementing hypothetical CCS systems, Calpine has estimated such costs. Those cost estimates are presented on Table 3-1 at the end of Section 3. 3.2.5.4 Step 3: Rank Remaining Control Technologies

As documented above, implementation of CCS technology is currently infeasible, leaving energy efficiency measures as the only technically feasible emission control options. As all of the energy efficiency related processes, practices, and designs discussed in Section 3.2.5.1 of this application are being proposed for this project, a ranking of the control technologies is not necessary for this application. 3.2.5.5 Step 4: Evaluate Most Effective Controls and Document Results

As all of the energy efficiency related processes, practices, and designs discussed in Section 3.2.5.1 of this application are being proposed for this project, an examination of the energy, environmental, and economic impacts of the efficiency designs is not necessary for this application. Because the CCS add-on control option discussed in Section 3.2.5.2 was determined to be technically infeasible, an examination of the energy, environmental, and economic impacts of that option is not necessary for this application. However, MEC II is including estimated costs for implementation of CCS.

6 Id. 7 Exhibit 36, Current State and Future Direction of Coal-fired Power in the Eastern Interconnection, Final Study

Report June 2013


3.2.5.6 Step 5: Select BACT

MEC II proposes as BACT for this project, the following energy efficiency processes, practices, and designs for the proposed combined cycle combustion turbine:

Use of Combined Cycle Power Generation Technology Combustion Turbine Energy Efficiency Processes, Practices, and Designs

o Efficient turbine design o Turbine inlet air cooling o Periodic turbine burner tuning o Reduction in heat loss o Instrumentation and controls

HRSG Energy Efficiency Processes, Practices, and Designs o Efficient heat exchanger design o Insulation of HRSG o Minimizing fouling of heat exchange surfaces o Minimizing vented steam and repair of steam leaks

Plant-wide Energy Efficiency Processes, Practices, and Designs o Fuel gas preheating o Drain operation o Multiple combustion turbine/HRSG trains o Boiler feed pump fluid drive design

Calpine calculated the design base load net heat rate without duct firing for the 1 x 1 Expansion Project combined cycle plant using the new CTG/HRSG train and the existing steam turbine. A compliance margin was applied based upon reasonable degradation factors that may foreseeably reduce efficiency under real world conditions. The design base load net heat rate for the proposed 1 X 1 combined cycle unit without duct firing is 7,075 Btu/kW-hr (HHV) without the application of degradation factors. Note that this rate reflects the facility’s “net” power production, meaning the denominator is the amount of power provided to the grid; it does not reflect the total amount of energy produced by the plant, which also includes auxiliary load consumed by operation of the plant. To determine an appropriate heat rate, the following compliance margins are added to the base heat rate value:

A 3.3% design margin reflecting the possibility that the constructed facility will not be able to achieve the design heat rate. A 6% performance margin reflecting efficiency losses due to equipment degradation prior to maintenance overhauls. A 3% degradation margin reflecting the variability in operation of auxiliary plant equipment due to use over time.

These factors are consistent with the compliance margin factors used in previous Calpine GHG BACT analyses. As a result of these adjustments, MEC II is proposing a BACT net heat rate for the Project of 7,979 Btu/kWh (HHV), corrected to the following conditions of:

Ambient Dry Bulb Temperature: 6ºF Ambient Relative Humidity: 59% Barometric Pressure: 14.28 psia Fuel Lower Heating Value: 21,500 Btu/lb Fuel HHV/LHV Ratio: 1.109


A GHG BACT limit of 1,000 lb/MW-hr on a gross power production basis is proposed based on 1 X 1 combined cycle operation. Calpine is proposing a heat rate demonstration test 180 days after first fire and again prior to obtaining a new permit to verify compliance with the heat rate limit. Although derived from a slightly less efficient operating mode, this limit will account for the range of possible MEC operating scenarios. The calculation of the net heat rate is provided on Table 3-2 at the end of this section. 3.3 BACT DETERMINATION FOR THE DIESEL ENGINE-DRIVEN EMERGENCY EQUIPMENT The proposed diesel fired emergency generator will be used for emergency situations, if any. However, the diesel engine-driven equipment will be operated for a minimal period on a bi-weekly basis for testing. 3.3.1 Control of NOx Emissions from Emergency-Use Diesel Engines As a result of the intended use of the proposed diesel fired emergency generator and subsequent limited operation, allowable NOx emissions from these units are minimal with an emission rate of 0.66 tons/yr. Based on a review of similar emission sources associated with recent power plant projects, these types of emission sources typically do not have add-on controls but should be operated according to the manufacturer’s specifications. Therefore, for the proposed diesel fired emergency equipment, BACT for controlling NOx emissions is proposed as maintenance in good working order, operation according to the manufacturer’s specifications and limiting non-emergency operation of the diesel engine to 100 hours per year. 3.3.2 Control of CO Emissions from Emergency-Use Diesel Engines Again, as a result of the intended use of the proposed diesel fired emergency generator and subsequent limited operation, allowable CO emissions from these units are minimal with an emission rate of 0.66 tons/yr. Based on a review of similar emission sources associated with recent power plant projects, these types of emission sources typically do not have add-on controls but should be operated according to the manufacturer’s specifications. Therefore, for the proposed diesel fired emergency equipment, BACT for controlling CO emissions is proposed as maintenance in good working order, operation according to the manufacturer’s specifications, and limiting non-emergency operation of the diesel engine to 100 hours per year. 3.3.3 Control of VOC Emissions from the Emergency-Use Diesel Engines The allowable VOC emissions from the proposed diesel fired emergency generator are minimal with a limited emission rate of 0.04 tons/yr. MEC II completed a review of similar emission sources associated with recent power plant projects. It was determined that these types of emission sources typically do not have add-on controls but should be operated according to the manufacturer’s specifications. Therefore, for the proposed diesel fired emergency generator, BACT for controlling VOC emissions is proposed as maintenance in good working order, operation according to the manufacturer’s specifications, and limiting non-emergency operation of the diesel engine to 100 hours per year.


3.3.4 Control of PM/PM10/PM2.5 Emissions from the Emergency-Use Diesel Engines The allowable PM/PM10/PM2.5 emissions from the proposed diesel fired emergency generator are minimal with a limited emission rate of 0.01 tons/yr. Based on a review of similar emission sources associated with recent power plant projects, these types of emission sources typically do not have add-on controls but should be operated according to the manufacturer’s specifications. Therefore, for the proposed diesel fired emergency generator, BACT for controlling particulate matter emissions is proposed as maintenance in good working order, operation according to the manufacturer’s specifications, and limiting non-emergency operation of the diesel engine to 100 hours per year. 3.3.5 Control of GHG Emissions from the Emergency-Use Diesel Engines Similar to the pollutants above, as a result of the intended use of the proposed diesel fired emergency generator and subsequent limited operation, allowable CO2e emissions from these units are minimal with an emission rate of 208 tons/yr. Generators of this size typically do not have add-on controls but should be operated according to the manufacturer’s specifications. Therefore, for the proposed diesel fired emergency equipment, BACT for controlling greenhouse gas emissions is proposed as maintenance in good working order, operation according to the manufacturer’s specifications, and limiting non-emergency operation of the diesel engine to 100 hours per year. 3.4 BACT DETERMINATION FOR THE COOLING TOWER The existing cooling tower is used for temperature management of process water for the installation. The 4 new cells will accommodate the additional cooling requirements of the expanded combined cycle unit. Projected annual emissions are minimal with an estimated emission rate of 6.58 tons per year for total particulate, 0.64 tons per year for PM10, and 0.01 tons per year for PM2.5 for the 4 additional cells. Based on a review of similar projects, cooling towers associated with combined cycle power plants are equipped with high efficiency mist eliminators. The existing cooling tower and proposed additional cooling tower cells will incorporate a mist eliminator (0.0005% tower drift rate). In conclusion, BACT for controlling PM/PM10/PM2.5 emissions for the proposed additional cooling tower cells is the use of a mist eliminator and maintenance of the fans and equipment in good working order and operation according to the manufacturer’s specifications with an estimated PM/PM10/PM2.5 emissions rates of 6.58 tons per year, 0.64 tons per year, and 0.01 tons per year, respectively. 3.5 BACT DETERMINATION FOR THE DIESEL FUEL STORAGE TANKS The proposed diesel fired emergency generator will be equipped with its own diesel storage tank. The tank will have a capacity of less than 6,000 gallons and will be used to store diesel fuel. Due to the low volatility of this material, potential VOC emissions are anticipated to be negligible. Based on a search of the RBLC, no control is proposed for this source. BACT is proposed as using a fixed roof tank and maintaining the tank in good working condition. 3.6 BACT DETERMINATION FOR NATURAL GAS PIPING FOR GHG EMISSIONS Natural gas is delivered to the site via pipeline. Gas will be metered and piped to the new combustion turbine and duct burner. Project GHG fugitive emissions from the natural gas


piping components associated with the new CT/HRSG train will include emissions of methane (CH4) and carbon dioxide (CO2). 3.6.1 Step 1: Identify All Available Control Technologies The following technologies were identified as potential control options for piping fugitives:

Implementation of leak detection and repair (LDAR) program using a hand held analyzer; Implementation of alternative monitoring using a remote sensing technology such as infrared cameras; and Implementation of audio/visual/olfactory (AVO) leak detection program.

The use of instrument LDAR and remote sensing technologies are technically feasible. Since pipeline-quality natural gas is odorized with a small amount of mercaptan, an AVO leak detection program for natural gas piping components is technically feasible. 3.6.2 Step 2: Eliminate Technically Infeasible Options There are no technically infeasible control options. 3.6.3 Step 3: Rank Remaining Control Technologies The use of a LDAR program with a portable gas analyzer meeting the requirements of 40 CFR 60, Appendix A, Method 21, can be effective for identifying leaking methane. The U.S. EPA has allowed the use of an optical gas imaging instrument as an alternative work practice for a Method 21 portable analyzer for monitoring equipment for leaks in 40 CFR 60.18(g). For components containing inorganic or odorous compounds, periodic AVO walk-through inspections provide predicted control efficiencies of 97% control for valves, flanges, relief valves, and sampling connections, and 95% for compressors. 3.6.4 Step 4: Evaluate Most Effective Controls and Document Results The frequency of inspection and the low odor threshold of mercaptans in natural gas make AVO inspections an effective means of detecting leaking components in natural gas service. The predicted emission control efficiency is comparable to the LDAR programs using Method 21 portable analyzers. 3.6.5 Step 5: Select BACT Any leak detection program implemented would be solely due to potential greenhouse gas emissions. Since the uncontrolled CO2e emissions from the natural gas piping represent approximately 0.01% of the total site-wide CO2e emissions, any emission control techniques applied to the piping fugitives will provide minimal CO2e emission reductions. Quarterly AVO inspections are proposed as BACT. 3.7 BACT DETERMINATION FOR ELECTRICAL EQUIPMENT INSULTATED WITH SF6 The generator circuit breakers associated with the proposed unit will be electrically insulated using SF6 gas. SF6 is a colorless, odorless, non-flammable, and non-toxic synthetic gas. It is a fluorinated compound that has an extremely stable molecular structure. The unique chemical properties of SF6 make it an efficient electrical insulator. The gas is used for


electrical insulation, arc quenching, and current interruption in high-voltage electrical equipment. SF6 is only used in sealed and safe systems which under normal circumstances do not leak gas. As part the Expansion Project, two new SF6 breakers will be installed. The new combustion turbine generator circuit breaker will contain approximately 35 lbs of SF6 gas. An additional breaker containing approximately 72 lbs of SF6 will be installed between the combustion turbine generator step-up transformer and the 115kV transmission line. Both proposed circuit breakers will be equipped with low pressure alarms and low pressure lockouts. The alarms will alert operating personnel of any leakage in the system and the lockout prevents any operation of the breaker due to lack of “quenching and cooling” SF6 gas. 3.7.1 Step 1: Identify All Available Control Technologies Step 1 of the Top-Down BACT analysis is to identify all feasible control technologies. One technology is the use of state-of-the-art SF6 technology with leak detection to limit fugitive emissions. In comparison to older SF6 circuit breakers, modern breakers are designed as a totally enclosed-pressure system with far lower potential for SF6 emissions. In addition, the effectiveness of leak-tight closed systems can be enhanced by equipping them with a density alarm that provides a warning when 10% of the SF6 (by weight) has escaped. The use of an alarm identifies potential leak problems before the bulk of the SF6 has escaped, so that it can be addressed proactively in order to prevent further release of the gas. One alternative considered in this analysis is to substitute another, non-greenhouse-gas substance for SF6 as the dielectric material in the breakers. Potential alternatives to SF6 were addressed in the National Institute of Standards and Technology (NTIS) Technical Note 1425, Gases for Electrical Insulation and Arc Interruption: Possible Present and Future Alternatives to Pure SF6.8

3.7.2 Step 2: Eliminate Technically Infeasible Options According to the report NTIS Technical Note 1425, SF6 is a superior dielectric gas for nearly all high voltage applications.9 It is easy to use, exhibits exceptional insulation and arc-interruption properties, and has proven its performance by many years of use and investigation. It is clearly superior in performance to the air and oil insulated equipment used prior to the development of SF6 -insulated equipment. The report concluded that although “…various gas mixtures show considerable promise for use in new equipment, particularly if the equipment is designed specifically for use with a gas mixture… it is clear that a significant amount of research must be performed for any new gas or gas mixture to be used in electrical equipment.” Therefore, there are currently no technically feasible options besides use of SF6. 3.7.3 Step 3: Rank Remaining Control Technologies The use of state-of-the-art SF6 technology with leak detection to limit fugitive emissions is the highest ranked control technology that is technically feasible for this application.

8 Christophorous, L.G., J.K. Olthoff, and D.S. Green, Gases for Electrical Insulation and Arc Interruption: Possible Present and Future Alternatives to Pure SF6, NIST Technical Note 1425, Nov.1997. 9 Id. at 28 – 29.


3.7.4 Step 4: Evaluate Most Effective Controls and Document Results Energy, environmental, or economic impacts were not addressed in this analysis because the use of alternative, non-greenhouse-gas substance for SF6 as the dielectric material in the breakers is not technically feasible. 3.7.5 Step 5: Select BACT Based on this top-down analysis, MEC II concludes that using state-of-the-art enclosed-pressure SF6 circuit breakers with leak detection would be the BACT control technology option. The circuit breakers will be designed to meet the latest of the American National Standards Institute (ANSI) C37.013 standard for high voltage circuit breakers.10 The proposed circuit breakers at the generator output and the step-up transformer output will have low pressure alarms and low pressure lockouts. These alarms will function as early leak detectors that will bring potential fugitive SF6 emissions problems to light before a substantial portion of the SF6 escapes. The lockouts prevent any operation of the breakers due to lack of “quenching and cooling” SF6 gas. The Expansion Project will also complete monthly inspections of the pressure of the breakers. 3.8 BACT DETERMINATION FOR THE CONDENSATE TANK The Expansion Project is proposing to install a small condensate tank. The condensate tank will emit a small amount of VOC. The use of the condensate tank will be minimal and on a batch cycle. The tank will have a capacity of less than 50 gallons. Due to the low volatility of this material; potential VOC emissions are anticipated to be negligible. Based on a search of the RBLC, no control is proposed for this source. BACT is proposed as maintaining the tank in good working condition. 3.9 BACT SUMMARY The emission limitations that are proposed to represent BACT for the emission units associated with the Facility are summarized in Table 3-1.

10 ANSI Standard C37.013, Standard for AC High-Voltage Generator Circuit Breakers on a Symmetrical Current

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.21

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tant

:N

Ox

Prop

osed

NO

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mit:

3PP

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%O

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lent

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0111

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Com

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tion

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Lim

itEm

issi

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mit

Uni

t

Emis

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itAv

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me

Cond

ition

Case

ByCa

seBa

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Stan

dard

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Lim

it

Stan

dard

Emis

sion

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itU

nit

Stan

dard

Lim

itAv

erag

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me

Cond

ition

Addi

tiona

lPer

mit

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itN

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*TX07

67LO

NC.HILL

POWER

STAT

ION

LONC.HILL,L.P.

1149

11AN

DPSDT

X138

010

/6/201

5Co

mbine

dCycle

Turbines

(>25

MW)

naturalgas

195MW

SelectiveCatalytic

Redu

ction

2PP

MRO

LLING24

HRAV

ERAG

EBA

CTPSD

Twopo

wer

configurationop

tions

authorize

dSiem

ens

–24

0MW

+25

0millionBritish

thermalun

itspe

rho

ur(M

MBtu/hr)d

uctb

urne

rGE–19

5MW

+67

0MMBtu/hr

ductbu

rne r

*TX07

14

SRBE

RTRO

NELEC

TRIC

GENER

ATINGSTAT

IONNRG

TEXA

SPO

WER

LLC

1027

31PSDT

X129

412

/19/20

14(2)com

bine

dcycle

turbines

naturalgas

240MW

SelectiveCatalytic

Redu

ction

2PP

MVD

@15

%O2,24

HRRO

LLING

AVER

AGE

BACT

PSD

0

(1)T

woSiem

ensM

odelF5

(SF5)C

TGse

achratedat

nominalcapabilityof

225megaw

atts(M

W).Each

CTGwillhave

adu

ctfired

HRSG

with

amaxim

umhe

atinpu

tof6

88millionBritish

thermalun

itspe

rho

ur(M

MBtu/hr).

(2)T

woGe

neralElectric

Mod

el7FA(GE7FA

)CTG

seach

ratedat

nominalcapabilityof

215MW.Each

CTGwillhave

adu

ctfired

HRSG

with

amaxim

umhe

atinpu

tof5

23MMBtu/hr.

(3)T

woMitsub

ishiH

eavy

Indu

stry

GFram

e(M

HI50

1G)C

TGse

achratedat

ano

minalelectric

output

of26

3MW.Each

CTGwillhave

adu

ctfired

HRSG

with

amaxim

umhe

atinpu

tof6

86MMBtu/hr.

*CO00

76PU

EBLO

AIRP

ORT

GENER

ATINGSTAT

IONBLAC

KHILLSELEC

TRIC

GENER

ATION,LLC

09PB

0591

12/11/20

14Four

combine

dcycle

combu

tionturbines

naturalgas

373mmbtu/hr

each

SCRanddrylowNOxbu

rners

8LB/HR

4HR

ROLLING

AVE/

STAR

TUPAN

DSH

UTD

OWN

BACT

PSD

0

GE,LM60

00PF,naturalgasfire

d,combine

dcycle

combu

stionturbine

5PP

M,vdat

15%O2.

Unitsare

smallerthanCalpine'sp

ropo

sedun

it.Therefore,

limits

willno

tbeconsidered

anyfurthe

r .

*TX07

10VICT

ORIAPO

WER

STAT

ION

VICT

ORIAWLE

L.P.

1082

58PSDT

X134

812

/1/201

4combine

dcycleturbinenaturalgas

197MW

SelectiveCatalytic

Redu

ction

2PP

MVD

@15

%O2,24

HRRO

LLING

AVER

AGE

BACT

PSD

0

Unitsareno

tthe

samemanufacturer.Therefore,the

BACT

emissionlim

itisno

tapp

licableandwillno

tbe

considered

anyfurthe

r .

*WV00

25

MOUNDS

VILLE

COMBINED

CYCLE

POWER

PLAN

TMOUNDS

VILLEPO

WER

,LLC

R1400

3011

/21/20

14Co

mbine

dCycle

Turbine/Du

ctBu

rne r

NaturalGa

s21

59mmBtu/Hr

SCR&DryLow

NOxBu

rners

15.2

LB/HR

BACT

PSD

2PP

M@

15%O2

Unitsareno

tthe


BACT

emissionlim

itisno

tapp

licableandwillno

tbe

considered

anyfurthe

r .

*TX07

12TR

INIDAD

GENER

ATINGFA

CILITY

SOUTH

ERNPO

WER

COMPA

NY

1113

93PSDT

X136

811

/20/20

14combine


497MW

SelectiveCatalytic

Redu

ction

2PP

MVD

@15

%O2,24

HRRO

LLING

AVER

AGE

BACT

PSD

0

Unitsareno

tthe


BACT

emissionlim

itisno

tapp

licableandwillno

tbe

considered

anyfurthe

r .

*TX06

89

CEDA

RBA

YOU

ELEC

TRIC

GENER

ATION

STAT

ION

NRG

TEXA

SPO

WE R

1058

10,

PSDT

X130

88/29

/201

4Co

mbine

dcyclenatural

gasturbine

sNaturalGa

s22

5MW

DLN,SCR

2PP

M24

HRRO

LLINGAV

G.BA

CTPSD

0Siem

ensM

odelF5,G

E7Fa,and

Mitsub

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eavy

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e

*TX06

78

FREEPO

RTLN

GPR

ETRE

ATMEN

TFA

CILIT Y

FREEPO

RTLN

GDE

VELO

PMEN

TLP

1048

40N17

0PSDT

X130

27/16

/201

4Co

mbu

stionTurbine

naturalgas

87MW

SelectiveCatalytic

Redu

ction

2PP

MVD

15@

O2,3

HOUR

ROLLING

AVER

AGE

BACT

PSD

0Manufactureru

nkno

wn .

*TX07

13

TENAS

KABR

OWNSV

ILLE

GENER

ATINGSTAT

IONTENAS

KABR

OWNSV

ILLE

PART

NER

S,LLC

1084

11PSDT

X135

04/29

/201

4(2)com

bine

dcycle

turbines

naturalgas

274MW

SelectiveCatalytic

Redu

ction

2PP

MVD

@15

%O2,24

HRRO

LLING

AVER

AGE

BACT

PSD

0Manufactureru

nkno

wn .

*IA01

07MAR

SHALLTOWN

GENER

ATINGSTAT

IONINTERSTA

TEPO

WER

AND

LIGH

T13

A49

9P

4/14

/201

4Co

mbu

stionturbine#1

combine

dcycle

naturalgas

2258

mmBtu/hr

Low

NOxbu

rnersa

ndSCR

2PP

M

30DA

YRO

LLINGAV

G.@15

%O2

BACT

PSD

0Siem

ens5

01FD

orF4.

*IA01

07MAR

SHALLTOWN

GENER

ATINGSTAT

IONINTERSTA

TEPO

WER

AND

LIGH

T13

A49

9P

4/14

/201

4Co

mbu

stionturbine#2

combine

dcycle

naturalgas

2258

mmBtu/hr

SCR,

Low

NOxbu

rner

2PP

M

30DA

YRO

LLING

AVER

AGE

BACT

PSD

0Siem

ens5

01FD

orF4.

*TX06

60

FGETEXA

SPO

WER

IAN

DFG

ETEXA

SPO

WER

IIFG

EPO

WER

LLC

PSDT

X136

43/24

/201

4Alstom

Turbine

NaturalGa

s23

0.7MW

Selectivecatalytic

redu

ction

2PP

MVD

CORR

ECTED

TO15

%O2,

ROLLING24

HRAV

EBA

CTPSD

0

Unitsareno

tthe


BACT

emissionlim

itisno

tapp

licableandwillno

tbe

considered

anyfurthe

r.

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

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=O

ctob

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,201

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nTu

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oces

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.21

Pollu

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itAv

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*OR00

50TR

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LLC

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LLC

2602

353/5/20

14

Mitsub

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501GA

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stionturbine,

combine

dcycle

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duct

burner.

naturalgas

2988

MMBtu/hr

Utilize

drylow

NOxbu

rners

whencombu

sng

naturalgas;

Utilize

water

injectionwhe

ncombu

sng

ULSD;

Utilize

selectivecatalytic

redu

ction(SCR

)with

aque

ous

2PP

MDV

AT15

%O2

3HR

ROLLING

AVER

AGEON

NG

BACT

PSD

0Mitsub

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501GA

*PA02

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FUTU

REPO

WER

PA/G

OODSPRINGS

NGC

CFA

CILITY

FUTU

REPO

WER

PAINC

5400

082A

3/4/20

14

Turbine,CO

MBINED

CYCLEUNIT(Siemen

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00)

NaturalGa

s22

67MMBtu/hr

SCR

2PP

MVD

@15

%OXYGE

NBA

CTPSD

79.9

TPY

BASEDONA12

MONTH

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TOTA

LSiem

ens5

000serie

s.

*PA02

96

BERK

SHO

LLOW

ENER

GYAS

SOC

LLC/ONTELAUNEE

BERK

SHO

LLOW

ENER

GYAS

SOCLLC

0605

150A

12/17/20

13Turbine,Co

mbine

dCycle,#1

and# 2

NaturalGa

s30

46MMBtu/hr

SCR

131.6TPY

12MONTH

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TOTA

LBA

CTPSD

0Manufactureru

nkno

wn .

*MI0

412

HOLLAN

DBO

ARDOF

PUBLICWORK

SEA

ST5THSTRE

E THO

LLAN

DBO

ARDOF

PUBLICWORK

S10

713

12/4/201

3

FGCT

GHRSG:

2Co

mbine

dcycleCT

Gswith

HRSG

swith

duct

burners

naturalgas

647MMBT

U/H

fore

ach

CTGH

RSG

SCRwith

DLNB(selectiv

ecatalytic

redu

ctionwith

dry

lowNOxbu

rners).

3PP

M

24H

ROLL.AVG

.NOT

STAR

TUP/SH

UTD

OWN

BACT

PSD

0Manufactureru

nkno

wn .

*MI0

412

HOLLAN

DBO

ARDOF

PUBLICWORK

SEA

ST5THSTRE

E THO

LLAN

DBO

ARDOF

PUBLICWORK

S10

713

12/4/201

3FG

CTGH

RSG:

Startup

&Shutdo

wn

naturalgas

647MMBT

U/H

fore

ach

CTGH

RSG

SCRwith

DLNB(selectiv

ecatalytic

redu

ctionwith

dry

lowNOxbu

rners).

43.7

LB/H

OPERA

TING

HOUR

DURING

STAR

TUP

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

*TX06

41PINEC

REST

ENER

GYCE

NTER

PINEC

REST

ENER

GYCE

NTERLLC

PSDT

X129

811

/12/20

13combine


700MW

selectivecatalytic

redu

ction

2PP

MVD

24HR

ROLLINGAV

G,15

%OXYGE

NBA

CTPSD

0Ge

neralElectric

7FA.05

,the

Siem

ensS

GT650

00F(4),

andtheSiem

ensS

GT650

00F(5 )

*TX07

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NDHILL

ENER

GYCE

NTER

CITY

OFAU

STIN

4810

6,PSDT

X101

2M2

9/13

/201

3

Naturalgasfired

combine

dcycle

turbines

NaturalGa

s17

3.9MW

SCR

2PP

M24

HRRO

LLINGAV

G.BA

CTPSD

0

GE7FANaturalGa

sfired

Combine

dCycleTurbine.

Unitsareno

tthe


BACT

emissionlim

itisno

tapp

licableandwillno

tbe

considered

anyfurthe

r .

*TX06

98BA

YPORT

COMPLEX

AIRLIQUIDELARG

EINDU

STRIES

U.S.,L.P.

9346

PSDT

X612

M2

9/5/20

13(4)cogen

eration

turbines

naturalgas

90MW

DLNandClosed

Loop

Emissions

Controls(CLEC)

5PP

MVD

@15

%O2,3

HRRO

LLING

AVER

AGE

BACT

PSD

0

Unitsareno

tthe


BACT

emissionlim

itisno

tapp

licableandwillno

tbe

considered

anyfurthe

r .

*MI0

410

THETFO

RDGE

NER

ATINGSTAT

IONCO

NSU

MER

SEN

ERGY

COMPA

NY

19112

7/25

/201

3

FGCC

Aor

FGCC

B4

nat.gasfire

dCT

Gw/

DBforH

RSG

naturalgas

2587

MMBT

U/H

heat

inpu

t,each

CTG

LowNOxbu

rnersa

ndselective

catalytic

redu

ction.

3PP

MV

24HRO

LLING

AVER

AGE

BACT

PSD

0Manufactureru

nkno

wn .

*MI0

410

THETFO

RDGE

NER

ATINGSTAT

IONCO

NSU

MER

SEN

ERGY

COMPA

NY

19112

7/25

/201

3

FGCC

Aor

FGCC

B:4nat

gasfire

dCT

Gwith

DBforH

RSG:

Startup/shutdo

wn

even

tsnaturalgas

2587

MMBT

U/H

desig

nhe

atinpu

t,eac h

LowNOxbu

rnersa

ndselective

catalytic

redu

ction.

