Technical Support Document Draft Air Emission Permit No. 03700003-101 … · · 2016-06-01Technical Support Document, ... 03700003-101 Page 1 of 12 Technical Support Document For

Technical Support Document, Permit Number: 03700003-101 Page 1 of 12

Technical Support Document For

Draft Air Emission Permit No. 03700003-101 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)

Northern States Power a MN Corp dba Xcel Energy 414 Nicollet Mall MP 7B Minneapolis, Minnesota 55401

Xcel Energy - Black Dog Generating Plant 1400 Black Dog Rd E Burnsville, Dakota County, Minnesota 55337

Contact: Jonathan Amos Phone: 612-330-7682

1.2 Facility description

Xcel Energy – Black Dog is an electric generating plant. The facility is composed of a natural gas-fired combined cycle gas turbine with duct burner, two emergency generators, one fire pump, and an auxiliary boiler. The main pollutants of concern are nitrogen oxides (NOx), carbon monoxide (CO), and carbon dioxide equivalent (CO2e) emitted from the combined cycle gas turbine. The turbine is equipped with low-NOx burners and NOx emissions are controlled by selective catalytic reduction (SCR).

1.3 Description of the activities allowed by this permit action This permit action is a major amendment with a minor amendment. Construction of a new simple cycle combustion turbine is authorized by this permit action. The main pollutants of concern from the new turbine are NOx, CO, and CO2e. The new turbine Unit 6 will be equipped with low-NOx burners. The major amendment also incorporates the April 2015 decommissioning of two coal fired units, Unit 3 (EU003) and Unit 4 (EU004), and the cessation of all coal-related activities. The minor amendment is to add requirements for the auxiliary boiler to the permit. The auxiliary boiler was installed in 2015 to provide heat to the facility, a role that was previously filled by the coal-fired boilers. The MPCA has a combined operating and construction permitting program under Minn. R. ch. 7007, and under Minn. R. 7007.0800. Under that authority, this permit action authorizes construction.

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

Date received Application type and description 03/02/2015 Permit Change - Minor 10/15/2015 Permit Change - Major

1.5 Facility emissions:


Table 3. Title I emissions summary

Pollutant

Emissions increase from the modification (tpy)

Limited emissions increase from the modification (tpy)

Source-wide contemporaneous increases and decreases* (tpy)

Net emissions increase (tpy)

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

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

PM 31.1 10.3 -216 0 25 No PM10 31.1 10.3 -216 0 15 No PM2.5 31.1 10.3 -55.2 0 10 No NOx 309 104 -6,120 0 40 No SO2 33.3 11.0 -3,090 0 40 No CO 280 177 -196 0 100 No Ozone (VOC) 31.7 22.0 -24.8 0 40 No Lead 0.00480 0.00158 -0.0232 0 0.6 No CO2e** 1,145,000 379,000 -1,570,000 0 75,000 No H2SO4 0.00409 0.00135 -8.98 0 7 No HAPs - Total 27.3 9.02 NA NA 25 No HAPs - Single 17.3 5.70 NA NA 10 No

*Other emission changes during the contemporaneous period as defined by 40 CFR § 52.21, 40 CFR§ 52.24 or 40 CFR pt. 51. These include the emissions decreases from the decommissioning of boiler Units 3 and 4 using baseline actuals from Jan 2013