78.4

T/YR

12MORO

LLTIMEPERIOD

FOR

STAR

TUP/SH

UTD

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

*OH03

52ORE

GONCLEA

NEN

ERGY

CENTER

ARCA

DIS,US,INC .

P011

0840

6/18

/201

3

2Co

mbine

dCycle

Combu

stionTurbines

Mitsub

ishi,with

duct

burners

NaturalGa

s47

917MMSCF/rolling

12MO

selectivecatalytic

redu

ction

(SCR

);drylowNOx

combu

stors;lean

fuel

techno

log y

20.8

LB/H

BACT

PSD

2PP

MPP

MVD

AT15

%O2

2Mitsub

ishiM

501GA

Cun

itsor

2Siem

ensS

GT80

00Hun

it

*OH03

52ORE

GONCLEA

NEN

ERGY

CENTER

ARCA

DIS,US,INC .

P011

0840

6/18

/201

3

2Co

mbine

dCycle

Combu

stionTurbines

Siem

ens,with

outd

uct

burners

NaturalGa

s51

5600

MMSCF/rolling

12mon

ths

selectivecatalytic

redu

ction

(SCR

);drylowNOx

combu

stors;lean

fuel

techno

log y

22LB/H

BACT

PSD

2PP

MPP

MVD

AT15

%O2

BACT

:2.0pp

mvd

at15

%O2.2Mitsub

ishiM

501GA

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itsor

2Siem

ensS

GT80

00Hun

its

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:N

Ox

Prop

osed

NO

xLi

mit:

3PP

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@15

%O

2;Eq

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lent

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0111

lb/M

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u

RBLC

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cilit

yN

ame

Corp

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eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

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elTh

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Thro

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Cont

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etho

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Lim

itEm

issi

onLi

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Uni

t

Emis

sion

Lim

itAv

gTi

me

Cond

ition

Case

ByCa

seBa

sis

Stan

dard

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sion

Lim

it

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

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me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

*OH03

52ORE

GONCLEA

NEN

ERGY

CENTER

ARCA

DIS,US,INC.

P011

0840

6/18

/201

3

2Co

mbine

dCycle

Combu

stionTurbines

Mitsub

ishi,with

out

ductbu

rners

NaturalGa

s47

917MMSCF/rolling

12MO

selectivecatalytic

redu

ction

(SCR

);drylowNOx

combu

stors;lean

fuel

techno

log y

22.6

LB/H

BACT

PSD

2PP

MPP

MVD

AT15

%O2

BACT

:2.0pp

mvd

at15

%O2.2Mitsub

ishiM

501GA

Cun

itsor

2Siem

ensS

GT80

00Hun

its

*MI0

405

MIDLAND

COGE

NER

ATION

VENTU

REMIDLAND

COGE

NER

ATIONVE

NTU

RE10

312

4/23

/201

3

Naturalgasfue

led

combine

dcycle

combu

stionturbine

gene

rators(CTG

)with

HRSG

Naturalgas

2237

MMBT

U/H

DrylowNOx(DLN

)burne

rand

selectivecatalytic

redu

ction

(SCR

)system.

2PP

M

EACH

CTG;

24HRO

LLING

AVG.

BACT

PSD

0CT

Mod

elno

tlisted

inpe

rmit .

*MI0

405

MIDLAND

COGE

NER

ATION

VENTU

REMIDLAND

COGE

NER

ATIONVE

NTU

RE10

312

4/23

/201

3

Naturalgasfue

led

combine

dcycle

combu

stionturbine

gene

rators(CTG

)with

HRSG

anddu

ctbu

rner

Naturalgas

2486

MMBT

U/H

DrylowNOx(DLN

)burne

rsandselectivecatalytic

redu

ction(SCR

)system.

2PP

M24

HRO

LLING

AVG

BACT

PSD

0CT

Mod

elno

tlisted

inpe

rmit.

*MI0

405

MIDLAND

COGE

NER

ATION

VENTU

REMIDLAND

COGE

NER

ATIONVE

NTU

RE10

312

4/23

/201

3

Naturalgasfue

led

combine

dcycle

combu

stionturbine

gene

rators(CTG

)with

HRSG

Naturalgas

2237

MMBT

U/H

each

DrylowNOx(DLN

)burne

rand

selectivecatalytic

redu

ction

(SCR

)18

5.7LB/H

HOURLY

DURING

STAR

TUP

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

*PA02

91HICK

ORY

RUN

ENER

GYSTAT

ION

HICK

ORY

RUNEN

ERGY

LLC

3733

7A4/23

/201

3CO

MBINED

CYCLE

UNITS#1

and# 2

NaturalGa

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SCR

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Thereisno

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ationto

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limits.

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ationto

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STAR

TUPPERIODS

)NAT

URA

LGA

S17

2MW

DRYLO

WNOXBU

RNER

S(LNB),

SELECT

IVECA

TALYTIC

REDU

CTION(SCR

)15

2LB/H

HOTSTAR

TUP

PERIODS

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

for the

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

CA12

11CO

LUSA

GENER

ATING

STAT

ION

PACIFICGA

S&ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(WAR

MSTAR

TUPPERIODS

)NAT

URA

LGA

S17

2MW

DRYLO

WNOXBU

RNER

S(LNB),

SELECT

IVECA

TALYTIC

REDU

CTION(SCR

)24

9.9LB/H

WAR

MSTAR

TUP

PERIODS

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

CA12

11CO

LUSA

GENER

ATING

STAT

ION

PACIFICGA

S&ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(COLD

STAR

TUPPERIODS

)NAT

URA

LGA

S17

2MW

DRYLO

WNOXBU

RNER

S(LNB),

SELECT

IVECA

TALYTIC

REDU

CTION(SCR

)33

3.3LB/H

COLD

STAR

TUP

PERIODS

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

t eno

ugh

inform

ationto

compare

limits.

OR00

48CA

RTYPLAN

TPO

RTLANDGE

NER

ALELEC

TRIC

2500

16ST

0212

/29/20

10

COMBINED

CYCLE

NAT

URA

LGA

SFIRE

DELEC

TRIC

GENER

ATING

UNI T

NAT

URA

LGA

S28

66MMBT

U/H

SELECT

IVECA

TALYTIC

REDU

CTION(SCR

)

Equivalent

to2.5PP

MNOx,

dry,corrected

to15

%O2

PPM@15

%O2

3HO

UR

ROLLING

BACT

PSD

0CT

Mod

elno

tlisted

inpe

rmit .

*IL01

12NELSO

NEN

ERGY

CENTER

INVE

NER

GYNELSO

N,LLC

9808

0039

12/28/20

10ElectricGe

neratio

nFacility

NaturalGa

s22

0MW

each

SCRandLow

NOxCo

mbu

stors

4.5PP

MVD

@15

%O2

HOURLYAV

GEXCE

PTDU

RINGSSM

ORTU

NING

BACT

PSD

0Manufactureru

nkno

wn .

AK00

73

INTERN

ATIONAL

STAT

IONPO

WER

PLAN

TCH

UGA

CHELEC

TRIC

ASSO

CIAT

ION

AQ01

64CP

T01

12/20/20

10FuelCo

mbu

stion

NaturalGa

s59

900HP

Turbines

EUIDs5

through8

shallbeeq

uipp

edwith

SelectiveCatalytic

Redu

ction

andDryLowNOx(SCR

and

DLN)com

bustors.SCRisapo

stcombu

stiongastreatmen

t5PP

M4HO

UR

BACT

PSD

0Manufactureru

nkno

wn .

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:N

Ox

Prop

osed

NO

xLi

mit:

3PP

MVD

@15

%O

2;Eq

uiva

lent

to0.

0111

lb/M

MBt

u

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

hput

Thro

ughp

utU

nit

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

t

Emis

sion

Lim

itAv

gTi

me

Cond

ition

Case

ByCa

seBa

sis

Stan

dard

Emis

sion

Lim

it

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

VA03

15

WAR

RENCO

UNTY

POWER

PLAN

TDO

MINION

VIRG

INIA

ELEC

TRIC

AND

POWER

COMPA

NY

8139

100

712

/17/20

10

COMBINED

CYCLE

TURB

INE&am

p;DU

CTBU

RNER

,3NaturalGa

s29

96MMBT

U/H

Twostage,lean

premixdry

low

NOxcombu

stor

anda

selectivecatalytic

redu

ction

(SCR

)con

trolsystem

using

ammon

iainjection.

2PP

MVD

@15

%O2

ONEHO

UR

AVER

AGE

BACT

PSD

0

Unitsareno

tthe


BACT

emissionlim

itisno

tapp

licableandwillno

tbe

considered

anyfurthe

r .

*CO00

73PU

EBLO

AIRP

ORT

GENER

ATINGSTAT

IONBLAC

KHILLSELEC

TRIC

GENER

ATION,LLC

09PB

0591

7/22

/201

0Four

combine

dcycle

combu

tionturbines

naturalgas

373mmbtu/hr

DryLowNOx(DLN

)Com

bustor

andSelectiveCatalytic

Redu

ction(SCR

)3PP

MVD

AT15

%O2

1HR

AVE

BACT

PSD

0GE

,LMS600

0PF,naturalgasfired

,com

bine

dcycle

CTG,

ratedat

373MMBtupe

rhou

reach

ID00

18LANGL

EYGU

LCH

POWER

PLAN

TIDAH

OPO

WER

COMPA

NYP20

09.009

26/25

/201

0

COMBU

STION

TURB

INE,CO

MBINED

CYCLEW/D

UCT

BURN

ERNAT

URA

LGA

S(ONLY)

2375

.28MMBT

U/H

SELECT

IVECA

TALYTIC

REDU

CTION(SCR

),DR

YLO

WNOX(DLN

),GO

ODCO

MBU

STION

PRAC

TICE

S(GCP

)2PP

MVD

3HR

ROLLING

/15%

O2

BACT

PSD

0Siem

ensS

GT650

00FCo

mbu

stionturbine .

GA01

38LIVE

OAK

SPO

WER

PLAN

TLIVE

OAK

SCO

MPA

NY,LLC

4911

12700

75P02

04/8/20

10

COMBINED

CYCLE

COMBU

STIONTU

RBINE

ELEC

TRIC

GENER

ATINGPLAN

TNAT

URA

LGA

S60

0MW

DRYLO

WNOxBU

RNER

S,SELECT

IVECA

TALYTIC

REDU

CTION

2.5PP

M@15

%02

3HO

UR

AVER

AGE/CO

NDITION2.11

BACT

PSD

0Manufactureru

nkno

wn .

CA12

09HIGH

DESERT

POWER

PROJECT

HIGH

DESERT

POWER

PROJECT

LLC

SE98

013/11

/201

0

COMBU

STIONTU

RBINE

GENER

ATORS

(NORM

ALOPERA

TION)NAT

URA

LGA

S19

0MW

DRYLO

WNOXBU

RNER

S(LNB),

SELECT

IVECA

TALYTIC

REDU

CTION(SCR

)2.5PP

MVD

@15

%O2,1

HRAV

GBA

CTPSD

0Siem

ensW

estin

ghou

sePo

wer

Corporation50

1FCT

G .

CA12

09HIGH

DESERT

POWER

PROJECT

HIGH

DESERT

POWER

PROJECT

LLC

SE98

013/11

/201

0

COMBU

STIONTU

RBINE

GENER

ATOR

(SHU

TDOWNPERIODS

)NAT

URA

LGA

S19

0MW

DRYLO

WNOXBU

RNER

S(LNB),

SELECT

IVECA

TALYTIC

REDU

CTION(SCR

)97

LB/SHU

TDOW

NSH

UTD

OWN

PERIODS

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

CA12

09HIGH

DESERT

POWER

PROJECT

HIGH

DESERT

POWER

PROJECT

LLC

SE98

013/11

/201

0

COMBU

STIONTU

RBINE

GENER

ATOR(STA

RTUP

PERIODS

)NAT

URA

LGA

S19

0MW

DRYLO

WNOXBU

RNER

S(LNB),

SELECT

IVECA

TALYTIC

REDU

CTION(SCR

)35

41LB/COLD

STAR

TUP

COLD

STAR

TUP

PERIODS

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#2(NORM

ALOPERA

TION,N

ODU

CTBU

RNING)

NAT

URA

LGA

S15

4MW

SCR

2PP

MVD

@15

%O2,1

HRAV

G(NO

DUCT

BURN

ING)

BACT

PSD

0

NaturalGa

sFire

dGE

7FA.

Thisun

itisno

tthe

same

manufacturer,so

thisBA

CTisno

tapp

licableandwill

notb

econsidered

furthe

rinthisanalysis .

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#2(NORM

ALOPERA

TION,W

ITH

DUCT

BURN

ING)

NAT

URA

LGA

S15

4MW

SCR

2PP

MVD

@15

%O2,1

HRAV

G(W

/DU

CTBU

RNING)

BACT

PSD

0

NaturalGa

sFire

dGE

7FA.

Thisun

itisno

tthe

same

manufacturer,so

thisBA

CTisno

tapp

licableandwill

notb

econsidered

furthe

rinthisanalysis.

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#1(NORM

ALOPERA

TION,N

ODU

CTBU

RNING)

NaturalGa

s15

4MW

SCR

2PP

MVD

1HR

AVG,

@15

%O2

(NODU

CTBU

RNING)

BACT

PSD

0

NaturalGa

sFire

dGE

7FA.

Thisun

itisno

tthe

same

manufacturer,so

thisBA

CTisno

tapp

licableandwill

notb

econsidered

furthe

rinthisanalysis.

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#1(NORM

ALOPERA

TION,W

ITH

DUCT

BURN

ING)

NAT

URA

LGA

S15

4MW

SCR

2PP

MVD

@15

%O2,1

HRAV

G(W

/DU

CTBU

RNING)

BACT

PSD

0

NaturalGa

sFire

dGE

7FA.

Thisun

itisno

tthe

same

manufacturer,so

thisBA

CTisno

tapp

licableandwill

notb

econsidered

furthe

rinthisanalysis.

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#1(W

ARM;H

OT

STAR

TUPPERIODS

)NAT

URA

LGA

S15

4MW

SCR

30LB/H

WAR

M&HO

TSTAR

TUP

PERIODS

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#2(W

ARM;H

OT

STAR

TUPPERIODS

)NAT

URA

LGA

S15

4MW

SCR

30LB/H

WAR

M&

HOW

STAR

TUP

PERIODS

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:N

Ox

Prop

osed

NO

xLi

mit:

3PP

MVD

@15

%O

2;Eq

uiva

lent

to0.

0111

lb/M

MBt

u

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

hput

Thro

ughp

utU

nit

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

t

Emis

sion

Lim

itAv

gTi

me

Cond

ition

Case

ByCa

seBa

sis

Stan

dard

Emis

sion

Lim

it

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#1(COLD

STAR

TUP

PERIODS

)NAT

URA

LGA

S15

4MW

SCR

52.4

LB/H

COLD

STAR

TUP

PERIODS

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#2(COLD

STAR

TUP

PERIODS

)NAT

URA

LGA

S15

4MW

SCR

52.4

LB/H

COLD

STAR

TUP

PERIODS

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#1(SHU

TDOWN

PERIODS

)NAT

URA

LGA

S15

4MW

SCR

114LB/H

SHUTD

OWN

PERIODS

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#2(SHU

TDOWN

PERIODS

)NAT

URA

LGA

S15

4MW

SCR

114LB/H

SHUTD

OWN

PERIODS

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

TX05

48MAD

ISONBE

LLEN

ERGY

CENTER

MAD

ISONBE

LLPA

RTNER

SLP

8337

88/18

/200

9ELEC

TRICITY

GENER

ATION

NAT

URA

LGA

S27

5MW

SELECT

IVECA

TALYTIC

REDU

CTION

2PP

MVD

@15

%O2,24

HRRO

LLING

AVG

BACT

PSD

0

Unitsareno

tthe


BACT

emissionlim

itisno

tapp

licableandwillno

tbe

considered

anyfurthe

r .

CA11

77OTA

YMESAEN

ERGY

CENTERLLC

OTA

YMESAEN

ERGY

CENTERLLC

9783

797/22

/200

9Ga

sturbine

combine

dcycle

Naturalgas

171.7MW

SCR

2.0PP

MVD

@15

%OXYGE

N1HO

UR

OTH

ERCA

SEBY

CASE

0

Consistso

fthree

Gene

ralElectric

(GE)

LMS10

00naturalgas

fired

turbinegene

ratorsat

100MW

each.

Finalized

Nox

limitof

2.5PP

Mat

15%O2as

a1ho

uraverage.

TX05

47

NAT

URA

LGA

SFIRE

DPO

WER

GENER

ATION

FACILIT Y

LAMAR

POWER

PART

NER

SIILLC

8320

76/22

/200

9ELEC

TRICITY

GENER

ATION

NAT

URA

LGA

S25

0MW

SELECT

IVECA

TALYTIC

REDU

CTION

2PP

MVD

@15

%O2,24

HRRO

LLING

AVG

BACT

PSD

0EITH

ER17

0MW

GENER

ALELEC

TRIC

7FAS

OR25

0MW

MITSU

BISH

I501

G S

TX05

46PA

TTILLO

BRAN

CHPO

WER

PLAN

TPA

TTILLO

BRAN

CHPO

WER

COMPA

NYLLC

8364

26/17

/200

9ELEC

TRICITY

GENER

ATION

NAT

URA

LGA

S35

0MW

SELECT

IVECA

TALYTIC

REDU

CTION

2PP

MVD

@15

%O224

HRRO

LLING

AVG

BACT

PSD

0GE

7FA,

GE7FB,

ANDSIEM

ENSSG

T650

00F

CA11

78AP

PLIEDEN

ERGY

LLC

APPLIEDEN

ERGY

LLC

9874

943/20

/200

9Ga

sturbine

combine

dcycle

Naturalgas

0SCR

2PP

M1HO

UR

BACT

PSD

0Manufactureru

nkno

wn.

OK01

29CH

OUTEAU

POWER

PLAN

TAS

SOCIAT

EDELEC

TRIC

COOPERA

TIVE

INC

2007

115C(M

1)PSD

1/23

/200

9

COMBINED

CYCLE

COGE

NER

ATION

>25M

WNAT

URA

LGA

S18

82MMBT

U/H

SCRAN

DDR

YLO

WNOX

2PP

M1HAV

G@

15%O2

BACT

PSD

0SIEM

ENSV8

4.3A

OK01

29CH

OUTEAU

POWER

PLAN

TAS

SOCIAT

EDELEC

TRIC

COOPERA

TIVE

INC

2007

115C(M

1)PSD

1/23

/200

9

COMBINED

CYCLE

COGE

NER

ATION

>25M

WNAT

URA

LGA

S18

82MMBT

U/H

DRYLO

WNOX

568LB/EVE

NT

4HSTAR

TUP

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

FL03

04CA

NEISLANDPO

WER

PARK

FLORIDA

MUNICIPAL

POWER

AGEN

CY(FMP A

PSDFL

400

(097

0043

014

AC)

9/8/20

08

300MW

COMBINED

CYCLECO

MBU

STION

TURB

INE

NAT

URA

LGA

S18

60MMBT

U/H

SCR

2PP

MVD

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GE4FACo

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same


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issionlim

itis

nota

pplicableandwillno

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anyfurthe

r

FL03

03

FPLWESTCO

UNTY

ENER

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NTERUNIT

3FLORIDA

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L)09

9064

600

2AC

(PSD

FL39

6)7/30

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8

THRE

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250

MW

CTG(EAC

H)WITH

SUPP

LEMEN

TARY

FIRE

DHR

SGNAT

URA

LGA

S23

33MMBT

U/H

DRYLO

WNOX

SELECT

IVECA

TALYST

REDU

CTION

2PP

MVD

(GAS

)24

HOURS

BACT

PSD

0

Doosan

Mod

elM50

1GCT

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tthe

same


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issionlim

itis

nota

pplicableandwillno

tbeconsidered

anyfurthe

r

LA01

36

PLAQ

UEM

INE

COGE

NER

ATION

FACILIT Y

THEDO

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COMPA

NY

PSDLA

659(M2)

7/23

/200

8

(4)G

ASTU

RBINES/DUCT

BURN

ERS

NAT

URA

LGA

S28

76MMBT

U/H

DRYLO

WNOXBU

RNER

S,SELECT

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TALYTIC

REDU

CTION

240LB/H

HOURLY

MAX

IMUM

NORM

ALOPERA

TION

BACT

PSD

5PP

MVD

@15

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NUAL

AVER

AGE

5PP

M

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24AR

SENAL

HILL

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T

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726

3/20

/200

8TW

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MBINED

CYCLE

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NAT

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LGA

S21

10MMBT

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LOW

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UCT

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WITH

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30.15LB/H

MAX

BACT

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AVER

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4PP

M

Calp

ine

Man

kato

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T/LA

ERCl

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05Cu

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arch

Date

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itN

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HILL

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T

SOUTH

WESTELEC

TRIC

POWER

COMPA

NY

(SWEPCO

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726

3/20

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8

SCN4HO

TSTAR

TUP

CTG1SCN8HO

TSTAR

TUPCT

G2

NAT

URA

LGA

S21

10MMBT

U/H

QUICKLYAS

POSSIBLE

ACCO

RDINGTO

MAN

UFA

CTURE

¿SRE

COMMEN

DED

PROCE

DURE

S.40

0LB/H

MAX

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

MN00

71FA

IRBA

ULT

ENER

GYPA

RKMINNESOTA

MUNICIPAL

POWER

AGEN

CY13

1000

7100

36/5/20

07

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CYCLE

COMBU

STIONTU

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W/DUCT

BURN

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LGA

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WNOXCO

MBU

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WAT

ERINJECT

ION

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IONIN

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3PP

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CTG&DB

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OR

DBNOOPE

BACT

PSD

4.5PP

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3HR

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DBOIL

Manufactureru

nkno

wn .

CA11

44BLYTHE

ENER

GYPR

OJECT

IICA

ITHN

ESSBLYTHE

II,LLC

SE02

014/25

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72CO

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STION

TURB

INES

NAT

URA

LGA

S17

0MW

SELECT

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TALYTIC

REDU

CTION

2.0PP

MVD

AT15

%O2,3

HRAV

GBA

CTPSD

0Ga

sTurbine

Natural

gasfire

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4.3A

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MW

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g)

OK01

17PSOSO

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OMA

2003

403CPSD

2/9/20

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DTU

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9PP

MBA

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nkno

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OGR

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D10

3001

101

0AC

1/26

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7

COMBINED

CYCLE

COMBU

STIONTU

RBINE

SYSTEM

(4ON1)

NAT

URA

LGA

S19

72MMBT

U/H

WAT

ERINJECT

ION

15PP

MVD

UNCO

RREC

TED

30DA

YSBA

SIS

NAT

URA

LGA

SBA

CTPSD

0Mod

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UNTY

ENER

GYCE

NTER

FLORIDA

POWER

AND

LIGH

TCO

MPA

NY

PSDFL

354AN

D09

9064

600

1AC

1/10

/200

7

COMBINED

CYCLE

COMBU

STIONGA

STU

RBINES

6UNITS

NAT

URA

LGA

S23

33MMBT

U/H

DRYLO

WNOXAN

DSCR

WAT

ERINJECT

ION

2PP

MVD

@15

%O2

24HR

(GAS

)BA

CTPSD

0

Doosan

Mod

elM50

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G.Unitsareno

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same


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issionlim

itis

nota

pplicableandwillno

tbeconsidered

anyfurthe

r

OK01

15LAWTO

NEN

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CILIT Y

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2001

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12/12/20

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ANDDU

CTBU

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RYLO

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BURN

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DDR

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STION

3.5PP

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@15

%O2

BACT

PSD

0Manufactureru

nkno

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TX04

97INEO

SCH

OCO

LATE

BAYO

UFA

CILITY

INEO

SUSA

LLC

PSDTX

983

AND46

192

8/29

/200

6

COGE

NER

ATIONTR

AIN

2AN

D3(TURB

INEAN

DDU

CTBU

RNER

EMISSIONS)

NAT

URA

LGA

S35

MW

SCRTO

CONTR

OLNOX

EMISSIONSFROM

BOTH

TURB

INES

ANDDU

CTBU

RNER

SAF

TERCO

NSIDE

RING

ALTERN

ATIVENOXCO

NTR

OL

11.43LB/H

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BACT

PSD

0Manufactureru

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TX05

02

NAC

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STER

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1015

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6/5/20

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501F

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21MMBU

T/H

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MVD

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2BA

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05WE052

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06

NAT

URA

LGA

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D,CO

MBINED

CYCLE

TURB

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NAT

URA

LGA

S30

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LOW

NOXBU

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SAN

DSCR

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HOURLYMAX

BACT

PSD

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Manufactureru

nkno

wn.

CA12

13

MOUNTA

INVIEW

POWER

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POWER

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6

COMBU

STION

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(NORM

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TION)

NAT

URA

LGA

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1991

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MBU

STORS,SELEC

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CATA

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DUCT

ION(SCR

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MVD

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MIN

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Four

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sGE724

1FAnaturalgas

combu

stion

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tthe

samemanufacturer ,

sothisBA

CTem

issionlim

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tapp

licablean

will

notb

econsidered

anyfurthe

r .

CA12

13

MOUNTA

INVIEW

POWER

COMPA

NY

LLC

MOUNTA

INVIEW

POWER

COMPA

NYLLC

SE04

014/21

/200

6

COMBU

STION

TURB

INES

(SHU

TDOWN

PERIODS

)NAT

URA

LGA

S17

5.7MW

EA.

1991

MMBT

U/HRDR

YLO

WNOXCO

MBU

STORS,SELEC

TIVE

CATA

LYTICRE

DUCT

ION(SCR

)70

LB/SHU

TDOW

N

30MIN

AVG

(SHU

TDOWN

PERIODS

)BA

CTPSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

CA12

13

MOUNTA

INVIEW

POWER

COMPA

NY

LLC

MOUNTA

INVIEW

POWER

COMPA

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014/21

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6

COMBU

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INES

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LGA

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5.7MW

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1991

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YLO

WNOXCO

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STORS,SELEC

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CATA

LYTICRE

DUCT

ION(SCR

)80

LB/H

1HR

AVG

(COMBU

STOR

TUNING

PERIODS

)BA

CTPSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

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,201

5Co

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stio

nTu

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.21

Pollu

tant

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Ox

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xLi

mit:

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Emis

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Cond

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Case

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Cond

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Addi

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mit

Lim

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MOUNTA

INVIEW

POWER

COMPA

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LLC

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POWER

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SE04

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6

COMBU

STION

TURB

INES

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RTUP

PERIODS

)NAT

URA

LGA

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5.7MW

EA.

1991

MMBT

U/HRDR

YLO

WNOXCO

MBU

STORS,SELEC

TIVE

CATA

LYTICRE

DUCT

ION(SCR

)16

0LB/H

3HR

AVG

(STA

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BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

CA11

95ELKHILLSPO

WER

LLC

ELKHILLSPO

WER

LLC

SJ99

021/12

/200

6

COMBU

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GENER

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its(NormalOpe

ratio

n)NAT

URA

LGA

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6MW

SCRORSCONOX,DR

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MVD

@15

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HRAV

GBA

CTPSD

0Manufactureru

nkno

wn .

CA11

95ELKHILLSPO

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LLC

ELKHILLSPO

WER

LLC

SJ99

021/12

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6

Combu

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Gene

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its(Turbine

Shutdo

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Even

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NaturalGa

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SCRORSCONOX

222LB/EVE

NT

TURB

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SHUTD

OWN

EVEN

TSBA

CTPSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

CA11

95ELKHILLSPO

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LLC

ELKHILLSPO

WER

LLC

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021/12

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6

COMBU

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Even

ts)

NAT

URA

LGA

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6MW

SCRORSCONOX

800LB/EVE

NT

EXTENDE

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TUP

EVEN

TSBA

CTPSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

TX05

16

CITY

PUBLICSERV

ICE

JKSPRU

CEELEC

TRICE

GENER

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CITY

PUBLICSERV

ICE

PSDTX

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492

12/28/20

05SPRU

CEPO

WER

GENER

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1600

LB/H

BACT

PSD

0

SU/SDLimit.

Calpineprop

osed

aseparate

SUSD

limit

forthe

prop

osed

unit.

Thereisno

teno

ugh

inform

ationto

compare

limits.

NV00

35TR

ACYSU

BSTA

TION

EXPA

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SIER

RAPA

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5

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INJECT

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UR

ROLLING

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Manufactureru

nkno

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NV00

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5

TURB

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Manufactureru

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OR00

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Unitsareno

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r .

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Manufactureru

nkno

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LA01

92CR

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CRESEN

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PSDLA

704

6/6/20

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187

MW

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2006

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CTION(SCR

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ON

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NUAL

AVER

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Facilitywas

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structed

andpe

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5

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INES

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URA

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84MMBT

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CTION.

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Manufactureru

nkno

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FL02

63FPLTU

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28

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POINT

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NER

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PROJECT

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PRODU

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EFSEC/2002

011/11

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5

GE7FACO

MBU

STION

TURB

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p;HE

ATRE

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NAT

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NOTES

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STIONTU

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RSYTHEN

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S,LLC

4911

8/31

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4

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NAT

URA

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2.5PP

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PSD

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mit

Lim

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otes

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Energy

Center

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NaturalGa

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NaturalGa

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SELECT

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BACT

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Manufactureru

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ine

Man

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Sear

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Jan

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05Cu

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arch

Date

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Pollu

tant

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rtic

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es

Prop

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Part

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ate

Lim

it:11

.9lb

/hr=

0.00

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RBLC

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Corp

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Com

pany

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Cont

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Lim

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Cond

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otes

*TX07

67LO

NC.HILL

POWER

STAT

ION

LONC.HILL,L.P.

1149

11AN

DPSDT

X138

010

/6/201

5Co

mbine

dCycle

Turbines

(>25

MW)

naturalgas

195MW

Particulate

matter,total<

10μ(TPM

10)&

total<

2.5μ

(TPM

2.5)

Good

combu

stionpractices

anduseof

pipe

linequ

ality

naturalgas

16LB/HR

BACT

PSD

Twopo

wer

configurationop

tions

authorize

dSiem

ens

–24

0MW

+25

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thermalun

itspe

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urne

rGE–19

5MW

+67

0MMBtu/hr

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it2

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PSDT

X139

0,N19

46/29

/201

5

Combine

dCycle

Turbines

(>25

MW)–

naturalgas

naturalgas

210MW

Particulate

matter,total<

10μ(TPM

10)&

total<

2.5μ

(TPM

2.5)

Good

combu

stionpractices,low

sulfu

rfuel

35.47LB/HR

BACT

PSD

Twopo

wer

configurationop

tions

authorize

dSiem

ens

–23

1MW

+50

0millionBritish

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itspe

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uctb

urne

rGE–21

0MW

+34

9.2

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*TX07

14

SRBE

RTRO

NELEC

TRIC

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ATING

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ION

NRG

TEXA

SPO

WER

LLC

1027

31PSDT

X129

412

/19/20

14(2)com

bine

dcycle

turbines

naturalgas

240MW

Particulate

matter,total&

2.5μ(TPM

2.5)

0BA

CTPSD

0

Threegastrurbineop

tions:2

Siem

ensM

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E7FA

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Mitsub

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10VICT

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WER

STAT

ION

VICT

ORIAWLE

L.P.

1082

58PSDT

X134

812

/1/201

4combine

dcycleturbine

naturalgas

197MW

Particulate

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2.5μ(TPM

2.5)

0BA

CTPSD

0Ge

neralelectric

7FA

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197MW

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tput.

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25

MOUNDS

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CYCLE

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TMOUNDS

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POWER

,LLC

R1400

3011

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14Co

mbine

dCycle

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ctBu

rne r

NaturalGa

s21

59mmBtu/Hr

Particulate

matter,total&

2.5μ(TPM

2.5)

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Combu

stionPractices,Inlet

Air

Filtration,&useof

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s7.6LB/HR

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0

Nom

inal19

7mW

Gene

ralElectric

Fram

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urne

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notes

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tofturbine

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(HHV

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12

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ERNPO

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1113

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X136

811

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14combine

dcycleturbine

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497MW

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2.5)

0BA

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0

Facilitywillconsist

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89

CEDA

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YOU

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TRIC

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ATION

STAT

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WE R

1058

10,

PSDT

X130

88/29

/201

4Co

mbine

dcyclenatural

gasturbine

sNaturalGa

s22

5MW

Particulate

matter,

filterable&2.5

μ(FPM

2.5)

Good

combu

stionpractices,natural

gas

0BA

CTPSD

0

Threeop

tions

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osed

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GE7Fa,andMitsub

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eavy

Indu

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e.The

newun

itswillprod

ucebe

tween21

526

3MW

each.

*TX06

78

FREEPO

RTLN

GPR

ETRE

ATMEN

TFA

CILIT Y

FREEPO

RTLN

GDE

VELO

PMEN

TLP

1048

40N17

0PSDT

X130

27/16

/201

4Co

mbu

stionTurbine

naturalgas

87MW

Particulate

matter,total&

2.5μ(TPM

2.5)

15.22LB/HR

BACT

PSD

0

*TX07

13

TENAS

KABR

OWNSV

ILLE

GENER

ATING

STAT

ION

TENAS

KABR

OWNSV

ILLE

PART

NER

S,LLC

1084

11PSDT

X135

04/29

/201

4(2)com

bine

dcycle

turbines

naturalgas

274MW

Particulate

matter,total&

2.5μ(TPM

2.5)

0BA

CTPSD

0

*IA01

07

MAR

SHALLTOWN

GENER

ATING

STAT

ION

INTERSTA

TEPO

WER

ANDLIGH

T13

A49

9P

4/14

/201

4Co

mbu

stionturbine#1

combine

dcycle

naturalgas

2258

mmBtu/hr

Particulate

matter,total

(TPM

)0.01

LB/M

MBT

UAV

G.OF3ONE

HOURTEST

RUNS

BACT

PSD

0tw

oiden

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ensS

GT650

00Fcombine

dcycle

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with

outd

uctfiring

*IA01

07

MAR

SHALLTOWN

GENER

ATING

STAT

ION

INTERSTA

TEPO

WER

ANDLIGH

T13

A49

9P

4/14

/201

4Co

mbu

stionturbine#2

combine

dcycle

naturalgas

2258

mmBtu/hr

Particulate

matter,total

(TPM

)0.01

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ERAG

EOF3ONE

HOURTEST

RUNS

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urning

*TX06

60

FGETEXA

SPO

WER

IANDFG

ETEXA

SPO

WER

IIFG

EPO

WER

LLC

PSDT

X136

43/24

/201

4Alstom

Turbine

NaturalGa

s23

0.7MW

Particulate

matter,total&

2.5μ(TPM

2.5)

Lowsulfu

rfue

l,good

combu

stion

practices

2PP

MVD

BACT

PSD

0Four

(4)A

lstom

GT24

CTGs

,eachwith

aHR

SGand

DBs,max

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ncapacity

409MMBtu/h r

*OR00

50

TROUTD

ALE

ENER

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LLC

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LLC

2602

353/5/20

14

Mitsub

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501GA

Ccombu

stionturbine,

combine

dcycle

configurationwith

duct

burner.

naturalgs

2988

MMBtu/hr

Particulate

matter,total&

10μ(TPM

10)

Utilize

onlynaturalgas

orULSDfuel;

Limitthetim

einstartupor

shutdo

wn .

23.6

LB/HRTO

TAL

PM6HR

AVER

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NG

BACT

PSD

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rner

499MMBtu/hr,naturalgas

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*PA02

98

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REPO

WER

PA/G

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NGC

CFA

CILITY

FUTU

REPO

WER

PAINC

5400

082A

3/4/20

14

Turbine,CO

MBINED

CYCLEUNIT(Siemen

s50

00)

NaturalGa

s22

67MMBtu/hr

Particulate

matter,

filterable(FPM

)10

.4LB/HR

WITHDU

CTBU

RNER

BACT

PSD

0

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

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seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

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nTu

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oces

sTyp

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Pollu

tant

:Pa

rtic

ulat

es

Prop

osed

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ate

Lim

it:11

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/hr=

0.00

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/MM

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pany

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mit

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Tim

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Case

Basi

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mit

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me

Cond

ition

Addi

tiona

lPer

mit

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98

FUTU

REPO

WER

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REPO

WER

PAINC

5400

082A

3/4/20

14

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MBINED

CYCLEUNIT(Siemen

s50

00)

NaturalGa

s22

67MMBtu/hr

Particulate

matter,total&

10μ(TPM

10)

15.6

LB/HR

WITHDU

CTBU

RNER

BACT

PSD

0

*PA02

96

BERK

SHO

LLOW

ENER

GYAS

SOC

LLC/ONTELAUNEE

BERK

SHO

LLOW

ENER

GYAS

SOCLLC

0605

150A

12/17/20

13Turbine,Co

mbine

dCycle,#1

and# 2

NaturalGa

s30

46MMBtu/hr

Particulate

matter,

filterable<

10μ(FPM

10)

48.56TPY

12MONTH

ROLLINGTO

TAL

BACT

PSD

02combu

stionturbinegene

ratorsand2he

atrecovery

steam

gene

ratorseq

uipp

edwith

adu

ctbu

rner

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96

BERK

SHO

LLOW

ENER

GYAS

SOC

LLC/ONTELAUNEE

BERK

SHO

LLOW

ENER

GYAS

SOCLLC

0605

150A

12/17/20

13Turbine,Co

mbine

dCycle,#1

and# 2

NaturalGa

s30

46MMBtu/hr

Particulate

matter,total&

2.5μ(TPM

2.5)

48.56TPY

12MONTH

ROLLINGTO

TAL

BACT

PSD

02combu

stionturbinegene

ratorsand2he

atrecovery

steam

gene

ratorseq

uipp

edwith

adu

ctbu

rner

*MI0

412

HOLLAN

DBO

ARD

OFPU

BLICWORK

SEA

ST5THSTRE

ETHO

LLAN

DBO

ARDOF

PUBLICWORK

S10

713

12/4/201

3

FGCT

GHRSG:

2Co

mbine

dcycleCT

Gswith

HRSG

swith

duct

burners

naturalgas

647MMBT

U/H

fore

ach

CTGH

RSG

Particulate

matter,

filterable(FPM

)Go

odcombu

stionpractices

andthe

useof

pipe

linequ

ality

naturalgas.

0.00

7LB/M

MBT

UTEST

PROTO

COL

BACT

PSD

02combine

dcyclenaturalgas

fired

CTGs

with

HRSG

s

*MI0

412

HOLLAN

DBO

ARD

OFPU

BLICWORK

SEA

ST5THSTRE

ETHO

LLAN

DBO

ARDOF

PUBLICWORK

S10

713

12/4/201

3

FGCT

GHRSG:

2Co

mbine

dcycleCT

Gswith

HRSG

swith

duct

burners

naturalgas

647MMBT

U/H

fore

ach

CTGH

RSG

Particulate

matter,total&

10μ(TPM

10)

Good

combu

stionpractices

andthe

useof

pipe

linequ

ality

naturalgas.

0.01

4LB/M

MBT

UTEST

PROTO

COL

BACT

PSD

02Co

mbine

dcycleCT

Gswith

HRSG

swith

ductbu

rners

*MI0

412

HOLLAN

DBO

ARD

OFPU

BLICWORK

SEA

ST5THSTRE

ETHO

LLAN

DBO

ARDOF

PUBLICWORK

S10

713

12/4/201

3

FGCT

GHRSG:

2Co

mbine

dcycleCT

Gswith

HRSG

swith

duct

burners

naturalgas

647MMBT

U/H

fore

ach

CTGH

RSG

Particulate

matter,total&

2.5μ(TPM

2.5)

Good

combu

stionpractices

andthe

useof

pipe

linequ

ality

naturalgas.

0.01

4LB/M

MBT

UTEST

PROTO

COL

BACT

PSD

02Co

mbine

dcycleCT

Gswith

HRSG

swith

ductbu

rners

*TX06

41PINEC

REST

ENER

GYCE

NTER

PINEC

REST

ENER

GYCE

NTERLLC

PSDT

X129

811

/12/20

13combine

dcycleturbine

naturalgas

700MW

Particulate

matter,total&

2.5μ(TPM

2.5)

pipe

linequ

ality

naturalgas

andgood

combu

stionpractice s

26.2

LB/H

BACT

PSD

0

2naturalgas

fired

combu

stionturbines,each

exhaustin

gto

afired

heat

recovery

steam

gene

rator

(HRSG).3

mod

elso

fcom

bustionturbines

arebe

ing

considered

:the

Gene

ralElectric

7FA.05

,the

Siem

ens

SGT6

5000

F(4),and

theSiem

ensS

GT650

00F(5).D

uct

Burnersa

reratedat

750MMBtu/hr

each.

*TX07

09SA

NDHILL

ENER

GYCE

NTER

CITY

OFAU

STIN

4810

6,PSDT

X101

2M2

9/13

/201

3

Naturalgasfired

combine

dcycle

turbines

NaturalGa

s17

3.9MW

Particulate

matter,total&

2.5μ(TPM

2.5)

0BA

CTPSD

0

*TX06

98BA

YPORT

COMPLEX

AIRLIQUIDELARG

EINDU

STRIES

U.S.,L.P .

9346

PSDT

X612

M2

9/5/20

13(4)cogen

eration

turbines

naturalgas

90MW

Particulate

matter,total&

2.5μ(TPM

2.5)

0BA

CTPSD

0(4)G

E7EAturbines

providingpo

wer

andprocess

steam

*MI0

410

THETFO

RDGE

NER

ATING

STAT

ION

CONSU

MER

SEN

ERGY

COMPA

NY

19112

7/25

/201

3

FGCC

Aor

FGCC

B4nat.

gasfire

dCT

Gw/D

Bfor

HRSG

naturalgas

2587

MMBT

U/H

heat

inpu

t,each

CTG

Particulate

matter,

filterable(FPM

)

Combu

stionair filters;efficient

combu

stioncontrol;lowsulfu

rnatural

gasfue

l.0.00

33LB/M

MBT

U

TEST

PROTO

COL;(3

1HTESTSIF

POSSIBLE)

BACT

PSD

04nat.gasfire

dCT

Gw/D

BforH

RSG

*MI0

410

THETFO

RDGE

NER

ATING

STAT

ION

CONSU

MER

SEN

ERGY

COMPA

NY

19112

7/25

/201

3

FGCC

Aor

FGCC

B4nat.

gasfire

dCT

Gw/D

Bfor

HRSG

naturalgas

2587

MMBT

U/H

heat

inpu

t,each

CTG

Particulate

matter,total&

2.5μ(TPM

2.5)

Combu

stionairfilters,efficient

combu

stioncontrol,lowsulfu

rnatural

gasfue

l.0.00

66LB/M

MBT

U

TEST

PROTO

COL(3

1HTESTSIF

POSSIBLE)

BACT

PSD

04nat.gasfire

dCT

Gw/D

BforH

RSG

*MI0

410

THETFO

RDGE

NER

ATING

STAT

ION

CONSU

MER

SEN

ERGY

COMPA

NY

19112

7/25

/201

3

FGCC

Aor

FGCC

B4nat.

gasfire

dCT

Gw/D

Bfor

HRSG

naturalgas

2587

MMBT

U/H

heat

inpu

t,each

CTG

Particulate

matter,total&

10μ(TPM

10)

Combu

stionairfilters;efficient

combu

stioncontrol;lowsulfu

rnatural

gasfue

l.0.00

66LB/M

MBT

U

TEST

PROTO

COL(3

1HTESTSIF

POSSIBLE)

BACT

PSD

04nat.gasfire

dCT

Gw/D

BforH

RSG

*OH03

52ORE

GONCLEA

NEN

ERGY

CENTER

ARCA

DIS,US,INC .

P011

0840

6/18

/201

3

2Co

mbine

dCycle

Combu

stionTurbines

Mitsub

ishi,with

duct

burners

NaturalGa

s47

917MMSCF/rolling

12MO

Particulate

matter,total&

10μ(TPM

10)

cleanbu

rningfuel,onlynaturalga s

10.1

LB/H

BACT

PSD

0

2Mitsub

ishi293

2MMBtu/Hcombine

dcycle

combu

stionturbines

,bothwith

300MMBtu/Hdu

ctbu

rners.

Willinstalleith

er2Siem

enso

r2Mitsub

ishi,

notb

oth

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:Pa

rtic

ulat

es

Prop

osed

Part

icul

ate

Lim

it:11

.9lb

/hr=

0.00

4lb

/MM

Btu

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

hput

Thro

ughp

utU

nit

Pollu

tant

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

tEm

issi

onLi

mit

Avg

Tim

eCo

nditi

onCa

seBy

Case

Basi

sSt

anda

rdEm

issi

onLi

mit

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

*OH03

52ORE

GONCLEA

NEN

ERGY

CENTER

ARCA

DIS,US,INC.

P011

0840

6/18

/201

3

2Co

mbine

dCycle

Combu

stionTurbines

Mitsub

ishi,with

out

ductbu

rners

NaturalGa

s47

917MMSCF/rolling

12MO

Particulate

matter,total&

10μ(TPM

10)

cleanbu


11.3

LB/H

BACT

PSD

0

2Mitsub

ishi293

2MMBtu/Hcombine

dcycle

combu

stionturbines

,bothwith

300MMBtu/Hdu

ctbu

rners.

Willinstalleith

er2Siem

enso

r2Mitsub

ishi,

notb

oth

*OH03

52ORE

GONCLEA

NEN

ERGY

CENTER

ARCA

DIS,US,INC.

P011

0840

6/18

/201

3

2Co

mbine

dCycle

Combu

stionTurbines

Siem

ens,with

outd

uct

burners

NaturalGa

s51

5600

MMSCF/rolling

12mon

ths

Particulate

matter,total&

10μ(TPM

10)

cleanbu


13.3

LB/H

BACT

PSD

0

2Mitsub

ishi293

2MMBtu/Hcombine

dcycle

combu

stionturbines

,bothwith

300MMBtu/Hdu

ctbu

rners.

Willinstalleith

er2Siem

enso

r2Mitsub

ishi,

notb

oth

*OH03

52ORE

GONCLEA

NEN

ERGY

CENTER

ARCA

DIS,US,INC.

P011

0840

6/18

/201

3

2Co

mbine

dCycle

Combu

stionTurbines

Siem

ens,with

duct

burners

NaturalGa

s51

560MMSCF/rolling

12MO

Particulate

matter,total&

10μ(TPM

10)

cleanbu


14LB/H

BACT

PSD

0

2Siem

ens2

932MMBtu/Hcombine

dcycle

combu

stionturbines

,bothwith

ductbu

rners.

Will

installeith

er2Siem

enso

r2Mitsub

ishi,no

tboth .

*MI0

405

MIDLAND

COGE

NER

ATION

VENTU

RE

MIDLAND

COGE

NER

ATION

VENTU

RE10

312

4/23

/201

3

Naturalgasfue

led

combine

dcycle

combu

stionturbine

gene

rators(CTG

)with

HRSG

anddu

ctbu

rner

(DB)

Naturalgas

2486

MMBT

U/H

Particulate

matter,total

(TPM

)Go

odcombu

stionpractice s

0.00

4LB/M

MBT

UTEST

PROTO

COL

BACT

PSD

0

2naturalgas

fired

CTGs

with

each

turbinecontaining

ahe

atrecovery

steam

gene

rator(HR

SG)ope

ratin

gwith

anaturalgas

fired

ductbu

rne r

*MI0

405

MIDLAND

COGE

NER

ATION

VENTU

RE

MIDLAND

COGE

NER

ATION

VENTU

RE10

312

4/23

/201

3

Naturalgasfue

led

combine

dcycle

combu

stionturbine

gene

rators(CTG

)with

HRSG

Naturalgas

2237

MMBT

U/H

Particulate

matter,total

(TPM

)Go

odcombu

stionpractice s

0.00

6LB/M

MBT

UEA

CHCT

G;TEST

PROTO

COL

BACT

PSD

02naturalgas

fired

CTGs

with

each

turbinecontaining

ahe

atrecovery

steam

gene

rator(HR

SG)

*MI0

405

MIDLAND

COGE

NER

ATION

VENTU

RE

MIDLAND

COGE

NER

ATION

VENTU

RE10

312

4/23

/201

3

Naturalgasfue

led

combine

dcycle

combu

stionturbine

gene

rators(CTG

)with

HRSG

Naturalgas

2237

MMBT

U/H

Particulate

matter,total&

10μ(TPM

10)

Good

combu

stionpractice s

0.00

6LB/M

MBT

UEA

CHCT

G;TEST

PROTO

COL

BACT

PSD

02naturalgas

fired

CTGs

with

each

turbinecontaining

ahe

atrecovery

steam

gene

rator(HR

SG)

*MI0

405

MIDLAND

COGE

NER

ATION

VENTU

RE

MIDLAND

COGE

NER

ATION

VENTU

RE10

312

4/23

/201

3

Naturalgasfue

led

combine

dcycle

combu

stionturbine

gene

rators(CTG

)with

HRSG

Naturalgas

2237

MMBT

U/H

Particulate

matter,total&

2.5μ(TPM

2.5)

Good

combu

stionpractice s

0.00

6LB/M

MBT

UEA

CHCT

G;TEST

PROTO

COL

BACT

PSD

02naturalgas

fired

CTGs

with

each

turbinecontaining

ahe

atrecovery

steam

gene

rator(HR

SG)

*MI0

405

MIDLAND

COGE

NER

ATION

VENTU

RE

MIDLAND

COGE

NER

ATION

VENTU

RE10

312

4/23

/201

3

Naturalgasfue

led

combine

dcycle

combu

stionturbine

gene

rators(CTG

)with

HRSG

anddu

ctbu

rner

(DB)

Naturalgas

2486

MMBT

U/H

Particulate

matter,total&

10μ(TPM

10)

Good

combu

stionpractice s

0.00

8LB/M

MBT

UTEST

PROTO

COL

BACT

PSD

0

2naturalgas

fired

CTGs

with

each

turbinecontaining

ahe

atrecovery

steam

gene

rator(HR

SG)w

itha

naturalgas

fired

ductbu

rne r

*MI0

405

MIDLAND

COGE

NER

ATION

VENTU

RE

MIDLAND

COGE

NER

ATION

VENTU

RE10

312

4/23

/201

3

gcombine

dcycle

combu

stionturbine

gene

rators(CTG

)with

HRSG

anddu

ctbu

rner

(DB)

Naturalgas

2486

MMBT

U/H

Particulate

matter,total&

2.5μ(TPM

2.5)

Good

combu

stionpractice s

0.00

8LB/M

MBT

UTEST

PROTO

COL

BACT

PSD

0

2naturalgas

fired

CTGs

with

each

turbinecontaining

ahe

atrecovery

steam

gene

rator(HR

SG)w

itha

naturalgas

fired

ductbu

rne r

*VA03

21

BRUNSW

ICK

COUNTY

POWER

STAT

ION

VIRG

INIA

ELEC

TRIC

ANDPO

WER

COMPA

NY

5240

400

13/12

/201

3CO

MBU

STIONTU

RBINE

GENER

ATORS,(3)

NaturalGa

s34

42MMBT

U/H

Particulate

matter,total&

2.5μ(TPM

2.5)

Lowsulfu

r/carbon

fuelandgood

combu

stionpractices.

0.00

33LB/M

MBT

U3HAV

G/WITHO

UT

DUCT

BURN

ING

BACT

PSD

0

Three(3)M

itsub

ishiM

501GA

Ccombu

stionturbine

gene

ratorswith

HRSG

ductbu

rners(naturalgas

fired

).

*VA03

21

BRUNSW

ICK

COUNTY

POWER

STAT

ION

VIRG

INIA

ELEC

TRIC

ANDPO

WER

COMPA

NY

5240

400

13/12

/201

3CO

MBU

STIONTU

RBINE

GENER

ATORS,(3)

NaturalGa

s34

42MMBT

U/H

Particulate

matter,total&

10μ(TPM

10)

Lowsulfu

r/carbon

fuelandgood

combu

stionpractices.

0.00

33LB/M

MBT

U3HAV

G/WITHO

UT

DUCT

BURN

ING

BACT

PSD

0

Three(3)M

itsub

ishiM

501GA

Ccombu

stionturbine

gene

ratorswith

HRSG

ductbu

rners(naturalgas

fired

).

*TX07

08LA

PALO

MA

ENER

GYCE

NTER

LAPA

LOMAEN

ERGY

CENTER,

LLC

1015

42PSDT

X128

82/7/20

13(2)com

bine

dcycle

turbines

naturalgas

650MW

Particulate

matter,total&

2.5μ(TPM

2.5)

0BA

CTPSD

0

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:Pa

rtic

ulat

es

Prop

osed

Part

icul

ate

Lim

it:11

.9lb

/hr=

0.00

4lb

/MM

Btu

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

hput

Thro

ughp

utU

nit

Pollu

tant

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

tEm

issi

onLi

mit

Avg

Tim

eCo

nditi

onCa

seBy

Case

Basi

sSt

anda

rdEm

issi

onLi

mit

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

*PA02

86

MOXIEEN

ERGY

LLC/PA

TRIOT

GENER

ATIONPLT

MOXIEEN

ERGY

LLC

4100

084A

1/31

/201

3Co

mbine

dCyclePo

wer

Blocks

472MW

(2)

NaturalGa

s0

Particulate

matter,total

(TPM

)0.00

57LB/M

MBT

UOTH

ERCA

SEBY

CASE

0Co

mbu

stionturbineandhe

atrecovery

steam

gene

ratorw

ithdu

ctbu

rner.

*PA02

86

MOXIEEN

ERGY

LLC/PA

TRIOT

GENER

ATIONPLT

MOXIEEN

ERGY

LLC

4100

084A

1/31

/201

3Co

mbine

dCyclePo

wer

Blocks

472MW

(2)

NaturalGa

s0

Particulate

matter,total&

10μ(TPM

10)

0.00

57LB/M

MBT

UOTH

ERCA

SEBY

CASE

0Co

mbu

stionturbineandhe

atrecovery

steam

gene

ratorw

ithdu

ctbu

rner.

*PA02

86

MOXIEEN

ERGY

LLC/PA

TRIOT

GENER

ATIONPLT

MOXIEEN

ERGY

LLC

4100

084A

1/31

/201

3Co

mbine

dCyclePo

wer

Blocks

472MW

(2)

NaturalGa

s0

Particulate

matter,total&

2.5μ(TPM

2.5)

0.00

57LB/M

MBT

UOTH

ERCA

SEBY

CASE

0Co

mbu

stionturbineandhe

atrecovery

steam

gene

ratorw

ithdu

ctbu

rner.

DE00

24GA

RRISONEN

ERGY

CENTER

GARR

ISONEN

ERGY

CENTER,

LLC/

CALPINE

CORP

ORA

TION

APC

2012

/009

81/30

/201

3Unit1

NaturalGa

s22

60millionBT

Us

Particulate

matter,total

(TPM

)FuelUsage

Restrictio

nto

natural gas

andlowsulfu

rdistillateoil

120.4TO

NS

12MONTH

ROLLINGAV

ERAG

EBA

CTPSD

0(1)3

09MW

GECo

mbine

dCycleCo

mbu

stionTurbine

Gene

ratin

g

*OH03

56

DUKE

ENER

GYHA

NGINGRO

CKEN

ERGY

DUKE

ENER

GYHA

NGINGRO

CK,LLC

P011

0487

12/18/20

12Turbines

(4)(mod

elGE

7FA)

DuctBu

rnersO

f fNAT

URA

LGA

S17

2MW

Particulate

matter,total&

10μ(TPM

10)

Burningnaturalgas

inan

efficient

combu

stionturbine

15LB/H

BACT

PSD

04GE

7FAcombine

dcycleturbines,whileop

erating

with

thedu

ctbu

rnerso

ff.

*OH03

56

DUKE

ENER

GYHA

NGINGRO

CKEN

ERGY

DUKE

ENER

GYHA

NGINGRO

CK,LLC

P011

0487

12/18/20

12Turbines

(4)(mod

elGE

7FA)

DuctBu

rnersO

nNAT

URA

LGA

S17

2MW

Particulate

matter,total&

10μ(TPM

10)

Burningnaturalgas

inan

efficient

combu

stionturbine

19.9

LB/H

BACT

PSD

04GE

7FAcombine

dcycleturbines,whileop

erating

with

thedu

ctbu

rnerso

ff.

*IN01

58

ST.JOSEPH

ENEG

RYCE

NTER,

LLC

ST.JOSEPH

ENER

GYCE

NTER,

LLC

14131

003

0057

912

/3/201

2

FOUR(4)N

ATURA

LGA

SCO

MBINED

CYCLE

COMBU

STION

TURB

INES

NAT

URA

LGA

S23

00MMBT

U/H

Particulate

matter,

filterable(FPM

)GO

ODCU

MBU

STIONPR

ACTICE

AND

FUEL

SPEC

IFICAT

ION

18LB/H

3HO

URS

BACT

PSD

0EA

CHTU

RBINEISEQ

UIPED

WITHNAT

URA

LGA

SFIRE

DDU

CTBU

RNER

S,AN

DHR

SG#

*IN01

58

ST.JOSEPH

ENEG

RYCE

NTER,

LLC

ST.JOSEPH

ENER

GYCE

NTER,

LLC

14131

003

0057

912

/3/201

2

FOUR(4)N

ATURA

LGA

SCO

MBINED

CYCLE

COMBU

STION

TURB

INES

NAT

URA

LGA

S23

00MMBT

U/H

Particulate

matter,total&

10μ(TPM

10)

GOODCU

MBU

STIONPR

ACTICE

AND

FUEL

SPEC

IFICAT

ION

18LB/H

3HO

URS

BACT

PSD

0EA

CHTU

RBINEISEQ

UIPED

WITHNAT

URA

LGA

SFIRE

DDU

CTBU

RNER

S,AN

DHR

SG#

*IN01

58

ST.JOSEPH

ENEG

RYCE

NTER,

LLC

ST.JOSEPH

ENER

GYCE

NTER,

LLC

14131

003

0057

912

/3/201

2

FOUR(4)N

ATURA

LGA

SCO

MBINED

CYCLE

COMBU

STION

TURB

INES

NAT

URA

LGA

S23

00MMBT

U/H

Particulate

matter,total&

2.5μ(TPM

2.5)

GOODCO

MBU

STIONPR

ACTICE

AND

FUEL

SPEC

IFICAT

ION

18LB/H

3HO

URS

BACT

PSD

0EA

CHTU

RBINEISEQ

UIPED

WITHNAT

URA

LGA

SFIRE

DDU

CTBU

RNER

S,AN

DHR

SG#

TX06

18CH

ANNEL

ENER

GYCE

NTERLLC

CHAN

NEL

ENER

GYCE

NTERLLC

PSDT

X955

M1

10/15/20

12Co

mbine

dCycle

Turbine

naturalgas

180MW

Particulate

matter,total

(TPM

)Go

odcombu

stionandtheuseof

gaseou

sfue

l27

LB/H

BACT

PSD

0TheturbineisaSiem

ens5

01Fwith

ductbu

rne r

TX06

18CH

ANNEL

ENER

GYCE

NTERLLC

CHAN

NEL

ENER

GYCE

NTERLLC

PSDT

X955

M1

10/15/20

12Co

mbine

dCycle

Turbine

naturalgas

180MW

Particulate

matter,total&

10μ(TPM

10)

good

combu

stionandtheuseof

gaseou

sfue

l27

LB/H

BACT

PSD

0TheturbineisaSiem

ens5

01Fwith

ductbu

rne r

TX06

18CH

ANNEL

ENER

GYCE

NTERLLC

CHAN

NEL

ENER

GYCE

NTERLLC

PSDT

X955

M1

10/15/20

12Co

mbine

dCycle

Turbine

naturalgas

180MW

Particulate

matter,total&

2.5μ(TPM

2.5)

good

combu

stionandtheuseof

gaseou

sfue

l27

LB/H

BACT

PSD

0TheturbineisaSiem

ens5

01Fwith

ductbu

rne r

FL03

37PO

LKPO

WER

STAT

ION

TAMPA

ELEC

TRIC

COMPA

NY

1050

23303

4AC

10/14/20

12Co

mbine

cyclepo

wer

block(4

on1)

naturalgas

1160

MW

Particulate

matter,

filterable&10

μ(FPM

10)

workpractices

2GR

S/10

0SCF

OFGA

SBA

CTPSD

04naturalgas

fueled

nominal16

5MW

simplecycle

combu

stionturbineelectricalgene

rators(CTG

s)

PA02

78

MOXIELIBE

RTY

LLC/AS

YLUM

POWER

PLT

MOXIEEN

ERGY

LLC

0800

045A

10/10/20

12

Combine

dcycle

Turbines

(2)

Natural

gasfire

dNaturalGa

s32

77MMBT

U/H

Particulate

matter,total

(TPM

)Usin

gfuelwith

little

orno

ashand

sulfu

rcon

tent.

0.00

4LB/M

MBT

UFO

R46

8MW

POWER

BLOCK

BACT

PSD

0

2combine

cycleTurbines,eachwith

acombu

stion

turbineandhe

atrecovery

steam

gene

ratorw

ithdu

ctbu

rner

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:Pa

rtic

ulat

es

Prop

osed

Part

icul

ate

Lim

it:11

.9lb

/hr=

0.00

4lb

/MM

Btu

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

hput

Thro

ughp

utU

nit

Pollu

tant

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

tEm

issi

onLi

mit

Avg

Tim

eCo

nditi

onCa

seBy

Case

Basi

sSt

anda

rdEm

issi

onLi

mit

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

TX06

19DE

ERPA

RKEN

ERGY

CENTER

DEER

PARK

ENER

GYCE

NTERLLC

PSDT

X979

M2

9/26

/201

2Co

mbine

dCycle

Turbine

naturalgas

180MW

Particulate

matter,total

(TPM

)good

combu

stionanduseof

natural

gas

27LB/H

BACT

PSD

0

naturalgas

fired

combine

dcycleturbinegene

rator

with

ahe

atrecovery

steam

gene

ratore

quippe

dwith

adu

ctbu

rner.TheturbineisaSiem

ens5

01F

TX06

19DE

ERPA

RKEN

ERGY

CENTER

DEER

PARK

ENER

GYCE

NTERLLC

PSDT

X979

M2

9/26

/201

2Co

mbine

dCycle

Turbine

naturalgas

180MW

Particulate

matter,total&

10μ(TPM

10)

good

combu

stionandtheuseof

naturalgas

27LB/H

BACT

PSD

0

naturalgas

fired

combine

dcycleturbinegene

rator

with

ahe

atrecovery

steam

gene

ratore

quippe

dwith

adu

ctbu


ens 5

01F

TX06

19DE

ERPA

RKEN

ERGY

CENTER

DEER

PARK

ENER

GYCE

NTERLLC

PSDT

X979

M2

9/26

/201

2Co

mbine

dCycle

Turbine

naturalgas

180MW

Particulate

matter,total&

2.5μ(TPM

2.5)

27LB/H

BACT

PSD

0

naturalgas

fired

combine

dcycleturbinegene

rator

with

ahe

atrecovery

steam

gene

ratore

quippe

dwith

adu

ctbu


ens5

01F

TX06

20ES

JOSLIN

POWER

PLAN

TCA

LHOUNPO

RTAU

THORITY

PSDT

X125

69/12

/201

2Co

mbine

dcyclegas

turbine

naturalgas

195MW

Particulate

matter,total&

2.5μ(TPM

2.5)

18LB/H

PERTU

RBINE

BACT

PSD

03combu

stionturbinegene

rators(CTG

)willbe

the

Gene

ralElectric

7FA.

Nodu

ctbu

rners .

TX06

20ES

JOSLIN

POWER

PLAN

TCA

LHOUNPO

RTAU

THORITY

PSDT

X125

69/12

/201

2Co

mbine

dcyclegas

turbine

naturalgas

195MW

Particulate

matter,total&

10μ(TPM

10)

good

combu

stionandnaturalgas

asfuel

18LB/H

PERTU

RBINE

BACT

PSD

03combu

stionturbinegene

rators(CTG

)willbe

the

Gene

ralElectric

7FA.

Nodu

ctbu

rners .

TX06

20ES

JOSLIN

POWER

PLAN

TCA

LHOUNPO

RTAU

THORITY

PSDT

X125

69/12

/201

2Co

mbine

dcyclegas

turbine

naturalgas

195MW

Particulate

matter,total

(TPM

)good

combu

stionandnaturalgas

asfuel

18LB/H

PERTU

RBINE

BACT

PSD

03combu

stionturbinegene

rators(CTG

)willbe

the

Gene

ralElectric

7FA.

Nodu

ctbu

rners .

*WY00

70

CHEYEN

NEPR

AIRIE

GENER

ATING

STAT

ION

BLAC

KHILLSPO

WER

,INC.

CT12

636

8/28

/201

2Co

mbine

dCycle

Turbine(EP0

1)NaturalGa

s40

MW

Particulate

matter,total

(TPM

)good

combu

stionpractice s

4LB/H

3HO

URAV

ERAG

EBA

CTPSD

17.5

TONS

CALENDA

RYEAR

(5)4

0MW

GELM

6000

combu

stionturbinegene

rators

*WY00

70

CHEYEN

NEPR

AIRIE

GENER

ATING

STAT

ION

BLAC

KHILLSPO

WER

,INC.

CT12

636

8/28

/201

2Co

mbine

dCycle

Turbine(EP0

2)NaturalGa

s40

MW

Particulate

matter,total

(TPM

)good

combu

stionpractice s

4LB/H

3HO

URAV

ERAG

EBA

CTPSD

17.5

TONS

CALENDA

RYEAR

(5)4

0MW

GELM

6000

combu

stionturbinegene

rators

*VA03

19

GATEWAY

COGE

NER

ATION1,

LLC

SMAR

TWAT

ERPR

OJECT

GATEWAY

GREEN

ENER

GY52

37500

28/27

/201

2CO

MBU

STION

TURB

INES,(2)

NaturalGa

s59

3MMBT

U/H

Particulate

matter,total&

2.5μ(TPM

2.5)

Cleanbu

rningfuelsa

ndgood

combu

stionpractices.

5LB/H

3HAV

GBA

CTPSD

02combu

sionturbines

(RollsRo

yceTren

t60WLE),no

ductbu

rning.

*VA03

19

GATEWAY

COGE

NER

ATION1,

LLC

SMAR

TWAT

ERPR

OJECT

GATEWAY

GREEN

ENER

GY52

37500

28/27

/201

2CO

MBU

STION

TURB

INES,(2)

NaturalGa

s59

3MMBT

U/H

Particulate

matter,total&

10μ(TPM

10)

Cleanbu

rningfuelsa

ndgood

combu

stionpractices.

5LB/H

3HAV

GBA

CTPSD

02combu

sionturbines

(RollsRo

yceTren

t60WLE),no

ductbu

rning.

LA02

57SA

BINEPA

SSLN

GTERM

INA L

SABINEPA

SSLN

G,LP

&SA

BINEPA

SSLIQUEFAC

TION,LL

PSDLA

703(M3)

12/6/201

1

Combine

dCycle

Refrigeration

CompressorT

urbine

s(8)

naturalgas

286MMBT

U/H

Particulate

matter,total

(TPM

)Go

odcombu

stionpractices

andfueled

bynaturalgas

2.08

LB/H

HOURLY

MAX

IMUM

BACT

PSD

0

LA02

56CO

GENER

ATION

PLAN

TWESTLAK

EVINYLS

COMPA

NYLP

PSDLA

754

12/6/201

1CO

GENER

ATIONTR

AINS

13(1

10,2

10,3

10)

NAT

URA

LGA

S47

5MMBT

U/H

Particulate

matter,total&

10μ(TPM

10)

USE

OFNAT

URA

LGA

SAS

FUEL

AND

GOODCO

MBU

STIONPR

ACTICE

S3.72

LB/H

HOURLY

MAX

IMUM

BACT

PSD

0

EACH

COGE

NTR

AINCO

NSISTSOFA50

MW

GELM

6000

PFSPRINTTU

RBINEAN

DAHE

ATRE

COVE

RYSTEA

MGE

NER

ATOREQ

UIPPEDWITHADU

CTBU

RNER

.

LA02

56CO

GENER

ATION

PLAN

TWESTLAK

EVINYLS

COMPA

NYLP

PSDLA

754

12/6/201

1CO

GENER

ATIONTR

AINS

13(1

10,2

10,3

10)

NAT

URA

LGA

S47

5MMBT

U/H

Particulate

matter,total&

2.5μ(TPM

2.5)

USE

OFNAT

URA

LGA

SAS

FUEL

AND

GOODCO

MBU

STIONPR

ACTICE

S3.72

LB/H

HOURLY

MAX

IMUM

BACT

PSD

0

EACH

COGE

NTR

AINCO

NSISTSOFA50

MW

GELM

6000

PFSPRINTTU

RBINEAN

DAHE

ATRE

COVE

RYSTEA

MGE

NER

ATOREQ

UIPPEDWITHADU

CTBU

RNER

.

*MI0

402

SUMPTER

POWER

PLAN

T

WOLVER

INEPO

WER

SUPP

LYCO

OPERA

TIVE

INC.

8111

11/17/20

11

Combine

dcycle

combu

stionturbinew/

HRSG

Naturalgas

130MW

electricalou

tpu t

Particulate

matter,total&

10μ(TPM

10)

0.00

66LB/M

MBT

UTES T

OTH

ERCA

SEBY

CASE

0Thisisacombine

dcyclecombu

stionturbine

*MI0

402

SUMPTER

POWER

PLAN

T

WOLVER

INEPO

WER

SUPP

LYCO

OPERA

TIVE

INC.

8111

11/17/20

11

Combine

dcycle

combu

stionturbinew/

HRSG

Naturalgas

130MW

electricalou

tpu t

Particulate

matter,total&

2.5μ(TPM

2.5)

0.00

66LB/M

MBT

UTES T

BACT

PSD

0Thisisacombine

dcyclecombu

stionturbine

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:Pa

rtic

ulat

es

Prop

osed

Part

icul

ate

Lim

it:11

.9lb

/hr=

0.00

4lb

/MM

Btu

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

hput

Thro

ughp

utU

nit

Pollu

tant

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

tEm

issi

onLi

mit

Avg

Tim

eCo

nditi

onCa

seBy

Case

Basi

sSt

anda

rdEm

issi

onLi

mit

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

CA12

12PA

LMDA

LEHY

BRID

POWER

PROJECT

CITY

OFPA

LMDA

LESE

0901

10/18/20

11

COMBU

STION

TURB

INES

(NORM

ALOPERA

TION)

NAT

URA

LGA

S15

4MW

Particulate

matter,total

(TPM

)USE

PUCQUALITYNAT

URA

LGA

S0.00

48LB/M

MBT

U9HR

AVG(NO

DUCT

BURN

ING)

BACT

PSD

02NAT

URA

LGA

SFIRE

DCO

MBU

STIONTU

RBINE

GENER

ATORS

(CTG

S)

CA12

12PA

LMDA

LEHY

BRID

POWER

PROJECT

CITY

OFPA

LMDA

LESE

0901

10/18/20

11

COMBU

STION

TURB

INES

(NORM

ALOPERA

TION)

NAT

URA

LGA

S15

4MW

Particulate

matter,total&

10μ(TPM

10)

USE

PUCQUALITYNAT

URA

LGA

S0.00

48LB/M

MBT

U9HR

AVG(NO

DUCT

BURN

ING)

BACT

PSD

02NAT

URA

LGA

SFIRE

DCO

MBU

STIONTU

RBINE

GENER

ATORS

(CTG

S)

CA12

12PA

LMDA

LEHY

BRID

POWER

PROJECT

CITY

OFPA

LMDA

LESE

0901

10/18/20

11

COMBU

STION

TURB

INES

(NORM

ALOPERA

TION)

NAT

URA

LGA

S15

4MW

Particulate

matter,total&

2.5μ(TPM

2.5)

USE

PUCQUALITYNAT

URA

LGA

S0.00

48LB/M

MBT

U9HR

AVG(NO

DUCT

BURN

ING)

BACT

PSD

02NAT

URA

LGA

SFIRE

DCO

MBU

STIONTU

RBINE

GENER

ATORS

(CTG

S)

TX06

00

THOMAS

C.FERG

USO

NPO

WER

PLAN

TLO

WER

COLO

RADO

RIVE

RAU

THORIT Y

PSDT

X124

49/1/20

11Naturalgasfired

turbines

naturalgas

390MW

Particulate

matter,total&

2.5μ(TPM

2.5)

pipe

linequ

ality

naturalgas

33.43LB/H

1H

BACT

PSD

0Po

wer

Plant.Tw

onaturalgas

fired

combine

dcycle

turbinegene

rators(GE7FA)

with

unfired

HRS G

LA02

54

NINEM

ILEPO

INT

ELEC

TRIC

GENER

ATING

PLAN

TEN

TERG

YLO

UISIANA

LLC

PSDLA

752

8/16

/201

1

COMBINED

CYCLE

TURB

INEGE

NER

ATORS

(UNITS6A

&am

p;6B

)NAT

URA

LGA

S71

46MMBT

U/H

Particulate

matter,total

<

2.5μ

(TPM

2.5)

WHI

FIRINGNAT

URA

GAS:US

OF

PIPELINEQUALITYNAT

URA

LGA

SAN

DGOODCO

MBU

STIONPR

ACTICE

S

WHILE

FIRINGFU

ELOIL:U

SEOFULTRA

LOW

SULFURFU

ELOILAN

DGO

OD

COMBU

STIONPR

ACTICE

S26

.23LB/H

HOURLYAV

ERAG

EW/O

DUCT

BURN

ERBA

CTPSD

02CO

MBINED

CYCLEGA

STU

RBINES

WITHDU

CTBU

RNER

S

LA02

54

NINEM

ILEPO

INT

ELEC

TRIC

GENER

ATING

PLAN

TEN

TERG

YLO

UISIANA

LLC

PSDLA

752

8/16

/201

1

COMBINED

CYCLE

TURB

INEGE

NER

ATORS

(UNITS6A

&am

p;6B

)NAT

URA

LGA

S71

46MMBT

U/H

Particulate

matter,total&

10μ(TPM

10)

WHI

FIRINGNAT

URA

GAS:US

OF

PIPELINEQUALITYNAT

URA

LGA

SAN

DGOODCO

MBU

STIONPR

ACTICE

S

WHILE

FIRINGFU

ELOIL:U

SEOFULTRA

LOW

SULFURFU

ELOILAN

DGO

OD

COMBU

STIONPR

ACTICE

S26

.23LB/H

HOURLYAV

ERAG

EW/O

DUCT

BURN

ERBA

CTPSD

02CO

MBINED

CYCLEGA

STU

RBINES

WITHDU

CTBU

RNER

S

CA11

92AV

ENAL

ENER

GYPR

OJECT

AVEN

ALPO

WER

CENTERLLC

SJ08

016/21

/201

1

COMBU

STIONTU

RBINE

#1(NORM

ALOPERA

TION,N

ODU

CTBU

RNING)

NAT

URA

LGA

S18

0MW

Particulate

matter,total

(TPM

)USE

PUCQUALITYNAT

URA

LGA

S8.91

LB/H

12MONTH

ROLLINGAV

GBA

CTPSD

0

CA11

92AV

ENAL

ENER

GYPR

OJECT

AVEN

ALPO

WER

CENTERLLC

SJ08

016/21

/201

1

COMBU

STIONTU

RBINE

#1(NORM

ALOPERA

TION,N

ODU

CTBU

RNING)

NAT

URA

LGA

S18

0MW

Particulate

matter,total

<

10μ

(TPM

10)

USE

PUCQUALITYNAT

URA

LGA

S8.91

LB/H

12MONTH

ROLLINGAV

GBA

CTPSD

0

CA11

92AV

ENAL

ENER

GYPR

OJECT

AVEN

ALPO

WER

CENTERLLC

SJ08

016/21

/201

1

COMBU

STIONTU

RBINE

#2(NORM

ALOPERA

TION,N

ODU

CTBU

RNING)

NAT

URA

LGA

S18

0MW

Particulate

matter,total

(TPM

)USE

PUCQUALITYNAT

URA

LGA

S8.91

LB/H

12MONTH

ROLLINGAV

GBA

CTPSD

0

CA11

92AV

ENAL

ENER

GYPR

OJECT

AVEN

ALPO

WER

CENTERLLC

SJ08

016/21

/201

1

COMBU

STIONTU

RBINE

#2(NORM

ALOPERA

TION,N

ODU

CTBU

RNING)

NAT

URA

LGA

S18

0MW

Particulate

matter,total&

10μ(TPM

10)

USE

PUCQUALITYNAT

URA

LGA

S8.91

LB/H

12MONTH

ROLLINGAV

GBA

CTPSD

0

CA11

92AV

ENAL

ENER

GYPR

OJECT

AVEN

ALPO

WER

CENTERLLC

SJ08

016/21

/201

1

COMBU

STIONTU

RBINE

#1(NORM

ALOPERA

TION,W

ITH

DUCT

BURN

ING)

NAT

URA

LGA

S18

0MW

Particulate

matter,total

(TPM

)USE

PUCQUALITYNAT

URA

LGA

S11

.78LB/H

12MONTH

ROLLINGAV

GBA

CTPSD

0

CA11

92AV

ENAL

ENER

GYPR

OJECT

AVEN

ALPO

WER

CENTERLLC

SJ08

016/21

/201

1

COMBU

STIONTU

RBINE

#1(NORM

ALOPERA

TION,W

ITH

DUCT

BURN

ING)

NAT

URA

LGA

S18

0MW

Particulate

matter,total&

10μ(TPM

10)

USE

PUCQUALITYNAT

URA

LGA

S11

.78LB/H

12MONTH

ROLLINGAV

GBA

CTPSD

0

CA11

92AV

ENAL

ENER

GYPR

OJECT

AVEN

ALPO

WER

CENTERLLC

SJ08

016/21

/201

1

COMBU

STIONTU

RBINE

#2(NORM

ALOPERA

TION,W

ITH

DUCT

BURN

ING)

NAT

URA

LGA

S18

0MW

Particulate

matter,total

(TPM

)USE

PUCQUALITYNAT

URA

LGA

S11

.78LB/H

12MONTH

ROLLINGAV

GBA

CTPSD

0

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:Pa

rtic

ulat

es

Prop

osed

Part

icul

ate

Lim

it:11

.9lb

/hr=

0.00

4lb

/MM

Btu

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

hput

Thro

ughp

utU

nit

Pollu

tant

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

tEm

issi

onLi

mit

Avg

Tim

eCo

nditi

onCa

seBy

Case

Basi

sSt

anda

rdEm

issi

onLi

mit

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

CA11

92AV

ENAL

ENER

GYPR

OJECT

AVEN

ALPO

WER

CENTERLLC

SJ08

016/21

/201

1

COMBU

STIONTU

RBINE

#2(NORM

ALOPERA

TION,W

ITH

DUCT

BURN

ING)

NAT

URA

LGA

S18

0MW

Particulate

matter,total&

10μ(TPM

10)

USE

PUCQUALITYNAT

URA

LGA

S11

.78LB/H

12MONTH

ROLLINGAV

GBA

CTPSD

0

CA12

11

COLU

SAGE

NER

ATING

STAT

ION

PACIFICGA

S&

ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(SHU

TDOWN

PERIODS

)NAT

URA

LGA

S17

2MW

Particulate

matter,total

(TPM

)USE

NAT

URA

LGA

S6LB/H

TURB

INE

SHUTD

OWN

PERIODS

BACT

PSD

0(2)N

ATURA

LGA

SFIRE

DTU

RBINES.B

OTH

TURB

INES

EQUIPPEDWITHDU

CTBU

RNER

ANDHR

SG.

CA12

11

COLU

SAGE

NER

ATING

STAT

ION

PACIFICGA

S&

ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(SHU

TDOWN

PERIODS

)NAT

URA

LGA

S17

2MW

Particulate

matter,total&

10μ(TPM

10)

USE

NAT

URA

LGA

S6LB/H

TURB

INE

SHUTD

OWN

PERIODS

BACT

PSD

0(2)N

ATURA

LGA

SFIRE

DTU

RBINES.B

OTH

TURB

INES

EQUIPPEDWITHDU

CTBU

RNER

ANDHR

SG.

CA12

11

COLU

SAGE

NER

ATING

STAT

ION

PACIFICGA

S&

ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(WAR

MSTAR

TUPPERIODS

)NAT

URA

LGA

S17

2MW

Particulate

matter,total

(TPM

)USE

NAT

URA

LGA

S12

LB/H

WAR

MSTAR

TUP

PERIODS

BACT

PSD

0(2)N

ATURA

LGA

SFIRE

DTU

RBINES.B

OTH

TURB

INES

EQUIPPEDWITHDU

CTBU

RNER

ANDHR

SG.

CA12

11

COLU

SAGE

NER

ATING

STAT

ION

PACIFICGA

S&

ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(WAR

MSTAR

TUPPERIODS

)NAT

URA

LGA

S17

2MW

matter,total

<

10μ

(TPM

10)

USE

NAT

URA

LGA

S12

LB/H

WAR

MSTAR

TUP

PERIODS

BACT

PSD

0(2)N

ATURA

LGA

SFIRE

DTU

RBINES.B

OTH

TURB

INES

EQUIPPEDWITHDU

CTBU

RNER

ANDHR

SG.

CA12

11

COLU

SAGE

NER

ATING

STAT

ION

PACIFICGA

S&

ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(HOT

STAR

TUPPERIODS

)NAT

URA

LGA

S17

2MW

Particulate

matter,total

(TPM

)USE

NAT

URA

LGA

S12

LB/H

HOTSTAR

TUP

PERIODS

BACT

PSD

0(2)N

ATURA

LGA

SFIRE

DTU

RBINES.B

OTH

TURB

INES

EQUIPPEDWITHDU

CTBU

RNER

ANDHR

SG.

CA12

11

COLU

SAGE

NER

ATING

STAT

ION

PACIFICGA

S&

ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(HOT

STAR

TUPPERIODS

)NAT

URA

LGA

S17

2MW

Particulate

matter,total

<

10μ

(TPM

10)

USE

NAT

URA

LGA

S12

LB/H

HOTSTAR

TUP

PERIODS

BACT

PSD

0(2)N

ATURA

LGA

SFIRE

DTU

RBINES.B

OTH

TURB

INES

EQUIPPEDWITHDU

CTBU

RNER

ANDHR

SG.

CA12

11

COLU

SAGE

NER

ATING

STAT

ION

PACIFICGA

S&

ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(COLD

STAR

TUPPERIODS

)NAT

URA

LGA

S17

2MW

Particulate

matter,

filterable(FPM

)USE

NAT

URA

LGA

S12

LB/H

COLD

STAR

TUP

PERIODS

BACT

PSD

0(2)N

ATURA

LGA

SFIRE

DTU

RBINES.B

OTH

TURB

INES

EQUIPPEDWITHDU

CTBU

RNER

ANDHR

SG.

CA12

11

COLU

SAGE

NER

ATING

STAT

ION

PACIFICGA

S&

ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(COLD

STAR

TUPPERIODS

)NAT

URA

LGA

S17

2MW

Particulate

matter,total&

10μ(TPM

10)

USE

NAT

URA

LGA

S12

LB/H

COLD

STAR

TUP

PERIODS

BACT

PSD

0(2)N

ATURA

LGA

SFIRE

DTU

RBINES.B

OTH

TURB

INES

EQUIPPEDWITHDU

CTBU

RNER

ANDHR

SG.

CA12

11

COLU

SAGE

NER

ATING

STAT

ION

PACIFICGA

S&

ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(NORM

ALOPERA

TION)

NAT

URA

LGA

S17

2MW

Particulate

matter,total&

10μ(TPM

10)

USE

NAT

URA

LGA

S13

.5LB/H

STAC

KTEST

BACT

PSD

0(2)N

ATURA

LGA

SFIRE

DTU

RBINES.B

OTH

TURB

INES

EQUIPPEDWITHDU

CTBU

RNER

ANDHR

SG.

CA12

11

COLU

SAGE

NER

ATING

STAT

ION

PACIFICGA

S&

ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(NORM

ALOPERA

TION)

NAT

URA

LGA

S17

2MW

Particulate

matter,

filterable(FPM

)USE

NAT

URA

LGA

S13

.5LB/H

STAC

KTEST

BACT

PSD

0(2)N

ATURA

LGA

SFIRE

DTU

RBINES.B

OTH

TURB

INES

EQUIPPEDWITHDU

CTBU

RNER

ANDHR

SG.

OR00

48CA

RTYPLAN

TPO

RTLANDGE

NER

ALELEC

TRIC

2500

16ST

0212

/29/20

10

COMBINED

CYCLE

NAT

URA

LGA

SFIRE

DELEC

TRIC

GENER

ATING

UNI T

NAT

URA

LGA

S28

66MMBT

U/H

Particulate

matter,

filterable&10

μ(FPM

10)

CLEA

NFU

E L2.5LB/M

MCF

BACT

PSD

0

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:Pa

rtic

ulat

es

Prop

osed

Part

icul

ate

Lim

it:11

.9lb

/hr=

0.00

4lb

/MM

Btu

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

hput

Thro

ughp

utU

nit

Pollu

tant

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

tEm

issi

onLi

mit

Avg

Tim

eCo

nditi

onCa

seBy

Case

Basi

sSt

anda

rdEm

issi

onLi

mit

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

*IL01

12NELSO

NEN

ERGY

CENTER

INVE

NER

GYNELSO

N,

LLC

9808

0039

12/28/20

10ElectricGe

neratio

nFacility

NaturalGa

s22

0MW

each

Particulate

matter,total

<

2.5μ

(TPM

2.5)

0.00

6LB/M

MBT

UHO

URLYAV

ERAG

EBA

CTPSD

02combine

dcyclecombu

stionturbines

followed

byHR

SGsu

singdu

ctbu

rners.

*IL01

12NELSO

NEN

ERGY

CENTER

INVE

NER

GYNELSO

N,

LLC

9808

0039

12/28/20

10ElectricGe

neratio

nFacility

NaturalGa

s22

0MW

each

Particulate

matter,total&

10μ(TPM

10)

0.01

2LB/M

MBT

UHO

URLYAV

ERAG

EBA

CTPSD

02combine

dcyclecombu

stionturbines

followed

byHR

SGsu

singdu

ctbu

rners.

AK00

73

INTERN

ATIONAL

STAT

IONPO

WER

PLAN

TCH

UGA

CHELEC

TRIC

ASSO

CIAT

ION

AQ01

64CP

T01

12/20/20

10FuelCo

mbu

stion

NaturalGa

s59

900HP

Particulate

matter,

filterable&10

μ(FPM

10)

Combu

stionTurbines

EUIDs5

8use

good

combu

stionpractices

involve

increasin

gtheresid

ence

timeand

excessoxygen

toen

sure

complete

combu

stionwhich

inturn

minim

izeparticulates

with

outa

naddon

control

0.00

66LB/M

MBT

U3HO

UR

BACT

PSD

0EU

IDs5

8Co

mbine

dCycleNaturalGa

sfired

Combu

stionTurbines

ratedat

59,900

hp(44.7MW)

VA03

15

WAR

RENCO

UNTY

POWER

PLAN

TDO

MINION

VIRG

INIA

ELEC

TRIC

ANDPO

WER

COMPA

NY

8139

100

712

/17/20

10

COMBINED

CYCLE

TURB

INE&am

p;DU

CTBU

RNER

,3NaturalGa

s29

96MMBT

U/H

Particulate

matter,total&

10μ(TPM

10)

NaturalGa

sonly,fuelhasm

axim

umsulfu

rcon

tent

of0.00

03%by

weight .

8LB/H

3HR

AVG.

(WITHO

UTDU

CTBU

RNER

FIRING)

BACT

PSD

0

Threeun

its(M

itsub

ishinaturalgasfired

combu

stion

turbine(CT)

gene

rator,M

odelM50

1GA

C),w

ithdu

ctbu

rner

VA03

15

WAR

RENCO

UNTY

POWER

PLAN

TDO

MINION

VIRG

INIA

ELEC

TRIC

ANDPO

WER

COMPA

NY

8139

100

712

/17/20

10

COMBINED

CYCLE

TURB

INE&am

p;DU

CTBU

RNER

,3NaturalGa

s29

96MMBT

U/H

Particulate

matter,total&

2.5μ(TPM

2.5)

NaturalGa

sonly,fuelhasm

axim

umsulfu

rcon

tent

of0.00

03%by

weight .

8LB/H

3HR

AVG.

(WITHO

UTDU

CTBU

RNER

FIRING)

BACT

PSD

0

Threeun

its(M

itsub

ishinaturalgasfired

combu

stion

turbine(CT)

gene

rator,M

odelM50

1GA

C),w

ithdu

ctbu

rner

TX05

90KINGPO

WER

STAT

ION

PONDE

RACA

PITA

LMAN

AGEM

ENTGP

INC

PSDT

X112

58/5/20

10Turbine

naturalgas

1350

MW

Particulate

matter,total

(TPM

)

uselowashfuel(naturalgaso

rlow

sulfu

rdieselasa

backup

)and

good

combu

stionpractices

11.1

LB/H

BACT

PSD

0

2configurationscen

arios:either

four

Siem

ensS

GT6

5000

FCT

Gsincombine

dcyclemod

e(Scenario

A)or

four

GEFram

e7FACT

Gsincombine

dcyclemod

e(Scenario

B).

TX05

90KINGPO

WER

STAT

ION

PONDE

RACA

PITA

LMAN

AGEM

ENTGP

INC

PSDT

X112

58/5/20

10Turbine

naturalgas

1350

MW

Particulate

matter,total&

10μ(TPM

10)

useof

lowashfuel(naturalgaso

rlow

sulfu

rdieselasa

backup

)11

.1LB/H

BACT

PSD

0

2configurationscen

arios:either

four

Siem

ensS

GT6

5000

FCT

Gsincombine

dcyclemod

e(Scenario

A)or

four

GEFram

e7FACT

Gsincombine

dcyclemod

e(Scenario

B).

TX05

90KINGPO

WER

STAT

ION

PONDE

RACA

PITA

LMAN

AGEM

ENTGP

INC

PSDT

X112

58/5/20

10Turbine

naturalgas

1350

MW

Particulate

matter,total&

2.5μ(TPM

2.5)

useof

lowashfuel(naturalgaso

rlow

sulfu

rdieselasa

backup

)11

.1LB/H

BACT

PSD

0

2configurationscen

arios:either

four

Siem

ensS

GT6

5000

FCT

Gsincombine

dcyclemod

e(Scenario

A)or

four

GEFram

e7FACT

Gsincombine

dcyclemod

e(Scenario

B).

*CO00

73

PUEB

LOAIRP

ORT

GENER

ATING

STAT

ION

BLAC

KHILLSELEC

TRIC

GENER

ATION,LLC

09PB

0591

7/22

/201

0Four

combine

dcycle

combu

tionturbines

naturalgas

373mmbtu/hr

Particulate

matter,total

(TPM

)Use

ofpipe

linequ

ality

naturalgas

and

good

combu

stor

desig

n4.3LB/HR

AVEOVE

RSTAC

KTEST

LENGT

HBA

CTPSD

0

ThreeGE

,LMS600

0PF,naturalgasfired

,com

bine

dcycleCT

G,ratedat

373MMBtupe

rhou

reach,based

onHH

Vandon

e(1)H

RSGeach

with

noDu

ctBu

rners.

7CT

soverall.

*CO00

73

PUEB

LOAIRP

ORT

GENER

ATING

STAT

ION

BLAC

KHILLSELEC

TRIC

GENER

ATION,LL C

09PB

0591

7/22

/201

0Four

combine

dcycle

combu

tionturbines

naturalgas

373mmbtu/hr

Particulate

matter,total&

10μ(TPM

10)

Use

ofpipe

linequ

ality

naturalgas

and

good

combu

stor

desig

n4.3LB/HR

AVEOVE

RSTAC

KTEST

LENGT

HBA

CTPSD

0

ThreeGE

,LMS600

0PF,naturalgasfired

,com

bine

dcycleCT

G,ratedat

373MMBtupe

rhou

reach,based

onHH

Vandon

e(1)H

RSGeach

with

noDu

ctBu

rners.

7CT

soverall.

ID00

18LANGL

EYGU

LCH

POWER

PLAN

TIDAH

OPO

WER

COMPA

NY

P20

09.009

26/25

/201

0

COMBU

STIONTU

RBINE,

COMBINED

CYCLEW/

DUCT

BURN

ERNAT

URA

LGA

S(ONLY)

2375

.28MMBT

U/H

Particulate

matter,

filterable&10

μ(FPM

10)

GOODCO

MBU

STIONPR

ACTICE

S(GCP

)0

SEENOTE

BACT

PSD

0SIEM

ENSSG

T650

00FCO

MBU

STIONTU

RBINE(NGC

T,CC

GT),du

ctbu

rne r

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#2(NORM

ALOPERA

TION,N

ODU

CTBU

RNING)

NAT

URA

LGA

S15

4MW

Particulate

matter,total

(TPM

)PU

CQUALITYNAT

URA

LGA

S12

LB/H

12MONTH

ROLLINGAV

G(NO

DUCT

BURN

ING)

BACT

PSD

015

4MW

Combine

dCycleCo

mbu

stionTurbine

Gene

rator

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#2(NORM

ALOPERA

TION,N

ODU

CTBU

RNING)

NAT

URA

LGA

S15

4MW

Particulate

matter,total&

2.5μ(TPM

2.5)

PUCQUALITYNAT

URA

LGA

S12

LB/H

PUCQUALITY

NAT

URA

LGA

SBA

CTPSD

015

4MW

Combine

dCycleCo

mbu

stionTurbine

Gene

rator

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#1(NORM

ALOPERA

TION,N

ODU

CTBU

RNING)

NaturalGa

s15

4MW

Particulate

matter,total

(TPM

)PU

CQUALITYNAT

URA

LGA

S12

LB/H

12MONTH

ROLLINGAV

G(NO

DUCT

BURN

ING)

BACT

PSD

015

4MW

Combine

dCycleCo

mbu

stionTurbine

Gene

rator

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:Pa

rtic

ulat

es

Prop

osed

Part

icul

ate

Lim

it:11

.9lb

/hr=

0.00

4lb

/MM

Btu

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

hput

Thro

ughp

utU

nit

Pollu

tant

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

tEm

issi

onLi

mit

Avg

Tim

eCo

nditi

onCa

seBy

Case

Basi

sSt

anda

rdEm

issi

onLi

mit

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#1(NORM

ALOPERA

TION,N

ODU

CTBU

RNING)

NaturalGa

s15

4MW

Particulate

matter,total&

2.5μ(TPM

2.5)

PUCQUALITYNAT

URA

LGA

S12

LB/H

12MONTH

ROLLINGAV

G(NO

DUCT

BURN

ING)

BACT

PSD

015

4MW

Combine

dCycleCo

mbu

stionTurbine

Gene

rator

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#2(NORM

ALOPERA

TION,W

ITH

DUCT

BURN

ING)

NAT

URA

LGA

S15

4MW

Particulate

matter,total

(TPM

)PU

CQUALITYNAT

URA

LGA

S18

LB/H

12MONTH

ROLLINGAV

G(W

/DU

CTBU

RNING)

BACT

PSD

015

4MW

Combine

dCycleCo

mbu

stionTurbine

Gene

rator

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#2(NORM

ALOPERA

TION,W

ITH

DUCT

BURN

ING)

NAT

URA

LGA

S15

4MW

Particulate

matter,total&

2.5μ(TPM

2.5)

PUCQUALITYNAT

URA

LGA

S18

LB/H

12MONTH

ROLLINGAV

G(W

/DU

CTBU

RNING)

BACT

PSD

015

4MW

Combine

dCycleCo

mbu

stionTurbine

Gene

rator

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#1(NORM

ALOPERA

TION,W

ITH

DUCT

BURN

ING)

NAT

URA

LGA

S15

4MW

Particulate

matter,total

(TPM

)USE

PUCQUALITYNAT

URA

LGA

S18

LB/H

12MONTH

ROLLINGAV

G(W

/DU

CTBU

RNING)

BACT

PSD

015

4MW

Combine

dCycleCo

mbu

stionTurbine

Gene

rator

CA11

91

VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#1(NORM

ALOPERA

TION,W

ITH

DUCT

BURN

ING)

NAT

URA

LGA

S15

4MW

Particulate

matter,total&

2.5μ(TPM

2.5)

PUCQUALITYNAT

URA

LGA

S18

LB/H

12MONTH

ROLLINGAV

G(W

/DU

CTBU

RNING)

BACT

PSD

015

4MW

Combine

dCycleCo

mbu

stionTurbine

Gene

rator

NJ0

074

WESTDE

PTFO

RDEN

ERGY

LSPO

WER

5607

8BO

P080

001

5/6/20

09TU

RBINE,CO

MBINED

CYCLE

NAT

URA

LGA

S17

298MMFT3/YR

Particulate

matter,

filterable&10

μ(FPM

10)

CLEA

NFU

ELS

NAT

URA

LGA

SAN

DULTRA

LOW

SULFUR(15P

PMSU

LFUR)

DISTILLATE

OI L

18.66LB/H

Other

Case

byCase

0

NJ0

074

WESTDE

PTFO

RDEN

ERGY

LSPO

WER

5607

8BO

P080

001

5/6/20

09TU

RBINE,CO

MBINED

CYCLE

NAT

URA

LGA

S17

298MMFT3/YR

Particulate

matter,

filterable<

2.5μ(FPM

2.5)

USE

OFCLEA

NFU

ELS,NAT

URA

LGA

SAN

DULTRA

LOW

SULFURDISTILLATE

OIL

18.66LB/H

Other

Case

byCase

0

OK01

29CH

OUTEAU

POWER

PLAN

TAS

SOCIAT

EDELEC

TRIC

COOPERA

TIVE

INC

2007

115

C(M

1)PSD

1/23

/200

9

COMBINED

CYCLE

COGE

NER

ATION

>25M

WNAT

URA

LGA

S18

82MMBT

U/H

Particulate

matter,

filterable&10

μ(FPM

10)

NAT

URA

LGA

SFU

E L6.59

LB/H

3HAV

GN/A

0SIEM

ENSV8

4.3A

TX05

42PEAR

SALL

POWER

PLAN

T

SOUTH

TEXA

SELEC

TRIC

COOPERA

TIVE

INC.

8482

41/23

/200

9ELEC

TRICAL

GENER

ATION

NAT

URA

LGA

S8.44

MW

Particulate

Matter(PM

)

TCEQ

¿SCU

RREN

TBA

CTGU

IDELINES

PROVIDE

NOGU

IDAN

CEFO

RPM

EMISSIONSFO

RTH

ISTYPE

OFEN

GINE.

LOW

ASHFU

ELAN

DCO

MBU

STION

CONTR

OLSAR

EUSEDAS

THECO

NTR

OL

METHO

D.STECWILLUSE

GOOD

0SEENOTE

BACT

PSD

0TW

ENTY

FOURSPAR

KIGNITIONINTERN

ALCO

MBU

STIONEN

GINES

CA11

98MORR

OBA

YPO

WER

PLAN

TDY

NER

GYMORR

OBA

YLLC

SCC20

0501

9/25

/200

8CO

MBU

STIONTU

RBINE

GENER

ATOR

NAT

URA

LGA

S18

0MW

Particulate

matter,total

(TPM

)

USE

PIPELINEQUALITYNAT

URA

LGA

S,OPERA

TEDU

CTBU

RNER

SNOMORE

THAN

4000

HRSPERYEAR

(12MONTH

ROLLINGAV

GBA

SIS)

11LB/H

6HR

ROLLINGAV

G(NODU

CTBU

RNING)

BACT

PSD

04GE

Fram

e7,Mod

elPG

7241

,180

MW

gasfired

turbines, twoHR

SGsw

ithdu

ctbu

rners

CA11

98MORR

OBA

YPO

WER

PLAN

TDY

NER

GYMORR

OBA

YLLC

SCC20

0501

9/25

/200

8CO

MBU

STIONTU

RBINE

GENER

ATOR

NAT

URA

LGA

S18

0MW

Particulate

matter,

filterable&10

μ(FPM

10)

USE

PIPELINEQUALITYNAT

URA

LGA

S,OPERA

TEDU

CTBU

RNER

SNOMORE

THAN

4000

HRSPERYEAR

(12MONTH

ROLLINGAV

GBA

SIS)

11LB/H

6HR

ROLLINGAV

G(NODU

CTBU

RNING)

BACT

PSD

04GE

Fram

e7,Mod

elPG

7241

,180

MW

gasfired

turbines,twoHR

SGsw

ithdu

ctbu

rners

CA11

98MORR

OBA

YPO

WER

PLAN

TDY

NER

GYMORR

OBA

YLLC

SCC20

0501

9/25

/200

8CO

MBU

STIONTU

RBINE

GENER

ATOR

NAT

URA

LGA

S18

0MW

Particulate

matter,total

(TPM

)

USE

PIPELINEQUALITYNAT

URA

LGA

S,OPERA

TEDU

CTBU

RNER

SNOMORE

THAN

4000

HRSPERYEAR

(12MONTH

ROLLINGAV

GBA

SIS)

11LB/H

6HR

ROLLINGAV

G(NODU

CTBU

RNING)

BACT

PSD

04GE

Fram

e7,Mod

elPG

7241

,180

MW

gasfired

turbines, twoHR

SGsw

ithdu

ctbu

rners

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:Pa

rtic

ulat

es

Prop

osed

Part

icul

ate

Lim

it:11

.9lb

/hr=

0.00

4lb

/MM

Btu

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

hput

Thro

ughp

utU

nit

Pollu

tant

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

tEm

issi

onLi

mit

Avg

Tim

eCo

nditi

onCa

seBy

Case

Basi

sSt

anda

rdEm

issi

onLi

mit

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

CA11

98MORR

OBA

YPO

WER

PLAN

TDY

NER

GYMORR

OBA

YLLC

SCC20

0501

9/25

/200

8CO

MBU

STIONTU

RBINE

GENER

ATOR

NAT

URA

LGA

S18

0MW

Particulate

matter,

filterable&10

μ(FPM

10)

USE

PIPELINEQUALITYNAT

URA

LGA

S,OPERA

TEDU

CTBU

RNER

SNOMORE

THAN

4000

HRSPERYEAR

(12MONTH

ROLLINGAV

GBA

SIS)

11LB/H

6HR

ROLLINGAV

G(NODU

CTBU

RNING)

BACT

PSD

04GE

Fram

e7,Mod

elPG

7241

,180

MW

gasfired

turbines,twoHR

SGsw

ithdu

ctbu

rners

FL03

04CA

NEISLAND

POWER

PARK

FLORIDA

MUNICIPAL

POWER

AGEN

CY(FMPA

PSDFL

400

(097

0043

014

AC)

9/8/20

08

300MW

COMBINED

CYCLECO

MBU

STION

TURB

INE

NAT

URA

LGA

S18

60MMBT

U/H

Particulate

matter,

filterable&10

μ(FPM

10)

FUEL

SPEC

IFICAT

IONS:2

GRS/10

0SCF

OFGA

S2GR

S/10

0SCF

GAS

BACT

PSD

0

GASFU

ELED

GENER

ALELEC

TRIC

7241

FACT

,A

SUPP

LEMEN

TARY

FIRE

DHR

SGWITHNAT

URA

LGA

SFU

ELED

DUCT

BURN

ERS(DB)

FL03

03

FPLWESTCO

UNTY

ENER

GYCE

NTER

UNIT3

FLORIDA

POWER

AND

LIGH

TCO

MPA

NY

(FP&

L)

0990

64600

2AC

(PSD

FL39

6)7/30

/200

8

THRE

ENOMINAL

250

MW

CTG(EAC

H)WITH

SUPP

LEMEN

TARY

FIRE

DHR

SGNAT

URA

LGA

S23

33MMBT

U/H

Particulate

Matter(PM

)2GR

/100

SCF

GAS

BACT

PSD

03CO

MBU

STIONTU

RBINEELEC

TRICAL

GENER

ATORS

(CTG

)

LA01

36

PLAQ

UEM

INE

COGE

NER

ATION

FACILIT Y

THEDO

WCH

EMICAL

COMPA

NY

PSDLA

659(M2)

7/23

/200

8

(4)G

ASTU

RBINES/DUCT

BURN

ERS

NAT

URA

LGA

S28

76MMBT

U/H

Particulate

matter,

filterable&10

μ(FPM

10)

USE

OFCLEA

NBU

RNINGFU

ELS

33.5

LB/H

HOURLY

MAX

IMUM

BACT

PSD

04NAT

URA

LGA

SFIRE

DGE

FRAM

E7FA

GASTU

RBINES,

DUCT

BURN

ERSYSTEM

LA02

24AR

SENAL

HILL

POWER

PLAN

T

SOUTH

WEST

ELEC

TRIC

POWER

COMPA

NY(SWEPCO

)PSDLA

726

3/20

/200

8TW

OCO

MBINED

CYCLE

GASTU

RBINE S

NAT

URA

LGA

S21

10MMBT

U/H

Particulate

Matter(PM

)

GOODCO

MBU

STIONDE

SIGN

/PRO

PER

OPERA

TINGPR

ACTICE

S/PIPELINE

QUALITYNAT

URA

LGA

SAS

FUE L

24.23LB/H

MAX

BACT

PSD

0CTG1TU

RBINE/DU

CTBU

RNER

(EQT012

)CT

G2TU

RBINE/DU

CTBU

RNER

(EQT013

)

CT01

51KLEENEN

ERGY

SYSTEM

S,LLC

KLEENEN

ERGY

SYSTEM

S,LLC

10401

31AN

D10

401

332/25

/200

8

SIEM

ENSSG

T650

00F

COMBU

STIONTU

RBINE

#1AN

D#2

(NAT

URA

LGA

SFIRE

D)WITH44

5MMBT

U/HRNAT

URA

LGA

SDU

CTBU

RNE R

NAT

URA

LGA

S2.1MMCF/H

Particulate

matter,

filterable&10

μ(FPM

10)

11LB/H

W/O

UTDU

CTBU

RNER

BACT

PSD

02SIEM

ENSSG

T650

00FCO

MBU

STIONTU

RBINE,DU

CTBU

RNER

ANDAN

HRSG

.

MN00

71FA

IRBA

ULT

ENER

GYPA

RK

MINNESOTA

MUNICIPAL

POWER

AGEN

CY13

1000

7100

36/5/20

07

COMBINED

CYCLE

COMBU

STIONTU

RBINE

W/DUCT

BURN

ERNAT

URA

LGA

S17

58MMBT

U/H

Particulate

matter,

filterable<

10μ(FPM

10)

0.01

LB/M

MBT

UCT

GNGORCT

G&

DBNG

BACT

PSD

0.03

LB/M

MBT

U

CTGOIL&DB

NOT

OPERA

TEORDB

NG

OROIL

GE7FACO

MBU

STIONTU

RBINEGE

NER

ATORWITH

DUCT

BURN

ER.

CA11

44BLYTHE

ENER

GYPR

OJECT

IICA

ITHN

ESSBLYTHE

II,LLC

SE02

014/25

/200

72CO

MBU

STION

TURB

INES

NAT

URA

LGA

S17

0MW

Particulate

matter,

filterable<

10μ(FPM

10)

USE

PUBLICUTILITY

COMMISSION

QUALITYNAT

URA

LGA

SW/S

ULFUR

CONTENTLESS

THAN

OREQ

UAL

TO0.5GR

AINSPER10

0SCF

6LB/H

BACT

PSD

0

OK01

17

PSO

SOUTH

WESTERN

POWER

PLT

PUBLICSERV

ICECO

OFOKLAH

OMA

2003

403C

PSD

2/9/20

07GA

SFIRE

DTU

RBINE S

Particulate

matter,

filterable&10

μ(FPM

10)

USE

OFLO

WAS

HFU

EL(NAT

URA

LGA

S)AN

DEFFICIEN

TCO

MBU

STION

0.00

93LB/M

MBT

UBA

CTPSD

0

FL02

86FPLWESTCO

UNTY

ENER

GYCE

NTER

FLORIDA

POWER

AND

LIGH

TCO

MPA

NY

PSDFL

354

AND09

9064

600

1AC

1/10

/200

7

COMBINED

CYCLE

COMBU

STIONGA

STU

RBINES

6UNITS

NAT

URA

LGA

S23

33MMBT

U/H

Particulate

matter,

filterable&10

μ(FPM

10)

2GS

/100

SCF

GAS

BACT

PSD

06MODE

L50

1GGA

STU

RBINEELEC

TRICAL

GENER

ATORSETS,D

UCT

BURN

E R

OK01

15LAWTO

NEN

ERGY

COGE

NFA

CILITY

ENER

GETIX

2001

205CM

1PSD

12/12/20

06CO

MBU

STIONTU

RBINE

ANDDU

CTBU

RNER

Particulate

matter,

filterable&10

μ(FPM

10)

GOODCO

MBU

STIONPR

ACTICE

S0.00

67LB/M

MBT

UBA

CTPSD

0

TX04

97INEO

SCH

OCO

LATE

BAYO

UFA

CILIT Y

INEO

SUSA

LLC

PSDTX

983

AND46

192

8/29

/200

6

COGE

NER

ATIONTR

AIN

2AN

D3(TURB

INEAN

DDU

CTBU

RNER

EMISSIONS)

NAT

URA

LGA

S35

MW

Particulate

matter,

filterable&10

μ(FPM

10)

THEUSE

OFPR

OPERCO

MBU

STION

CONTR

OLAN

DFIRINGONLY

GASEOUS

FUELSCO

NTA

ININGNOAS

HISBA

CTFO

RPA

RTICULATE

MAT

TERFROM

THE

GASFIRE

DTU

RBINES

AND

DUCT

BURN

ERS.

10.03LB/H

BACT

PSD

02TU

RBINES

ANDTW

OHE

ATRE

COVE

RYSTEA

MGE

NER

ATORS,W

ITH3DU

CTBU

RNER

S .

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:Pa

rtic

ulat

es

Prop

osed

Part

icul

ate

Lim

it:11

.9lb

/hr=

0.00

4lb

/MM

Btu

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

hput

Thro

ughp

utU

nit

Pollu

tant

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

tEm

issi

onLi

mit

Avg

Tim

eCo

nditi

onCa

seBy

Case

Basi

sSt

anda

rdEm

issi

onLi

mit

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

TX05

02

NAC

OGD

OCH

ESPO

WER

STER

NE

GENER

ATING

FACILIT Y

NAC

OGD

OCH

ESPO

WER

LLC

PSDTX

1015

AND49

293

6/5/20

06

WESTINGH

OUSE/SIEME

NSMODE

LSW

501F

GASTU

RBINEW/4

16.5

MMBT

UDU

CTBU

RNER

SNAT

URA

LGA

S19

0MW

Particulate

matter,

filterable&10

μ(FPM

10)

STEA

GPO

WER

LLCRE

PRESEN

TSTH

EFIRINGOFPIPELINENAT

URA

LGA

SIN

THECO

MBU

STIONTU

RBINES

AND

DUCT

FIRE

DHR

SGSAS

BACT

FOR

PM10

.26

.9LB/H

BACT

PSD

0

3WESTINGH

OUSE/SIEMEN

SMODE

L50

1FCO

MBU

STIONTU

RBINES,THR

EEHE

ATRE

COVE

RYSTEA

MGE

NER

ATORS

(HRSGS

)WITH37

5MMBT

U/HR

DUCT

BURN

ERS

NY00

95

CAITHN

ESBE

LLPO

RTEN

ERGY

CENTER

CAITHN

ESSBE

LLPO

RT,

LLC

PSDNY00

015/10

/200

6CO

MBU

STIONTU

RBINE

NAT

URA

LGA

S22

21MMBU

T/H

Particulate

matter,

filterable&10

μ(FPM

10)

LOW

SULFURFU

E L0.00

55LB/M

MBT

UNODU

CTBU

RNING

BACT

PSD

0CO

MBINED

CYCLEWITHDU

CTFIRINGUPTO

494

MMBT

U/H

CO00

56

ROCK

YMOUNTA

INEN

ERGY

CENTER,

LLC

CALPINECO

RP.

05WE052

45/2/20

06

NAT

URA

LGA

SFIRE

D,CO

MBINED

CYCLE

TURB

INE

NAT

URA

LGA

S30

0MW

Particulate

matter,

filterable<

10μ(FPM

10)

NAT

URA

LGA

SQUALITYFU

ELONLY

ANDGO

ODCO

MBU

STIONCO

NTR

OL

PRAC

TICE

S.0.00

74LB/M

MBT

UBA

CTPSD

01CO

MBU

STIONTU

RBINE,GA

SFIRE

D,CO

MBINED

CYCLE.

TX05

16

CITY

PUBLIC

SERV

ICEJK

SPRU

CEELEC

TRICE

GENER

ATINGUNIT

2CITY

PUBLICSERV

ICE

PSDTX

1037

AND70

492

12/28/20

05SPRU

CEPO

WER

GENER

ATORUNITNO2

Particulate

Matter(PM

)26

4LB/H

BACT

PSD

0

NV00

35

TRAC

YSU

BSTA

TION

EXPA

NSION

PROJECT

SIER

RAPA

CIFIC

POWER

COMPA

NY

AP49

1115

048/16

/200

5

TURB

INE,CO

MBINED

CYCLECO

MBU

STION#2

WITHHR

SGAN

DDU

CTBU

RNER

.NAT

URA

LGA

S30

6MW

Particulate

matter,

filterable&10

μ(FPM

10)

BEST

COMBU

STIONPR

ACTICE

S.0.01

1LB/M

MBT

U3HO

URRO

LLING

BACT

PSD

02TU

RBINEGE

NER

ATORS

WITHHR

SG''S

ANDDU

CTBU

RNER

NV00

35

TRAC

YSU

BSTA

TION

EXPA

NSION

PROJECT

SIER

RAPA

CIFIC

POWER

COMPA

NY

AP49

1115

048/16

/200

5

TURB

INE,CO

MBINED

CYCLECO

MBU

STION#1

WITHHR

SGAN

DDU

CTBU

RNER

.NAT

URA

LGA

S30

6MW

Particulate

matter,

filterable&10

μ(FPM

10)

BEST

COMBU

STIONPR

ACTICE

S.0.01

1LB/M

MBT

U3HO

URRO

LLING

BACT

PSD

02TU

RBINEGE

NER

ATORS

WITHHR

SG''S

ANDDU

CTBU

RNER

OR00

41WAN

APAEN

ERGY

CENTER

DIAM

ONDWAN

APAI,

L.P.

R10P

SDOR

0501

8/8/20

05

COMBU

STIONTU

RBINE

&am

p;HE

ATRE

COVE

RYSTEA

MGE

NER

ATOR

NAT

URA

LGA

S23

84.1

MMBT

U/H

Particulate

Matter(PM

)0

SEEPO

LUTA

NT

NOTE

BACT

PSD

0GE

7241

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2006

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Particulate

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10)

USE

OFCLEA

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5

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INES

ANDDU

CTBU

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SNAT

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Particulate

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19LB/H

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AND

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338

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NAT

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Particulate

Matter(PM

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28

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NER

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BPWESTCO

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0201

1/11

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5

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ATRE

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MGE

NER

ATOR

NAT

URA

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ELTYPE

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BACT

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NOTES

3CT

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RGUNITS,DU

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Calp

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Man

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atin

gat

norm

altu

rbin

eba

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adco

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ons;

Equi

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9lb

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cilit

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Corp

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eor

Com

pany

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ePe

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Cont

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mit

Uni

tEm

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mit

Avg

Tim

eCo

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Case

Basi

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anda

rdEm

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mit

Stan

dard

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itU

nit

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dard

Lim

itAv

erag

eTi

me

Cond

ition

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tiona

lPer

mit

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itN

otes

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67LO

NC.HILL

POWER

STAT

ION

LONC.HILL,L.P.

1149

11AN

DPSDT

X138

010

/6/201

5Co

mbine

dCycle

Turbines

(>25

MW)

naturalgas

195MW

Oxidatio

nCatalyst

2PP

MRO

LLING24

HRAV

ERAG

EBA

CTPSD

Twopo

wer

configurationop

tions

authorize

dSiem

ens–

240MW

+25

0millionBritish

thermalun

itspe

rhou

r(M

MBtu/hr)d

uctb

urne

r GE–19

5MW

+67

0MMBtu/hr

ductbu

rner

*TX07

27CE

DARBA

YOUELEC

TRIC

GENER

ATINGSTAT

ION

NRG

TEXA

SPO

WER

LLC

8028

9&

PSDT

X108

2M1

3/31

/201

5Co

mbine

dcycle

turbines

NaturalGa

s18

7MW/turbine

Oxidatio

ncatalysts

15PP

MVD

15%O2

BACT

PSD

02naturalgas

fired

combu

stionturbines

*TX07

14SRBE

RTRO

NELEC

TRIC

GENER

ATINGSTAT

ION

NRG

TEXA

SPO

WER

LLC

1027

31PSDT

X129

412

/19/20

14(2)com

bine

dcycle

turbines

naturalgas

240MW

oxidationcatalyst

4PP

MVD

@15

%O2,ONE

HOUR

BACT

PSD

0

Thegasturbine

swillbe

oneof

threeop

tions:(1)

Two

Siem

ensM

odelF5

(SF5)C

TGsw

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ctfired

HRSG

,(2)

TwoGe

neralElectric

Mod

el7FA(GE7FA

)CTG

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eavy

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HRSG

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BLAC

KHILLSELEC

TRIC

GENER

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09PB

0591

12/11/20

14Four

combine

dcycle

combu

tionturbines

natural gas

373mmbtu/hr

each

Catalytic

Oxidatio

n.38

LB/HR

4HR

ROLLINGAV

E/

STAR

TUPAN

DSH

UTD

OWN

BACT

PSD

0

SU/SDLimit.

GE,LM60

00PF,naturalgasfire

d,combine

dcyclecombu

stionturbines,w

ithHR

SGandno

duct

burners.

*TX07

10VICT

ORIAPO

WER

STAT

ION

VICT

ORIAWLE

L.P.

1082

58PSDT

X134

812

/1/201

4combine


197MW

oxidationcatalyst

4PP

MVD

@15

%O2,3HR

ROLLINGAV

ERAG

EBA

CTPSD

0Ge

neralElectric

7FA.04

with

ductbu

rners.

*WV00

25

MOUNDS

VILLE

COMBINED

CYCLE

POWER

PLAN

TMOUNDS

VILLEPO

WER

,LLC

R1400

3011

/21/20

14Co

mbine

dCycle

Turbine/Du

ctBu

rner

NaturalGa

s21

59mmBtu/Hr

Oxidatio

nCatalyst+

Combu

stionCo

ntrols

9.2LB/HR

BACT

PSD

2PP

M@

15%O2

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7mW

Gene

ralElectric

Fram

e7FA.04

Turbinew/D

uctB

urne

r

*TX07

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INIDAD

GENER

ATING

FACILITY

SOUTH

ERNPO

WER

COMPA

NY

1113

93PSDT

X136

811

/20/20

14combine


497MW

oxidationcatalyst

4PP

MVD

@15

%O2,24

HRRO

LLINGAV

ERAG

EBA

CTPSD

0AMitsub

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eavy

Indu

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mod

elgasfire

dcombu

stionturbineeq

uipp

edwith

aHR

SGandDB

*TX06

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RISTI

LIQUEFAC

TIONPLAN

TCO

RPUSCH

RISTI

LIQUEFAC

TIONLLC

PSDT

X130

610

5710

9/12

/201

4Re

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snaturalgas

4000

0hp

drylowem

ission

combu

stors

29PP

MVD

@15

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UR

ROLLINGAV

ERAG

EBA

CTPSD

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2500

+DL

Eturbines

*TX06

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YOUELEC

TRIC

GENER

ATIONSTAT

ION

NRG

TEXA

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WER

1058

10,

PSDT

X130

88/29

/201

4Co

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0

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HeavyIndu

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RTLN

GDE

VELO

PMEN

TLP

1048

40N17

0PSDT

X130

27/16

/201

4Co

mbu

stionTurbine

naturalgas

87MW

oxidationcatalyst

4PP

MVD

@15

%O2,3HO

UR

ROLLINGAV

ERAG

EBA

CTPSD

0

*TX07

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KABR

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ILLE

GENER

ATINGSTAT

ION

TENAS

KABR

OWNSV

ILLE

PART

NER

S,LLC

1084

11PSDT

X135

04/29

/201

4(2)com

bine

dcycle

turbines

naturalgas

274MW

oxidationcatalyst

2PP

MVD

@15

%O2,24

HRRO

LLINGAV

ERAG

EBA

CTPSD

0

Usin

gcombine

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logy

and

fueled

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ality

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osed

perm

itauthorize

stwoCT

s(2x1CC

GT),althou

ghthefin

alde

signselected

byTenaskamay

onlyconsist

ofon

eCT

(1x1

CCGT

).Includ

esdu

ctbu

rners

*IA01

07MAR

SHALLTOWN

GENER

ATINGSTAT

ION

INTERSTA

TEPO

WER

AND

LIGH

T13

A49

9P

4/14

/201

4Co

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combine

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naturalgas

2258

mmBtu/hr

catalytic

oxidize

r2PP

M30

DAYRO

LLING

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@15

%O2

BACT

PSD

0

twoiden

ticalSiem

ensS

GT650

00Fcombine

dcycle

turbines

with

outd

uct firing,eachat

2258

mmBtu/hr

gene

ratin

gapprox.300

MW

each.

*IA01

07MAR

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GENER

ATINGSTAT

ION

INTERSTA

TEPO

WER

AND

LIGH

T13

A49

9P

4/14

/201

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stionturbine#2

combine

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naturalgas

2258

mmBtu/hr

COcatalyst

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M30

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LLING

AVER

AGE

BACT

PSD

0Tw

ocombine

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with

outd

uctb

urning.

*TX06

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ETEXA

SPO

WER

IAND

FGETEXA

SPO

WER

IIFG

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WER

LLC

PSDT

X136

43/24

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4Alstom

Turbine

NaturalGa

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0.7MW

Oxidatio

ncatalyst

2PP

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CORR

ECTEDTO

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LLING3HR

AVE

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0Four

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Calp

ine

Man

kato

Ener

gyCe

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RACT

/BAC

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ERCl

earin

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seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

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nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:C O

Prop

osed

COLi

mit:

4PP

MVD

@15

%O

2w

hile

oper

atin

gat

norm

altu

rbin

eba

selo

adco

nditi

ons;

Equi

vale

ntto

0.00

9lb

/MM

Btu

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cilit

yN

ame

Corp

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eor

Com

pany

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ePe

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Stan

dard

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itAv

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Cond

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mit

Lim

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LLC

2602

353/5/20

14

Mitsub

ishiM

501GA

Ccombu

stionturbine,

combine

dcycle

configurationwith

duct

burner.

naturalgs

2988

MMBtu/hr

Oxida

oncatalyst;

Limitthetim

einstartupor

shutdo

wn.

3.3PP

MDV

AT15

%O2

3HR

ROLLING

AVER

AGEONNG

BACT

PSD

0

3naturalgas

fired

turbines,one

ofwhich

willbe

acombine

dcycleun

itwith

ductbu

rner

andhe

atrecovery

steam

gene

rator.

*PA02

98

FUTU

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WER

PA/G

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NGC

CFA

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PAINC

5400

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14

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00)

NaturalGa

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MVD

@15

%OXYGE

NBA

CTPSD

84.8

TPY

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MONTH

ROLLING

TOTA

L

Combu

stionturbinegene

ratora

ndahe

atrecovery

steam

gene

ratorthatw

illprovidesteam

todriveasin

glesteam

turbinegene

rator.Each

heat

recovery

steam

gene

rator

willbe

equipp

edwith

adu

ctbu

rner

*PA02

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LLOW

ENER

GYAS

SOCLLC/ONTELAUNEE

BERK

SHO

LLOW

ENER

GYAS

SOCLLC

0605

150A

12/17/20

13Turbine,Co

mbine

dCycle,#1

and#2

NaturalGa

s30

46MMBtu/hr

COCatalyst

211.92

TPY

12MONTH

ROLLING

TOTA

LBA

CTPSD

02combu

stionturbinegene

ratorsand2he

atrecovery

steam

gene

ratorswith

ductbu

rners

*MI0

412

HOLLAN

DBO

ARDOF

PUBLICWORK

SEA

ST5THSTRE

ETHO

LLAN

DBO

ARDOF

PUBLICWORK

S10

713

12/4/201

3

FGCT

GHRSG:

2Co

mbine

dcycleCT

Gswith

HRSG

swith

duct

burners

naturalgas

647MMBT

U/H

fore

ach

CTGH

RSG

Oxidatio

ncatalyst

techno

logy

andgood

combu

stionpractices.

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M

24HRO

LL.A

VG.,

NOT

STAR

TUP/SH

UTD

OW

NBA

CTPSD

0

2combine

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gene

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s)with

Heat

Recovery

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Gene

rators

(HRSGs

)equ

ippe

dwith

ductbu

rnersfor

supp

lemen

tal

firing.

*MI0

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HOLLAN

DBO

ARDOF

PUBLICWORK

SEA

ST5THSTRE

ETHO

LLAN

DBO

ARDOF

PUBLICWORK

S10

713

12/4/201

3FG

CTGH

RSG:

Startup

&am

p;Shutdo

wn

naturalgas

647MMBT

U/H

fore

ach

CTGH

RSG

Oxidatio

ncatalyst

techno

logy

andgood

combu

stionpractices.

247.3LB/H

OPERA

TINGHO

UR

DURINGSTAR

TUP

BACT

PSD

0

Thisprocessiside

ntified

sepe

ratelyforthe

startupand

shutdo

wnpe

riods

associated

with

theprocess

equipm

entinclude

dinFG

CTGH

RSG.

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REST

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X129

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ROLL

AVG,

15%

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N,8010

0%LO

ADBA

CTPSD

0

2naturalgas

fired

combu

stionturbines

(CTs),each

exhaustin

gto

afired

heat

recovery

steam

gene

rator

(HRSG)

toprod

ucesteam

todriveashared

steam

turbine

gene

rator.Threemod

elso

fcom

bustionturbines

are

beingconsidered

:Gen

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,the

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ens

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ENER

GYCE

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4810

6,PSDT

X101

2M2

9/13

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3

Naturalgasfired

combine

dcycle

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s17

3.9MW

OC

2PP

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RAV

G.BA

CTPSD

0GE

7FANaturalGa

sfired

Combine

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DBfired

HRSG

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STRIES

U.S.,L.P.

9346

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9/5/20

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eration

turbines

naturalgas

90MW

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Controls(CLEC)

15PP

MVD

@15

%O2

BACT

PSD

0(4)G

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providingpo

wer

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*MI0

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THETFO

RDGE

NER

ATING

STAT

ION

CONSU

MER

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ERGY

COMPA

NY

19112

7/25

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FGCC

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FGCC

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DBforH

RSG

naturalgas

2587

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heat

inpu

t,each

CTG

Efficient

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LLAV

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CHHTU

RBINE

OPERA

TBA

CTPSD

0Naturalgasfire

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RSG;

4total.

*MI0

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THETFO

RDGE

NER

ATING

STAT

ION

CONSU

MER

SEN

ERGY

COMPA

NY

19112

7/25

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3

FGCC

Aor

FGCC

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gasfire

dCT

Gwith

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RSG:

Startup/shutdo

wn

even

tsnaturalgas

2587

MMBT

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desig

nhe

atinpu

t,each

Efficient

combu

stion

controlplusc

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LLTIME

PERIOD

STAR

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UTD

OW

NBA

CTPSD

0

Four

(4)n

aturalgasfire

dcombine

dcyclecombu

stion

turbinegene

rators(CTG

)and

heat

recovery

steam

gene

rators(HRSG)

with

ductbu

rner

firingcapability;

ancillary

facilityeq

uipm

ent.

*OH03

52ORE

GONCLEA

NEN

ERGY

CENTER

ARCA

DIS,US,INC.

P011

0840

6/18

/201

3

2Co

mbine

dCycle

Combu

stionTurbines

Mitsub

ishi,with

duct

burners

NaturalGa

s47

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12MO

oxidationcatalyst

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BACT

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MPP

MVD

AT15

%O2

TwoMitsub

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2MMBtu/Hcombine

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stionturbines

,bothwith

ductbu

rners.

Will

installeith

er2Siem

enso

r2Mitsub

ishi,no

t both(not

determ

ined

).

*OH03

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GONCLEA

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ERGY

CENTER

ARCA

DIS,US,INC.

P011

0840

6/18

/201

3

2Co

mbine

dCycle

Combu

stionTurbines

Siem

ens,with

outd

uct

burners

NaturalGa

s51

5600

MMSCF/rolling

12mon

ths

oxidationcatalyst

13LB/H

BACT

PSD

2PP

MPP

MVD

AT15

%O2

TwoMitsub

ishi293

2MMBtu/Hcombine

dcycle

combu

stionturbines

,bothwith

ductbu

rners.

Will

installeith

er2Siem

enso

r2Mitsub

ishi,no

tboth(not

determ

ined

).

*OH03

52ORE

GONCLEA

NEN

ERGY

CENTER

ARCA

DIS,US,INC.

P011

0840

6/18

/201

3

2Co

mbine

dCycle

Combu

stionTurbines

Siem

ens,with

duct

burners

NaturalGa

s51

560MMSCF/rolling

12MO

oxidationcatalyst

13LB/H

BACT

PSD

2PP

MPP

MVD

AT15

%O2

TwoMitsub

ishi293

2MMBtu/Hcombine

dcycle

combu

stionturbines

,bothwith

ductbu

rners.

Will

installeith

er2Siem

enso

r2Mitsub

ishi,no

tboth(not

determ

ined

).

*OH03

52ORE

GONCLEA

NEN

ERGY

CENTER

ARCA

DIS,US,INC.

P011

0840

6/18

/201

3

2Co

mbine

dCycle

Combu

stionTurbines

Mitsub

ishi,with

out

ductbu

rners

NaturalGa

s47

917MMSCF/rolling

12MO

oxidationcatalyst

13.7

LB/H

BACT

PSD

2PP

MPP

MVD

AT15

%O2

TwoMitsub

ishi293

2MMBtu/Hcombine

dcycle

combu

stionturbines

,bothwith

ductbu

rners.

Will

installeith

er2Siem

enso

r2Mitsub

ishi,no

tboth(not

determ

ined

).

*VA03

22

GREENEN

ERGY

PART

NER

S/STONEW

ALL,

LLC

GREENEN

ERGY

PART

NER

S/STONEW

ALL,

LLC

7382

600

14/30

/201

3

Largecombu

stion

turbines

CCT1

and

CCT2

NaturalGa

s2.23

MMBT

U/hr

Catalytic

Oxidizer

0BA

CTPSD

0

Thetw

ocombu

stionturbineconfigurationop

tions

curren

tlybe

ingconsidered

aretheGe

neralElectric

GE7FA.05

andSiem

ensS

GT650

00F5

units.Tthe

prop

osed

CTgene

ratorswilleither

beGe

neralElectric

GE7FA.05

orSiem

ensS

GT650

00F5

units.W

illinclud

edu

ctbu

rners

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:C O

Prop

osed

COLi

mit:

4PP

MVD

@15

%O

2w

hile

oper

atin

gat

norm

altu

rbin

eba

selo

adco

nditi

ons;

Equi

vale

ntto

0.00

9lb

/MM

Btu

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

hput

Thro

ughp

utU

nit

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

tEm

issi

onLi

mit

Avg

Tim

eCo

nditi

onCa

seBy

Case

Basi

sSt

anda

rdEm

issi

onLi

mit

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

*MI0

405

MIDLAND

COGE

NER

ATION

VENTU

RE

MIDLAND

COGE

NER

ATION

VENTU

RE10

312

4/23

/201

3

Naturalgasfue

led

combine

dcycle

combu

stionturbine

gene

rators(CTG

)with

HRSG

Naturalgas

2237

MMBT

U/H

Good

combu

stionpractices

9PP

MEA

CHCT

G;24

HRO

LLINGAV

G.BA

CTPSD

0

2naturalgas

fired

CTGs

with

each

turbinecontaining

ahe

atrecovery

steam

gene

rator(HR

SG).Thetw

oCT

Gs(w

ithHR

SG)are

conn

ectedto

onesteam

turbine

gene

rator.

Each

CTGiseq

uppe

dwith

adrylowNOx

(DLN

)burne

r

*MI0

405

MIDLAND

COGE

NER

ATION

VENTU

RE

MIDLAND

COGE

NER

ATION

VENTU

RE10

312

4/23

/201

3

Naturalgasfue

led

combine

dcycle

combu

stionturbine

gene

rators(CTG

)with

HRSG

anddu

ctbu

rner

(DB)

Naturalgas

2486

MMBT

U/H

Good

combu

stionpractices

10.5

PPM

EACH

CTG/

DB;24H

ROLLINGAV

G.BA

CTPSD

0

2naturalgas

fired

CTGs

with

each

turbinecontaining

ahe

atrecovery

steam

gene

rator(HR

SG)toop

eratein

combine

dcycle.

Thetw

oCT

Gs(w

ithHR

SG)are

conn

ectedto

onesteam

turbinegene

rator.HR

SGis

operatingwith

anaturalgas

fired

ductbu

rner

*MI0

405

MIDLAND

COGE

NER

ATION

VENTU

RE

MIDLAND

COGE

NER

ATION

VENTU

RE10

312

4/23

/201

3

Naturalgasfue

led

combine

dcycle

combu

stionturbine

gene

rators(CTG

)with

HRSG

Startup/Shutdo

wn

Naturalgas

2237

MMBT

U/H

each

Good

combu

stionpractices

3123

LB/H

HOURLYDU

RING

STAR

TUP

BACT

PSD

0

SU/SDLimitforT

wo(2)n

aturalgasfire

dCT

Gswith

each

turbinecontaining

ahe

atrecovery

steam

gene

rator

(HRSG)

toop

erateincombine

dcycle.

Thetw

oCT

Gs(w

ithHR

SG)are

conn

ectedto

onesteam

turbine

gene

rator.

*PA02

91HICK

ORY

RUNEN

ERGY

STAT

ION

HICK

ORY

RUNEN

ERGY

LLC

3733

7A4/23

/201

3CO

MBINED

CYCLE

UNITS#1

and#2

NaturalGa

s3.4MMCF/HR

COcatalyst

2PP

MVD

@15

%OXYGE

NWITHORWITHO

UT

DUCT

BURN

EROTH

ERCA

SEBY

CASE

0

2combu

stionturbinegene

ratorsand2he

atrecovery

steam

gene

ratorsthat

willprovidesteam

todriveasin

gle

steam

turbinegene

rator.Each

heat

recovery

steam

gene

ratorw

illbe

equipp

edwith

adu

ctbu

rner.M

odels

considered

:Gen

eralElectric7FA(GE7FA,

Siem

ensS

GT6

5000

F(Siemen

sF),Mitsub

ishiM

501G

(Mitsub

ishiG

,Siem

ensS

GT680

00H(Siemen

sH)

*VA03

21BR

UNSW

ICKCO

UNTY

POWER

STAT

ION

VIRG

INIA

ELEC

TRIC

AND

POWER

COMPA

NY

5240

400

13/12

/201

3CO

MBU

STIONTU

RBINE

GENER

ATORS,(3)

NaturalGa

s34

42MMBT

U/H

Oxidatio

ncatalyst;goo

dcombu

stionpractices.

1.5PP

MVD

3HAV

G/WITHO

UT

DUCT

BURN

ING

BACT

PSD

0Three(3)M

itsub

ishiM

501GA

Ccombu

stionturbine

gene

ratorswith

HRSG

ductbu

rners(naturalgas

fired

).

*TX07

08LA

PALO

MAEN

ERGY

CENTER

LAPA

LOMAEN

ERGY

CENTER,

LLC

1015

42PSDT

X128

82/7/20

13(2)com

bine

dcycle

turbines

naturalgas

650MW

oxidationcatalyst

2PP

MVD

@15

%O2,3HR

ROLLING,

8010

0%LO

ADBA

CTPSD

0

2combu

stionturbines

(CTs)con

nected

toelectric

gene

ratorswith

ductbu

rnersT

heapplicantisc

onsid

ering

threemod

elso

fCT:

(1)G


;(2)

Siem

ensS

GT650

00F(4);o

r(3)

Siem

ensS

GT650

00F(5).

*PA02

86

MOXIEEN

ERGY

LLC/PA

TRIOT

GENER

ATIONPLT

MOXIEEN

ERGY

LLC

4100

084A

1/31

/201

3Co

mbine

dCyclePo

wer

Blocks

472MW

(2)

NaturalGa

s0

COCatalyst

2PP

MDV

BACT

PSD

0

Twonaturalgas

fired

combine

dcyclepo

werblocks

whe

reeach

powerblockconsistso

facombu

stionturbine

andhe

atrecovery

steam

gene

ratorw

ithdu

ctbu

rner.

*OH03

56DU

KEEN

ERGY

HANGING

ROCK

ENER

GYDU

KEEN

ERGY

HANGING

ROCK

,LLC

P011

0487

12/18/20

12Turbines

(4)(mod

elGE

7FA)

DuctBu

rnersO

ffNAT

URA

LGA

S17

2MW

Good

combu

stionpractices

burningnaturalgas

25.7

LB/H

BACT

PSD

6PP

M

PPMVD

AT15

%O2

ON24

HBLOCK

AVER

AGE

Four

GE7FAcombine

dcycleturbines

with

thedu

ctbu

rners

*OH03

56DU

KEEN

ERGY

HANGING

ROCK

ENER

GYDU

KEEN

ERGY

HANGING

ROCK

,LLC

P011

0487

12/18/20

12Turbines

(4)(mod

elGE

7FA)

DuctBu

rnersO

nNAT

URA

LGA

S17

2MW

Good

combu

stionpractices

burningnaturalgas

45.9

LB/H

BACT

PSD

8PP

M

PPMVD

AT15

%O2

ON24

HBLOCK

AVER

AGE

Four

GE7FAcombine

dcycleturbines

with

thedu

ctbu

rners

*IN01

58ST.JOSEPH

ENEG

RYCE

NTER,

LLC

ST.JOSEPH

ENER

GYCE

NTER,

LLC

14131

00300

579

12/3/201

2

FOUR(4)N

ATURA

LGA

SCO

MBINED

CYCLE

COMBU

STION

TURB

INES

NAT

URA

LGA

S23

00MMBT

U/H

OXIDA

TIONCA

TALYST

2PP

MVD

3HO

URS

BACT

PSD

0

EACH

TURB

INEISEQ

UIPED

WITHNAT

URA

LGA

SFIRE

DDU

CTBU

RNER

S,AN

DAHE

ATRE

COVE

RYSTEA

MGE

NER

ATORIDEN

TIFIED

ASHR

SG#.

*IN01

58ST.JOSEPH

ENEG

RYCE

NTER,

LLC

ST.JOSEPH

ENER

GYCE

NTER,

LLC

14131

00300

579

12/3/201

2

FOUR(4)N

ATURA

LGA

SCO

MBINED

CYCLE

COMBU

STION

TURB

INES

STAR

TUP/SH

UTD

OWN

CYCLENAT

URA

LGA

S23

00MMBT

U/H

2125

LB*EVE

NT

BACT

PSD

0SU

/SDlim

iton

ly.

*DE00

23NRG

ENER

GYCE

NTER

DOVE

RNRG

ENER

GYCE

NTER

DOVE

RLLC

AQM

001/00

127(R

2)(REV

1)10

/31/20

12UNIT2

KD1

NaturalGa

s65

5MMBT

U/H

Oxidatio

nCatalystSystem

19.54LB/H

1HO

URAV

ERAG

EOTH

ERCA

SEBY

CASE

050

0MMBT

U/hrG

asTurbine(M

odel:G

ELM

6000

)

TX06

18CH

ANNEL

ENER

GYCE

NTERLLC

CHAN

NEL

ENER

GYCE

NTERLLC

PSDT

X955

M1

10/15/20

12Co

mbine

dCycle

Turbine

naturalgas

180MW

Good

combu

stion

4PP

MVD

@15

%O2ONA24

HRRO

LLINGAV

GBA

CTPSD

0TheturbineisaSiem

ens5

01Fratedat

ano

minal18

0megaw

attswith

DB

PA02

78

MOXIELIBE

RTY

LLC/AS

YLUM

POWER

PLT

MOXIEEN

ERGY

LLC

0800

045A

10/10/20

12

Combine

dcycle

Turbines

(2)

Natural

gasfire

dNaturalGa

s32

77MMBT

U/H

Oxidatio

nCatalyst

2PP

MVD

@15

%O2

BACT

PSD

2PP

MVD

@15

%O2

Twocombine


acombu

stion

turbineandhe

atrecovery

steam

gene

ratorw

ithdu

ctbu

rner.

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:C O

Prop

osed

COLi

mit:

4PP

MVD

@15

%O

2w

hile

oper

atin

gat

norm

altu

rbin

eba

selo

adco

nditi

ons;

Equi

vale

ntto

0.00

9lb

/MM

Btu

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

hput

Thro

ughp

utU

nit

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

tEm

issi

onLi

mit

Avg

Tim

eCo

nditi

onCa

seBy

Case

Basi

sSt

anda

rdEm

issi

onLi

mit

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

TX06

19DE

ERPA

RKEN

ERGY

CENTER

DEER

PARK

ENER

GYCE

NTERLLC

PSDT

X979

M2

9/26

/201

2Co

mbine

dCycle

Turbine

naturalgas

180MW

good

combu

stion

4PP

MVD

@15

%O2,24

HRRO

LLINGAV

GBA

CTPSD

0TheturbineisaSiem

ens5

01Fratedat

ano

minal18

0megaw

attswith

DB

TX06

20ES

JOSLIN

POWER

PLAN

TCA

LHOUNPO

RTAU

THORITY

PSDT

X125

69/12

/201

2Co

mbine

dcyclegas

turbine

naturalgas

195MW

good

combu

stion

4PP

MVD

@15

%O2,24

HRRO

LLINGAV

GBA

CTPSD

0Thethreecombu

stionturbinegene

rators(CTG

)willbe

theGe

neralElectric

7FA.

Nodu

ctbu

rners.

*WY00

70CH

EYEN

NEPR

AIRIE

GENER

ATINGSTAT

ION

BLAC

KHILLSPO

WER

,INC.

CT12

636

8/28

/201

2Co

mbine

dCycle

Turbine(EP0

1)NaturalGa

s40

MW

Oxidatio

nCatalyst

4PP

MVAT

15%

O2

1HO

UR

BACT

PSD

32TO

NSPER

YEAR

*WY00

70CH

EYEN

NEPR

AIRIE

GENER

ATINGSTAT

ION

BLAC

KHILLSPO

WER

,INC.

CT12

636

8/28

/201

2Co

mbine

dCycle

Turbine(EP0

2)NaturalGa

s40

MW

Oxidatio

nCatalyst

4PP

MVAT

15%

O2

1HO

UR

BACT

PSD

32TO

NSPER

YEAR

LA02

57SA

BINEPA

SSLN

GTERM

INAL

SABINEPA

SSLN

G,LP

&SA

BINEPA

SSLIQUEFAC

TION,LL

PSDLA

703(M3)

12/6/201

1

Combine

dCycle

Refrigeration

CompressorT

urbine

s(8)

naturalgas

286MMBT

U/H

Good

combu

stionpractices

andfueled

bynaturalgas

43.6

LB/H

HOURLYMAX

IMUM

BACT

PSD

58.4

PPMV

AT15

%O2

*MI0

402

SUMPTER

POWER

PLAN

T

WOLVER

INEPO

WER

SUPP

LYCO

OPERA

TIVE

INC.

8111

11/17/20

11

Combine

dcycle

combu

stionturbinew/

HRSG

Naturalgas

130MW

electricalou

tput

0.04

8LB/M

MBT

U24

HRRO

LLING

AVER

AGE

OTH

ERCA

SEBY

CASE

0Thisisacombine

dcyclecombu

stionturbinewith

ano

nredhe

atrecovery

steam

gene

rator(HR

SG).

CA12

12PA

LMDA

LEHY

BRID

POWER

PROJECT

CITY

OFPA

LMDA

LESE

0901

10/18/20

11

COMBU

STION

TURB

INES

(NORM

ALOPERA

TION)

NAT

URA

LGA

S15

4MW

OXIDA

TIONCA

TALYST

SYSTEM

1.5PP

MVD

@15

%O2,1HR

AVG

(NODU

CTBU

RNING)

BACT

PSD

0

2NAT

URA

LGA

SFIRE

DCO

MBU

STIONTU

RBINE

GENER

ATORS

(CTG

S),TWOHE

ATRE

COVE

RYSTEA

MGE

NER

ATORS

(HRSG),O

NESTEA

MTU

RBINEGE

NER

ATOR

(STG

)

CA12

12PA

LMDA

LEHY

BRID

POWER

PROJECT

CITY

OFPA

LMDA

LESE

0901

10/18/20

11

COMBU

STION

TURB

INES

(SHU

TDOWN

PERIODS

)NAT

URA

LGA

S11

0MMBT

U/H

OXIDA

TIONCA

TALYST

SYSTEM

337LB/EVE

NT

SHUTD

OWNPERIODS

BACT

PSD

0

SU/SDLimiton

ly.2NAT

URA

LGA

SFIRE

DCO

MBU

STION

TURB

INEGE

NER

ATORS

(CTG

S),TWOHE

ATRE

COVE

RYSTEA

MGE

NER

ATORS

(HRSG),O

NESTEA

MTU

RBINE

GENER

ATOR(STG

)

CA12

12PA

LMDA

LEHY

BRID

POWER

PROJECT

CITY

OFPA

LMDA

LESE

0901

10/18/20

11

COMBU

STION

TURB

INES

(STA

RTUP

PERIODS

)NAT

URA

LGA

S15

4MW

CATA

LYST

OXIDA

TION

SYSTEM

410LB/EVE

NT

COLD

STAR

TUP

PERIODS

BACT

PSD

0

SU/SDlim

iton

ly.2

NAT

URA

LGA

SFIRE

DCO

MBU

STION

TURB

INEGE

NER

ATORS

(CTG

S),TWOHE

ATRE

COVE

RYSTEA

MGE

NER

ATORS

(HRSG),O

NESTEA

MTU

RBINE

GENER

ATOR(STG

)

TX06

00TH

OMAS

C.FERG

USO

NPO

WER

PLAN

TLO

WER

COLO

RADO

RIVE

RAU

THORITY

PSDT

X124

49/1/20

11Naturalgasfired

turbines

naturalgas

390MW

Good

combu

stionpractices

andoxidationcatalyst

4PP

MVD

ROLLING3HR

AT15

%OXYGE

N/LOAD

>=60

%BA

CTPSD

0

(2)G

E7FA

at195MW

each,

(1)steam

turbineat

200MW.

Each

turbineiseq

uipp

edwith

anun

fired

heat

recovery

steam

gene

rator(HR

SG),which

provides

steam

forthe

steam

turbine.

LA02

54

NINEM

ILEPO

INT

ELEC

TRIC

GENER

ATING

PLAN

TEN

TERG

YLO

UISIANALLC

PSDLA

752

8/16

/201

1

COMBINED

CYCLE

TURB

INEGE

NER

ATORS

(UNITS6A

&am

p;6B

)NAT

URA

LGA

S71

46MMBT

U/H

OXIDA

TIONCA

TALYST

AND

GOODCO

MBU

STION

PRAC

TICE

S3PP

MVD

@15

%O2

HOURLYAV

ERAG

EBA

CTPSD

3PP

MVD

@15

%O2

HOURLYAV

ERAG

ECO

MBINED

CYCLETU

RBINEGE

NER

ATORS

CA11

92AV

ENAL

ENER

GYPR

OJECT

AVEN

ALPO

WER

CENTER

LLC

SJ08

016/21

/201

1

COMBU

STIONTU

RBINE

#1(NORM

ALOPERA

TION,N

ODU

CTBU

RNING)

NAT

URA

LGA

S18

0MW

OXIDA

TIONCA

TALYST

SYSTEM

1.5PP

MVD

@15

%O2,1HR

AVG

BACT

PSD

0

CA11

92AV

ENAL

ENER

GYPR

OJECT

AVEN

ALPO

WER

CENTER

LLC

SJ08

016/21

/201

1

COMBU

STIONTU

RBINE

#2(NORM

ALOPERA

TION, N

ODU

CTBU

RNING)

NAT

URA

LGA

S18

0MW

OXIDA

TIONCA

TALYST

SYSTEM

1.5PP

MVD

@15

%O2,1HR

AVG

BACT

PSD

0

CA11

92AV

ENAL

ENER

GYPR

OJECT

AVEN

ALPO

WER

CENTER

LLC

SJ08

016/21

/201

1

COMBU

STIONTU

RBINE

#1(NORM

ALOPERA

TION,W

ITH

DUCT

BURN

ING)

NAT

URA

LGA

S18

0MW

OXIDA

TIONCA

TALYST

SYSTEM

2PP

MVD

@15

%O2,1HR

AVG

BACT

PSD

0

CA11

92AV

ENAL

ENER

GYPR

OJECT

AVEN

ALPO

WER

CENTER

LLC

SJ08

016/21

/201

1

COMBU

STIONTU

RBINE

#2(NORM

ALOPERA

TION,W

ITH

DUCT

BURN

ING)

NAT

URA

LGA

S18

0MW

OXIDA

TIONCA

TALYST

SYSTEM

2PP

MVD

@15

%O2,1HR

AVG

(W/D

UCT

FIRING)

BACT

PSD

0

CA11

92AV

ENAL

ENER

GYPR

OJECT

AVEN

ALPO

WER

CENTER

LLC

SJ08

016/21

/201

1

COMBU

STIONTU

RBINE

#1(STA

RTUP&am

p;SH

UTD

OWNPERIODS

)NAT

URA

LGA

S18

0MW

OXIDA

TIONCA

TALYST

SYSTEM

1000

LB/H

EACH

TURB

INE&

HRSG

BACT

PSD

0SU

/SDLimiton

ly.

CA11

92AV

ENAL

ENER

GYPR

OJECT

AVEN

ALPO

WER

CENTER

LLC

SJ08

016/21

/201

1

COMBU

STIONTU

RBINE

#2(STA

RTUP&am

p;SH

UTD

OWNPERIODS

)NAT

URA

LGA

S18

0MW

OXIDA

TIONCA

TALYST

SYSTEM

1000

LB/H

EACH

TURB

INE&

HRSG

BACT

PSD

0SU

/SDLimiton

ly.

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:C O

Prop

osed

COLi

mit:

4PP

MVD

@15

%O

2w

hile

oper

atin

gat

norm

altu

rbin

eba

selo

adco

nditi

ons;

Equi

vale

ntto

0.00

9lb

/MM

Btu

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

hput

Thro

ughp

utU

nit

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

tEm

issi

onLi

mit

Avg

Tim

eCo

nditi

onCa

seBy

Case

Basi

sSt

anda

rdEm

issi

onLi

mit

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

CA12

11CO

LUSA

GENER

ATING

STAT

ION

PACIFICGA

S&ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(NORM

ALOPERA

TION)

NAT

URA

LGA

S17

2MW

CATA

LYTICOXIDA

TION

SYSTEM

3PP

MVD

@15

%O2,3HR

ROLLINGAV

GBA

CTPSD

0

TWO(2)N

ATURA

LGA

SFIRE

DTU

RBINES

AT17

2MW

EACH

.BOTH

TURB

INES

EQUIPPEDWITHA68

8MMBT

U/HRDU

CTBU

RNER

ANDHR

SG.

CA12

11CO

LUSA

GENER

ATING

STAT

ION

PACIFICGA

S&ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(HOT

STAR

TUPPERIODS

)NAT

URA

LGA

S17

2MW

CATA

LYTICOXIDA

TION

SYSTEM

370.3LB/H

HOTSTAR

TUP

PERIODS

BACT

PSD

0

HotS

tartup

limiton

ly.TW

O(2)N

ATURA

LGA

SFIRE

DTU

RBINES

AT17

2MW

EACH

.BOTH

TURB

INES

EQUIPPED

WITHA68

8MMBT

U/HRDU

CTBU

RNER

ANDHR

SG.

CA12

11CO

LUSA

GENER

ATING

STAT

ION

PACIFICGA

S&ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(WAR

MSTAR

TUPPERIODS

)NAT

URA

LGA

S17

2MW

CATA

LYTICOXIDA

TION

SYSTEM

373.6LB/H

WAR

MSTAR

TUP

PERIODS

BACT

PSD

0

Warm

Startuplim

iton

ly.TW

O(2)N

ATURA

LGA

SFIRE

DTU

RBINES

AT17

2MW

EACH

.BOTH

TURB

INES

EQUIPPED

WITHA68

8MMBT

U/HRDU

CTBU

RNER

ANDHR

SG.

CA12

11CO

LUSA

GENER

ATING

STAT

ION

PACIFICGA

S&ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(COLD

STAR

TUPPERIODS

)NAT

URA

LGA

S17

2MW

CATA

LYTICOXIDA

TION

SYSTEM

429.6LB/H

COLD

STAR

TUP

PERIODS

BACT

PSD

0

ColdStartuplim

iton

ly.TW

O(2)N

ATURA

LGA

SFIRE

DTU

RBINES

AT17

2MW

EACH

.BOTH

TURB

INES

EQUIPPED

WITHA68

8MMBT

U/HRDU

CTBU

RNER

ANDHR

SG.

CA12

11CO

LUSA

GENER

ATING

STAT

ION

PACIFICGA

S&ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(SHU

TDOWN

PERIODS

)NAT

URA

LGA

S17

2MW

CATA

LYTICOXIDA

TION

SYSTEM

483.5LB/H

TURB

INESH

UTD

OWN

PERIODS

BACT

PSD

0

Shutdo

wnlim

iton

ly.TW

O(2)N

ATURA

LGA

SFIRE

DTU

RBINES

AT17

2MW

EACH

.BOTH

TURB

INES

EQUIPPED

WITHA68

8MMBT

U/HRDU

CTBU

RNER

ANDHR

SG.

*IL01

12NELSO

NEN

ERGY

CENTER

INVE

NER

GYNELSO

N,LLC

9808

0039

12/28/20

10ElectricGe

neratio

nFacility

NaturalGa

s22

0MW

each

5PP

MVD

@15

%O2

HOURLYAV

GEXCE

PTDU

RINGSSM

OR

TUNING

BACT

PSD

0

Does

notinclude

SU/SDem

issions.Tw

onaturalgas

fired

combine

dcyclepo

werblocks

whe

reeach

powerblock

consistso

facombu

stionturbineandhe

atrecovery

steam

gene

ratorw

ithdu

ctbu

rner.

VA03

15

WAR

RENCO

UNTY

POWER

PLAN

TDO

MINION

VIRG

INIA

ELEC

TRIC

AND

POWER

COMPA

NY

8139

100

712

/17/20

10

COMBINED

CYCLE

TURB

INE&am

p;DU

CTBU

RNER

,3NaturalGa

s29

96MMBT

U/H

Oxidatio

ncatalystand

good

combu

stion

practices.

1.5PP

MVD

ONEHR

AVER

AGE

(W/O

DUCT

BURN

ERFIRING)

BACT

PSD

0

Does

notinclude

DBfiring.

Emissions

areforo

neof

threeun

its(M

itsub

ishinaturalgasfired

combu

stion

turbine(CT)

gene

rator,M

odelM50

1GA

C).W

ithdu

ctbu

rner

TX05

90KINGPO

WER

STAT

ION

PONDE

RACA

PITA

LMAN

AGEM

ENTGP

INC

PSDT

X112

58/5/20

10Turbine

naturalgas

1350

MW

good

combu

stionpractices

with

anoxidationcatalyst

2PP

MVD

AT15

%O2

THRE

EHO

UR

ROLLING

BACT

PSD

0

*CO00

73PU

EBLO

AIRP

ORT

GENER

ATINGSTAT

ION

BLAC

KHILLSELEC

TRIC

GENER

ATION,LLC

09PB

0591

7/22

/201

0Four

combine

dcycle

combu

tionturbines

naturalgas

373mmbtu/hr

Good

combu

stioncontrol

andcatalytic

oxidation

4PP

MVD

AT15

%O2

1HR

AVE

BACT

PSD

0ThreeGE

,LMS600

0PF,naturalgasfired

,com

bine

dcycle

CTG,

(1)H

RSGeach

with

noDu

ctBu

rners

ID00

18LANGL

EYGU

LCHPO

WER

PLAN

TIDAH

OPO

WER

COMPA

NY

P20

09.009

26/25

/201

0

COMBU

STION

TURB

INE,CO

MBINED

CYCLEW/D

UCT

BURN

ERNAT

URA

LGA

S(ONLY)

2375

.28MMBT

U/H

CATA

LYTICOXIDA

TION

(CATOX

),DR

YLO

WNO

X(DLN

),GO

ODCO

MBU

STION

PRAC

TICE

S(GCP

)2PP

MVD

3HR

ROLLING/1

5%O2

BACT

PSD

2510

LB/H

1HR

/15%

O2

DURINGSU

/SD

Limitdo

esno

tapp

lydu

ringSU

/SD.

SIEM

ENSSG

T650

00F

COMBU

STIONTU

RBINE(NGC

T,CC

GT)FORELEC

TRICAL

GENER

ATION,N

OMINAL

269MW

AND2.14

66MMSCF/HR

.WITHDU

CTBU

RNER

GA01

38LIVE

OAK

SPO

WER

PLAN

TLIVE

OAK

SCO

MPA

NY,

LLC

4911

12700

75P

020

4/8/20

10

COMBINED

CYCLE

COMBU

STIONTU

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ELEC

TRIC

GENER

ATINGPLAN

TNAT

URA

LGA

S60

0MW

GOODCO

MBU

STION

PRAC

TICE

SAN

DCA

TALYTIC

OXIDA

TION

2PP

M@15

%02

3HO

URAV

ERAG

EWO/O

DUCT

FIRING/

CONDITIO

BACT

PSD

208T/YR

12CO

NSECU

TVE

MONTH

AVER

AGE/CO

NDITI

ON2.

L2CO

MBU

STIONTU

RBINES

ANDONESTEA

MTU

RBINE,

HRSG

with

ADU

CTBU

RNER

.CTs

SELECT

EDAR

ESIEM

ENS

MODE

LSG

T650

00F

CA12

09HIGH

DESERT

POWER

PROJECT

HIGH

DESERT

POWER

PROJECT

LLC

SE98

013/11

/201

0

COMBU

STIONTU

RBINE

GENER

ATORS

(NORM

ALOPERA

TION)NAT

URA

LGA

S19

0MW

OXIDA

TIONCA

TALYST

SYSTEM

4PP

MVD

@15

%O2,24

HRAV

GBA

CTPSD

0

THRE

E(3)C

OMBU

STIONTU

RBINEGE

NER

ATORS

AT19

0MW

EACH

ANDEQ

UIPPEDWITHA16

0MMBT

U/HRDU

CTBU

RNER

ANDHR

SG

CA12

09HIGH

DESERT

POWER

PROJECT

HIGH

DESERT

POWER

PROJECT

LLC

SE98

013/11

/201

0

COMBU

STIONTU

RBINE

GENER

ATOR(STA

RTUP

PERIODS

)NAT

URA

LGA

S19

0MW

OXIDA

TIONCA

TALYST

SYSTEM

183LB/COLD

STAR

TUP

COLD

STAR

TUP

PERIODS

BACT

PSD

0

Coldstartuplim

iton

ly.TH

REE(3)C

OMBU

STION

TURB

INEGE

NER

ATORS

AT19

0MW

EACH

ANDEQ

UIPPED

WITHA16

0MMBT

U/HRDU

CTBU

RNER

ANDHR

SG

CA12

09HIGH

DESERT

POWER

PROJECT

HIGH

DESERT

POWER

PROJECT

LLC

SE98

013/11

/201

0

COMBU

STIONTU

RBINE

GENER

ATOR

(SHU

TDOWNPERIODS

)NAT

URA

LGA

S19

0MW

OXIDA

TIONCA

TALYST

SYSTEM

239LB/SHU

TDOWN

SHUTD

OWNPERIODS

BACT

PSD

0

Shutdo

wnlim

iton

ly.TH

REE(3)C

OMBU

STIONTU

RBINE

GENER

ATORS

AT19

0MW

EACH

ANDEQ

UIPPEDWITHA

160MMBT

U/HRDU

CTBU

RNER

ANDHR

SG

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:C O

Prop

osed

COLi

mit:

4PP

MVD

@15

%O

2w

hile

oper

atin

gat

norm

altu

rbin

eba

selo

adco

nditi

ons;

Equi

vale

ntto

0.00

9lb

/MM

Btu

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

hput

Thro

ughp

utU

nit

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

tEm

issi

onLi

mit

Avg

Tim

eCo

nditi

onCa

seBy

Case

Basi

sSt

anda

rdEm

issi

onLi

mit

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

CA11

91VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#2(NORM

ALOPERA

TION,N

ODU

CTBU

RNING)

NAT

URA

LGA

S15

4MW

OXIDA

TIONCA

TALYST

SYSTEM

2PP

MVD

@15

%O2,1HR

AVG

(NODU

CTBU

RNING)

BACT

PSD

0Do

esno

tinclude

SU/SDem

issions.

CA11

91VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#1(NORM

ALOPERA

TION,N

ODU

CTBU

RNING)

NaturalGa

s15

4MW

OXIDA

TIONCA

TALYST

SYSTEM

2PP

MVD

@15

%O2,1HR

AVG

(NODU

CTBU

RNING)

BACT

PSD

0Do

esno

tinclude

SU/SDem

issions.

CA11

91VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#2(NORM

ALOPERA

TION,W

ITH

DUCT

BURN

ING)

NAT

URA

LGA

S15

4MW

OXIDA

TIONCA

TALYST

SYSTEM

3PP

MVD

@15

%O2,1HR

AVG

(W/D

UCT

BURN

ING)

BACT

PSD

0Do

esno

tinclude

SU/SDem

issions.

CA11

91VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#1(NORM

ALOPERA

TION,W

ITH

DUCT

BURN

ING)

NAT

URA

LGA

S15

4MW

OXIDA

TIONCA

TALYST

SYSTEM

3PP

MVD

@15

%O2,1HR

AVG

(W/D

UCT

BURN

ING)

BACT

PSD

0Do

esno

tinclude

SU/SDem

issions.

CA11

91VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#1(COLD

STAR

TUP

PERIODS

)NAT

URA

LGA

S15

4MW

OXIDA

TIONCA

TALYST

SYSTEM

224LB/H

COLD

STAR

TUP

PERIODS

BACT

PSD

0SU

/SDLimiton

ly.

CA11

91VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#2(COLD

STAR

TUP

PERIODS

)NAT

URA

LGA

S15

4MW

OXIDA

TIONCA

TALYST

SYSTEM

224LB/H

COLD

STAR

TUP

PERIODS

BACT

PSD

0SU

/SDLimiton

ly.

CA11

91VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#1(W

ARM

&am

p;HO

TSTAR

TUPPERIODS

)NAT

URA

LGA

S15

4MW

OXIDA

TIONCA

TALYST

SYSTEM

247LB/H

WAR

M&HO

TSTAR

TUPPERIODS

BACT

PSD

0SU

/SDLimiton

ly.

CA11

91VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#2(W

ARM

&am

p;HO

TSTAR

TUPPERIODS

)NAT

URA

LGA

S15

4MW

OXIDA

TIONCA

TALYST

SYSTEM

247LB/H

WAR

M&HO

WSTAR

TUPPERIODS

BACT

PSD

0SU

/SDLimiton

ly.

CA11

91VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#1(SHU

TDOWN

PERIODS

)NAT

URA

LGA

S15

4MW

OXIDA

TIONCA

TALYST

SYSTEM

674LB/H

SHUTD

OWNPERIODS

BACT

PSD

0SU

/SDLimiton

ly.

CA11

91VICT

ORV

ILLE

2HY

BRID

POWER

PROJECT

CITY

OFVICT

ORV

ILLE

SE07

023/11

/201

0

COMBU

STIONTU

RBINE

#2(SHU

TDOWN

PERIODS

)NAT

URA

LGA

S15

4MW

OXIDA

TIONCA

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674LB/H

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LLEN

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SLP

8337

88/18

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9ELEC

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NAT

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LGA

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5MW

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NAT

URA

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8482

41/23

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ATION

NAT

URA

LGA

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MW

OXIDA

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0

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ELED

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DHR

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ELED

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ine

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mit:

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atin

gat

norm

altu

rbin

eba

selo

adco

nditi

ons;

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vale

ntto

0.00

9lb

/MM

Btu

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

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elTh

roug

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nit

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etho

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scrip

tion

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Lim

itEm

issi

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mit

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tEm

issi

onLi

mit

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Tim

eCo

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seBy

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sSt

anda

rdEm

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onLi

mit

Stan

dard

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nit

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dard

Lim

itAv

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me

Cond

ition

Addi

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mit

Lim

itN

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FL03

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UNTY

ENER

GYCE

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FLORIDA

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AND

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L)09

9064

600

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6)7/30

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8

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250

MW

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W)G

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SCO

MBU

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TRICAL

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ATORS

(CTG

)

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INE

COGE

NER

ATIONFA

CILITY

THEDO

WCH

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COMPA

NY

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7/23

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8

(4)G

ASTU

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BURN

ERS

NAT

URA

LGA

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76MMBT

U/H

GOODCO

MBU

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PRAC

TICE

S21

2.5LB/H

HOURLYMAX

IMUM

BACT

PSD

25PP

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@15

%O2

ANNUAL

AVER

AGE

4NAT

URA

LGA

SFIRE

DGE

FRAM

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GASTU

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SUPP

LEMEN

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DDU

CTBU

RNER

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LA02

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SENAL

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POWER

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T

SOUTH

WESTELEC

TRIC

POWER

COMPA

NY

(SWEPCO

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726

3/20

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8TW

OCO

MBINED

CYCLE

GASTU

RBINES

NAT

URA

LGA

S21

10MMBT

U/H

PROPEROPERA

TING

PRAC

TICE

S14

3.31

LB/H

MAX

BACT

PSD

10PP

MVD

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%O2

ANNUAL

AVER

AGE

CTG1TU

RBINE/DU

CTBU

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(EQT

012)

CTG2TU

RBINE/DU

CTBU

RNER

(EQT013

)

LA02

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SENAL

HILL

POWER

PLAN

T

SOUTH

WESTELEC

TRIC

POWER

COMPA

NY

(SWEPCO

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726

3/20

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8

SCN4HO

TSTAR

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CTG1SCN8HO

TSTAR

TUPCT

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NAT

URA

LGA

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10MMBT

U/H

COMPLETEEV

ENTS

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POSSIBLE

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MAN

UFA

CTURE

¿SRE

COMMEN

DED

PROCE

DURE

S.15

75.8

LB/H

MAX

BACT

PSD

0

CT01

51KLEENEN

ERGY

SYSTEM

S,LLC

KLEENEN

ERGY

SYSTEM

S,LLC

10401

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401

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8

SIEM

ENSSG

T650

00F

COMBU

STIONTU

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D#2

(NAT

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LGA

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U/HRNAT

URA

LGA

SDU

CTBU

RNER

NAT

URA

LGA

S2.1MMCF/H

COCA

TLYST

4.3LB/H

W/O

UTDU

CTBU

RNER

BACT

PSD

0.9PP

MVD

@15

%O2

1HR

BLOCK

(W/O

UTDU

CTBU

RNER

)

Limitdo

esno

tinclude

ductbu

rner.2TU

RBINETR

AINS.

EACH

TURB

INETR

AINCO

NSISTSOFASIEM

ENSSG

T650

00FCO

MBU

STIONTU

RBINE,DU

CTBU

RNER

ANDAN

HRSG

.

GA01

27PLAN

TMCD

ONOUGH

COMBINED

CYCLE

SOUTH

ERN

COMPA

NY/GE

ORG

IAPO

WER

4911

06700

03V

022

1/7/20

08CO

MBINED

CYCLE

COMBU

STIONTU

RBINENAT

URA

LGA

S25

4MW

OXIDA

TIONCA

TALYST

1.8PP

M@

15%O2

3HO

UR

BACT

PSD

0

6TU

RBINES,LIM

ITSAR

EFO

REA

CHTU

RBINE(M

ITSU

BISH

IMODE

LM50

1G).

Thisisno

tthe

sametype

ofun

itas

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itisno

tcon

sidered

intheanalysis.

MN00

71FA

IRBA

ULT

ENER

GYPA

RKMINNESOTA

MUNICIPAL

POWER

AGEN

CY13

1000

7100

36/5/20

07

COMBINED

CYCLE

COMBU

STIONTU

RBINE

W/DUCT

BURN

ERNAT

URA

LGA

S17

58MMBT

U/H

GOODCO

MBU

STION

9PP

MVD

3HR

.AVG

CTGON

NGNODB

BACT

PSD

11PP

MVD

3HR

AVGCT

GNG

DBNGOROIL

COMBU

STIONTU

RBINEAN

DDU

CTBU

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CA11

44BLYTHE

ENER

GYPR

OJECT

IICA

ITHN

ESSBLYTHE

II,LLC

SE02

014/25

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72CO

MBU

STION

TURB

INES

NAT

URA

LGA

S17

0MW

4PP

MVD

AT15

%O2,3HR

AVGBA

CTPSD

0

OK01

17PSOSO

UTH

WESTERN

POWER

PLT

PUBLICSERV

ICECO

OF

OKLAH

OMA

2003

403CPSD

2/9/20

07GA

SFIRE

DTU

RBINES

COMBU

STIONCO

NTR

OL

25PP

MVD

@15

%O2

BACT

PSD

0

FL02

85PR

OGR

ESSBA

RTOW

POWER

PLAN

TPR

OGR

ESSEN

ERGY

FLORIDA

(PEF)

PSDFL

381AN

D10

3001

101

0AC

1/26

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7

COMBINED

CYCLE

COMBU

STIONTU

RBINE

SYSTEM

(4ON1)

NAT

URA

LGA

S19

72MMBT

U/H

GOODCO

MBU

STION

8PP

MVD

24HR

BLOCK

AVER

AGECE

MS

BACT

PSD

0

4MODE

LSG

T650

00FCO

MBU

STIONTU

RBINE

ELEC

TRICAL

GENER

ATORS;FOURDU

CTFIRE

DHE

ATRE

COVE

RYSTEA

MGE

NER

ATORS

(HRSG¿

S)WITHDU

CTBU

RNER

FL02

86FPLWESTCO

UNTY

ENER

GYCE

NTER

FLORIDA

POWER

AND

LIGH

TCO

MPA

NY

PSDFL

354AN

D09

9064

600

1AC

1/10

/200

7

COMBINED

CYCLE

COMBU

STIONGA

STU

RBINES

6UNITS

NAT

URA

LGA

S23

33MMBT

U/H

8PP

MVD

@15

%O2

24HR

BACT

PSD

0

EACH

COMBINED

CYCLEUNITSYSTEM

WILLCO

NSIST

OF:

THRE

ENOMINAL

250MEG

AWAT

TMODE

L50

1GGA

STU

RBINEELEC

TRICAL

GENER

ATORSETS

WITHDU

CTBU

RNER

OK01

15LAWTO

NEN

ERGY

COGE

NFA

CILITY

ENER

GETIX

2001

205CM

1PSD

12/12/20

06CO

MBU

STIONTU

RBINE

ANDDU

CTBU

RNER

GOODCO

MBU

STION

PRAC

TICE

S16

.38PP

MVD

@15

%O2

BACT

PSD

0

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

Jan

1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

5Co

mbu

stio

nTu

rbin

ePr

oces

sTyp

e15

.21

Pollu

tant

:C O

Prop

osed

COLi

mit:

4PP

MVD

@15

%O

2w

hile

oper

atin

gat

norm

altu

rbin

eba

selo

adco

nditi

ons;

Equi

vale

ntto

0.00

9lb

/MM

Btu

RBLC

IDFa

cilit

yN

ame

Corp

orat

eor

Com

pany

Nam

ePe

rmit

Num

Perm

itIs

suan

ceDa

tePr

oces

sNam

ePr

imar

yFu

elTh

roug

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Thro

ughp

utU

nit

Cont

rolM

etho

dDe

scrip

tion

Emis

sion

Lim

itEm

issi

onLi

mit

Uni

tEm

issi

onLi

mit

Avg

Tim

eCo

nditi

onCa

seBy

Case

Basi

sSt

anda

rdEm

issi

onLi

mit

Stan

dard

Emis

sion

Lim

itU

nit

Stan

dard

Lim

itAv

erag

eTi

me

Cond

ition

Addi

tiona

lPer

mit

Lim

itN

otes

TX04

97INEO

SCH

OCO

LATE

BAYO

UFA

CILITY

INEO

SUSA

LLC

PSDTX

983AN

D46

192

8/29

/200

6

COGE

NER

ATIONTR

AIN

2AN

D3(TURB

INEAN

DDU

CTBU

RNER

EMISSIONS)

NAT

URA

LGA

S35

MW

BPAM

OCO

PROPO

SES

PROPERCO

MBU

STION

CONTR

OLAS

BACT

FORCO

ANDVO

CEM

ISSIONS

FROM

THETU

RBINES

AND

DUCT

BURN

ERS.

COEM

ISSIONSFROM

EACH

TURB

INEWILLNOT

EXCE

ED15

PPMVD

AT85

%TO

100%

OFBA

SELO

AD.

COEM

ISSIONSFROM

EACH

TU66

.81LB/H

BACT

PSD

0

2NOMINALLY

RATED35

MW

GASFIRE

DTU

RBINES

AND

TWOHE

ATRE

COVE

RYSTEA

MGE

NER

ATORS,EQUIPPED

WITHDU

CTBU

RNER

S.

TX05

02

NAC

OGD

OCH

ESPO

WER

STER

NEGE

NER

ATING

FACILITY

NAC

OGD

OCH

ESPO

WER

LLC

PSDTX

1015

AND

4929

36/5/20

06

WESTINGH

OUSE/SIEM

ENSMODE

LSW

501F

GASTU

RBINEW/ 4

16.5

MMBT

UDU

CTNAT

URA

LGA

S19

0MW

STEA

GPO

WER

LLC

REPR

ESEN

TSGO

OD

COMBU

STIONPR

ACTICE

SFO

RTH

ECO

NTR

OLOFCO

109.4LB/H

BACT

PSD

0

3WESTINGH

OUSE/SIEMEN

SMODE

L50

1FCO

MBU

STION

TURB

INES,THR

EEHE

ATRE

COVE

RYSTEA

MGE

NER

ATORS

(HRSGS

)WITHDU

CTBU

RNER

S,AN

DTH

REE14

0MW

STEA

MDR

IVEN

TURB

INEGE

NER

ATORS

MN00

66

NORT

HERN

STAT

ESPO

WER

CO.D

BAXC

ELEN

ERGY

RIVE

RSIDE

PLAN

T

NORT

HERN

STAT

ESPO

WER

CO.D

BAXC

ELEN

ERGY

0530

0015

004

5/16

/200

6TU

RBINE,CO

MBINED

CYCLE(2)

NAT

URA

LGA

S18

85mmbtu/h

GOODCO

MBU

STION

PRAC

TICE

S10

PPMVD

@15

%O2

3HR

BLOCK

BACT

PSD

10PP

M@

15%

O2

2NGFIRE

DFCLAS

SCO

MBU

STIONTU

RBINES

&HR

SG.

NODU

CTBU

RNER

.EITHE

RGE

ORMITSU

BISH

ITURB

INES.

NY00

95CA

ITHN

ESBE

LLPO

RTEN

ERGY

CENTER

CAITHN

ESSBE

LLPO

RT,

LLC

PSDNY00

015/10

/200

6CO

MBU

STIONTU

RBINENAT

URA

LGA

S22

21MMBU

T/H

OXIDA

TIONCA

TALYST

2PP

MVD

@15

%02

BACT

PSD

0

CO00

56RO

CKYMOUNTA

INEN

ERGY

CENTER,

LLC

CALPINECO

RP.

05WE052

45/2/20

06

NAT

URA

LGA

SFIRE

D,CO

MBINED

CYCLE

TURB

INE

NAT

URA

LGA

S30

0MW

USE

GOODCO

MBU

STION

CONTR

OLPR

ACTICE

SAN

DCA

TALISTICOXIDA

TION.

3PP

M@

15%O2

BACT

PSD

3PP

M@

15O2

THISISAN

ADDITIONOFONECO

MBU

STIONTU

RBINE,

GASFIRE

D,CO

MBINED

CYCLE.

CA11

95ELKHILLSPO

WER

LLC

ELKHILLSPO

WER

LLC

SJ99

021/12

/200

6

COMBU

STIONTU

RBINE

GENER

ATOR,

2un

its(NormalOpe

ratio

n)NAT

URA

LGA

S16

6MW

SCRORSCONOX

4PP

MVD

@15

%O2,1HR

AVG

BACT

PSD

0

Eac h

CTGsystem

willgene

rate

166MW

unde

rdesign

ambien

tcon

ditio

nswith

steam

power

augm

entatio

nfrom

thedu

ctbu

rners,and15

3MW

with

outsteam

augm

entatio

n.

CA11

95ELKHILLSPO

WER

LLC

ELKHILLSPO

WER

LLC

SJ99

021/12

/200

6

Combu

stionTurbine

Gene

rator,2un

its(Turbine

Shutdo

wn

Even

ts)

NaturalGa

s16

6MW

SCRORSCONOX

222LB/EVE

NT

TURB

INESH

UTD

OWN

EVEN

TSBA

CTPSD

0

LimitforS

hutdow

nlim

itson

ly.Each

CTGsystem

will

gene

rate

166MW

unde

rdesignam

bien

tcon

ditio

nswith

steam

power

augm

entatio

nfrom

thedu

ctbu

rners,and

153MW

with

outsteam

augm

entatio

n.

CA11

95ELKHILLSPO

WER

LLC

ELKHILLSPO

WER

LLC

SJ99

021/12

/200

6

COMBU

STIONTU

RBINE

GENER

ATOR,

2un

its(Exten

dedStartup

Even

ts)

NAT

URA

LGA

S16

6MW

SCRORSCONOX

3600

LB/EVE

NT

EXTENDE

DSTAR

TUP

EVEN

TSBA

CTPSD

0

Startuplim

iton

ly.Each

CTGsystem

willgene

rate

166

MW

unde

rdesignam

bien

tcon

ditio

nswith

steam

power

augm

entatio

nfrom

thedu

ctbu

rners,and15

3MW

with

outsteam

augm

entatio

n.

TX05

16

CITY

PUBLICSERV

ICEJK

SPRU

CEELEC

TRICE

GENER

ATINGUNIT2

CITY

PUBLICSERV

ICE

PSDTX

1037

AND

7049

212

/28/20

05SPRU

CEPO

WER

GENER

ATORUNITNO2

4480

LB/H

BACT

PSD

0

NV00

35TR

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DBforH

RSG;

4total.

*OH03

52ORE

GONCLEA

NEN

ERGY

CENTER

ARCA

DIS,US,INC.

P011

0840

6/18

/201

3

2Co

mbine

dCycle

Combu

stionTurbines

Siem

ens,with

out

ductbu

rners

NaturalGa

s51

5600

MMSCF/rolling

12mon

ths

oxidationcatalyst

3.9LB/H

BACT

PSD

1PP

MPP

MVD

AT15

%O2

2Mitsub

ishi293

2MMBtu/Hcombine

dcyclecombu

stion

turbines,bothwith

ductbu

rners.

Willinstalleith

er2

Siem

enso

r2Mitsub

ishi,no

tboth

*OH03

52ORE

GONCLEA

NEN

ERGY

CENTER

ARCA

DIS,US,INC.

P011

0840

6/18

/201

3

2Co

mbine

dCycle

Combu

stionTurbines

Siem

ens,with

duct

burners

NaturalGa

s51

560MMSCF/rolling

12MO

oxidationcatalyst

5.9LB/H

BACT

PSD

1.9PP

MPP

MVD

AT15

%O2

2Mitsub

ishi293

2MMBtu/Hcombine

dcyclecombu

stion

turbines,bothwith

ductbu

rners.

Willinstalleith

er2

Siem

enso

r2Mitsub

ishi,no

tboth

*OH03

52ORE

GONCLEA

NEN

ERGY

CENTER

ARCA

DIS,US,INC.

P011

0840

6/18

/201

3

2Co

mbine

dCycle

Combu

stionTurbines

Mitsub

ishi,with

duct

burners

NaturalGa

s47

917MMSCF/rolling

12MO

oxidationcatalyst

7.3LB/H

BACT

PSD

2PP

MPP

MVD

AT15

%O2

2Mitsub

ishi293

2MMBtu/Hcombine

dcyclecombu

stion

turbines,bothwith

ductbu

rners.

Willinstalleith

er2

Siem

enso

r2Mitsub

ishi,no

tboth

*OH03

52ORE

GONCLEA

NEN

ERGY

CENTER

ARCA

DIS,US,INC.

P011

0840

6/18

/201

3

2Co

mbine

dCycle

Combu

stionTurbines

Mitsub

ishi,with

out

ductbu

rners

NaturalGa

s47

917MMSCF/rolling

12MO

oxidationcatalyst

7.9LB/H

BACT

PSD

2PP

MPP

MVD

AT15

%O2

2Mitsub

ishi293

2MMBtu/Hcombine

dcyclecombu

stion

turbines,bothwith

outd

uctb

urne

rs.Willinstalleith

er2

Siem

enso

r2Mitsub

ishi,no

tboth

*MI0

405

MIDLAND

COGE

NER

ATION

VENTU

REMIDLANDCO

GENER

ATION

VENTU

RE10

312

4/23

/201

3

Naturalgasfue

led

combine

dcycle

combu

stionturbine

gene

rators(CTG

)with

HRSG

Naturalgas

2237

MMBT

U/H

Good

combu

stionpractices

0.00

18LB/M

MBT

UEA

CHCT

G;TEST

PROTO

COL

BACT

PSD

02naturalgas

fired

CTGs

with

each

turbinecontaining

ahe

atrecovery

steam

gene

rator(HR

SG)

*MI0

405

MIDLAND

COGE

NER

ATION

VENTU

REMIDLANDCO

GENER

ATION

VENTU

RE10

312

4/23

/201

3

Naturalgasfue

led

combine

dcycle

combu

stionturbine

gene

rators(CTG

)with

HRSG

anddu

ctNaturalgas

2486

MMBT

U/H

Good

combu

stionpractices

0.00

4LB/M

MBT

UTEST

PROTO

COL

BACT

PSD

02naturalgas

fired

CTGs

with

each

turbinecontaining

ahe

atrecovery

steam

gene

rator(HR

SG)w

ithdu

ctbu

rner

*PA02

91HICK

ORY

RUN

ENER

GYSTAT

ION

HICK

ORY

RUNEN

ERGY

LLC

3733

7A4/23

/201

3CO

MBINED

CYCLE

UNITS#1

and#2

NaturalGa

s3.4MMCF/HR

Oxidatio

nCatalyst

1.5PP

MVD

@15

%OXYGE

NWITHORWITHO

UT

DUCT

BURN

EROTH

ERCA

SEBY

CASE

0

With

ductbu

rners.Mod

elsu

nder

consideration:

1.Ge

neralElectric

7FA(GE7FA,

2.Siem

ensS

GT650

00F

(Siemen

sF),3.Mitsub

ishiM

501G

(Mitsub

ishiG

),4.

Siem

ensS

GT680

00H(Siemen

sH)

*VA03

21

BRUNSW

ICK

COUNTY

POWER

STAT

ION

VIRG

INIA

ELEC

TRIC

AND

POWER

COMPA

NY

5240

400

13/12

/201

3

COMBU

STION

TURB

INE

GENER

ATORS,(3)

NaturalGa

s34

42MMBT

U/H

Oxidatio

ncatalyst;goo

dcombu

stionpractices.

0.7PP

MVD

3HAV

G/WITHO

UT

DUCT

BURN

ING

BACT

PSD

0Three(3)M

itsub

ishiM

501GA

Ccombu

stionturbine

gene

ratorswith

HRSG

ductbu

rners(naturalgas

fired

).

*TX07

08LA

PALO

MAEN

ERGY

CENTER

LAPA

LOMAEN

ERGY

CENTER,

LLC

1015

42PSDT

X128

82/7/20

13(2)com

bine

dcycle

turbines

naturalgas

650MW

oxidationcatalyst

2PP

MVD

@15

%O2,3HR

ROLLING

BACT

PSD

0

2combu

stionturbines

(CTs)con

nected

toelectric

gene

rators,w

ithdu

ctbu

rners.3mod

elso

fCTun

der

consideration:

(1)G


;(2)

Siem

ens

SGT6

5000

F(4);o

r(3)

Siem

ensS

GT650

00F(5).

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86

MOXIEEN

ERGY

LLC/PA

TRIOT

GENER

ATIONPLT

MOXIEEN

ERGY

LLC

4100

084A

1/31

/201

3

Combine

dCycle

Power

Blocks

472

MW

(2)

NaturalGa

s0

COCatalyst

1PP

MDV

WITHO

UTDU

CTBU

RNER

BACT

PSD

33.8

TPY

EACH

UNIT

Does

notinclude

ductbu

rner.2naturalgas

fired

combine

dcyclepo

werblocks

whe

reeach

powerblock

consistso

facombu

stionturbineandhe

atrecovery

steam

gene

ratorw

ithdu

ctbu

rner.

*OH03

56

DUKE

ENER

GYHA

NGINGRO

CKEN

ERGY

DUKE

ENER

GYHA

NGING

ROCK

,LLC

P011

0487

12/18/20

12

Turbines

(4)(mod

elGE

7FA)

DuctBu

rners

Off

NAT

URA

LGA

S17

2MW

Usin

gefficient

combu

stion

techno

logy

3.2LB/H

BACT

PSD

0Four

GE7FAcombine

dcycleturbines

with

ductbu

rners

*OH03

56

DUKE

ENER

GYHA

NGINGRO

CKEN

ERGY

DUKE

ENER

GYHA

NGING

ROCK

,LLC

P011

0487

12/18/20

12

Turbines

(4)(mod

elGE

7FA)

DuctBu

rners

On

NAT

URA

LGA

S17

2MW

Usin

gefficient

combu

stion

techno

logy

7.3LB/H

BACT

PSD

0Four

GE7FAcombine

dcycleturbines

with

ductbu

rners

*IN01

58ST.JOSEPH

ENEG

RYCE

NTER,

LLC

ST.JOSEPH

ENER

GYCE

NTER,

LLC

14131

003

0057

912

/3/201

2

FOUR(4)N

ATURA

LGA

SCO

MBINED

CYCLECO

MBU

STION

TURB

INES

NAT

URA

LGA

S23

00MMBT

U/H

OXIDIZEDCA

TALYST

1PP

MVD

3HO

URS

BACT

PSD

0FO

UR(4)N

ATURA

LGA

SCO

MBINED

CYCLECO

MBU

STION

TURB

INES

WITHDU

CTBU

RNER

S

Calp

ine

Man

kato

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/BAC

T/LA

ERCl

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seSe

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ch=

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1,20

05Cu

rren

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arch

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=O

ctob

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tant

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osed

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ame

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58ST.JOSEPH

ENEG

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ST.JOSEPH

ENER

GYCE

NTER,

LLC

14131

003

0057

912

/3/201

2

FOUR(4)N

ATURA

LGA

SCO

MBINED

CYCLECO

MBU

STION

TURB

INES

STAR

TUP/SH

UTD

OWN

NAT

URA

LGA

S23

00MMBT

U/H

22TO

NS

12CO

NSECU

TIVE

MONTH

PERIOD

BACT

PSD

0.00

2lb/M

MBtu

*DE00

23NRG

ENER

GYCE

NTERDO

VER

NRG

ENER

GYCE

NTERDO

VER

LLC

AQM

001/00

127(R

2)(REV

1)10

/31/20

12UNIT2

KD1

NaturalGa

s65

5MMBT

U/H

Oxidatio

ncatalystsystem

6.4LB/H

1HO

URAV

ERAG

EOTH

ERCA

SEBY

CASE

0.01

0lb/M

MBtu

500MMBT

U/hrG

asTurbine(M

odel:G

ELM

6000

)

TX06

18CH

ANNEL

ENER

GYCE

NTERLLC

CHAN

NEL

ENER

GYCE

NTER

LLC

PSDT

X955

M1

10/15/20

12Co

mbine

dCycle

Turbine

naturalgas

180MW

Good

combu

stion

2PP

MVD

@15

%O2

BACT

PSD

0

TheturbineisaSiem

ens5

01Fratedat

ano

minal18

0MW

andthedu

ctbu

rner

willhave

amaxim

umde

signhe

atinpu

tof4

75MMBtu/hr.

FL03

37PO

LKPO

WER

STAT

ION

TAMPA

ELEC

TRIC

COMPA

NY

1050

23303

4AC

10/14/20

12Co

mbine

cyclepo

wer

block(4

on1)

naturalgas

1160

MW

fuelSulfu

rlim

its1.4PP

MVD

@15

%O2

BACT

PSD

04naturalgas

fueled

nominal16

5MW

simplecycle

combu

stionturbineelectricalgene

rators(CTG

s)

PA02

78

MOXIELIBE

RTY

LLC/AS

YLUM

POWER

PLT

MOXIEEN

ERGY

LLC

0800

045A

10/10/20

12

Combine

dcycle

Turbines

(2)

Natural

gasfire

dNaturalGa

s32

77MMBT

U/H

Oxidatio

nCatalyst

1PP

MVD

WITHO

UTDU

CTBU

RNER

LAER

02combine


acombu

stionturbine

andhe

atrecovery

steam

gene

ratorw

ithdu

ctbu

rner

TX06

19DE

ERPA

RKEN

ERGY

CENTER

DEER

PARK

ENER

GYCE

NTER

LLC

PSDT

X979

M2

9/26

/201

2Co

mbine

dCycle

Turbine

naturalgas

180MW

good

combu

stion,useof

natural

gas

2PP

MVD

@15

%O2

BACT

PSD

0

naturalgas

fired

combine

dcycleturbinegene

rator

Siem

ens5

01Fwith

ahe

atrecovery

steam

gene

rator

equipp

edwith

adu

ctbu

rner.

TX06

20ES

JOSLIN

POWER

PLAN

TCA

LHOUNPO

RTAU

THORITY

PSDT

X125

69/12

/201

2Co

mbine

dcyclegas

turbine

naturalgas

195MW

good

combu

stionandnaturalgas

asfuel

2PP

MVD

@15

%O2

BACT

PSD

0Thethreecombu

stionturbinegene

rators(CTG

)willbe

theGe

neralElectric

7FA.

Nodu

ctbu

rners.

*WY00

70

CHEYEN

NEPR

AIRIE

GENER

ATING

STAT

ION

BLAC

KHILLSPO

WER

,INC.

CT12

636

8/28

/201

2Co

mbine

dCycle

Turbine(EP0

1)NaturalGa

s40

MW

Oxidatio

nCatalyst

3PP

MVAT

15%

O2

1HO

UR

BACT

PSD

14.7

TONSPERYEAR

(5)4

0MW

GELM

6000

combu

stionturbinegene

rators

*WY00

70

CHEYEN

NEPR

AIRIE

GENER

ATING

STAT

ION

BLAC

KHILLSPO

WER

,INC.

CT12

636

8/28

/201

2Co

mbine

dCycle

Turbine(EP0

2)NaturalGa

s40

MW

Oxidatio

nCatalyst

3PP

MVAT

15%

O2

3HO

URAV

ERAG

EBA

CTPSD

14.7

TONSPERYEAR

(5)4

0MW

GELM

6000

combu

stionturbinegene

rators

LA02

57SA

BINEPA

SSLN

GTERM

INAL

SABINEPA

SSLN

G,LP

&SA

BINEPA

SSLIQUEFAC

TION,

LLPSDLA

703(M3)

12/6/201

1

Combine

dCycle

Refrigeration

CompressorT

urbine

s(8)

naturalgas

286MMBT

U/H

Good

combu

stionpractices

and

fueled

bynaturalgas

0.66

LB/H

HOURLYMAX

IMUM

BACT

PSD

0.00

2lb/M

MBtu

GELM

2500

+G4

TX06

00

THOMAS

C.FERG

USO

NPO

WER

PLAN

TLO

WER

COLO

RADO

RIVE

RAU

THORITY

PSDT

X124

49/1/20

11Naturalgasfired

turbines

naturalgas

390MW

Naturalgas,good

combu

stion

practices

andoxidationcatalyst

2PP

MVD

3HR

AT15

%OXYGE

NBA

CTPSD

0Tw

onaturalgas

fired

combine

dcycleturbinegene

rators

(GE7FA)

with

unfired

HRSG

LA02

54

NINEM

ILEPO

INT

ELEC

TRIC

GENER

ATINGPLAN

TEN

TERG

YLO

UISIANALLC

PSDLA

752

8/16

/201

1

COMBINED

CYCLE

TURB

INE

GENER

ATORS

(UNITS

6A&am

p;6B

)NAT

URA

LGA

S71

46MMBT

U/H

GOODCO

MBU

STIONPR

ACTICE

S1.4PP

MVD

@15

%O2

HOURLYAV

ERAG

EW/O

DUCT

BURN

ERBA

CTPSD

02CO

MBINED

CYCLEGA

STU

RBINES

WITHDU

CTBU

RNER

S

CA12

11

COLU

SAGE

NER

ATING

STAT

ION

PACIFICGA

S&ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(NORM

ALOPERA

TION)

NAT

URA

LGA

S17

2MW

2PP

MVD

@15

%O2,1HR

ROLLINGAV

GBA

CTPSD

0

TWO(2)N

ATURA

LGA

SFIRE

DTU

RBINES

AT17

2MW

EACH

.BOTH

TURB

INES

EQUIPPEDWITHA68

8MMBT

U/HRDU

CTBU

RNER

ANDHR

SG.

CA12

11

COLU

SAGE

NER

ATING

STAT

ION

PACIFICGA

S&ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(SHU

TDOWN

PERIODS

)NAT

URA

LGA

S17

2MW

23.9

LB/H

TURB

INE

SHUTD

OWNPERIODS

BACT

PSD

0

SDlim

iton

ly.TW

O(2)N

ATURA

LGA

SFIRE

DTU

RBINES

AT17

2MW

EACH

.BOTH

TURB

INES

EQUIPPEDWITHA68

8MMBT

U/HRDU

CTBU

RNER

ANDHR

SG.

CA12

11

COLU

SAGE

NER

ATING

STAT

ION

PACIFICGA

S&ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(WAR

MSTAR

TUPPERIODS

)NAT

URA

LGA

S17

2MW

27.7

LB/H

WAR

MSTAR

TUP

PERIODS

BACT

PSD

0

SUlim

iton

ly.TW

O(2)N

ATURA

LGA

SFIRE

DTU

RBINES

AT17

2MW

EACH

.BOTH

TURB

INES

EQUIPPEDWITHA68

8MMBT

U/HRDU

CTBU

RNER

ANDHR

SG.

CA12

11

COLU

SAGE

NER

ATING

STAT

ION

PACIFICGA

S&ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(HOT

STAR

TUPPERIODS

)NAT

URA

LGA

S17

2MW

27.7

LB/H

HOTSTAR

TUP

PERIODS

BACT

PSD

0

SULimiton

ly.TW

O(2)N

ATURA

LGA

SFIRE

DTU

RBINES

AT17

2MW

EACH

.BOTH

TURB

INES

EQUIPPEDWITHA

688MMBT

U/HRDU

CTBU

RNER

ANDHR

SG.

CA12

11

COLU

SAGE

NER

ATING

STAT

ION

PACIFICGA

S&ELEC

TRIC

COMPA

NY

SAC06

013/11

/201

1

COMBU

STION

TURB

INES

(COLD

STAR

TUPPERIODS

)NAT

URA

LGA

S17

2MW

27.7

LB/H

COLD

STAR

TUP

PERIODS

BACT

PSD

0

SULimiton

ly.TWO(2)N

ATURA

LGA

SFIRE

DTU

RBINES

AT17

2MW

EACH

.BOTH

TURB

INES

EQUIPPEDWITHA68

8MMBT

U/HRDU

CTBU

RNER

ANDHR

SG.

Calp

ine

Man

kato

Ener

gyCe

nter

RACT

/BAC

T/LA

ERCl

earin

ghou

seSe

arch

Sear

ch=

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1,20

05Cu

rren

tSe

arch

Date

=O

ctob

er26

,201

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mbu

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nTu

rbin

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oces

sTyp

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.21

Pollu

tant

:VO

C

Prop

osed

VOC

Lim

it:3.

4PP

MVD

@15

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2;Eq

uiva

lent

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004

lb/M

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u

RBLC

IDFa

cilit

yN

ame

Corp

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Com

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me

Cond

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mit

Lim

itN

otes

*IL01

12NELSO

NEN

ERGY

CENTER

INVE

NER

GYNELSO

N,LLC

9808

0039

12/28/20

10ElectricGe

neratio

nFacility

NaturalGa

s22

0MW

each

4PP

MVD

@15

%O2

HOURLYAV

GEXCE

PTDU

RINGSSM

OR

TUNING

BACT

PSD

0

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/17/

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Die

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Die

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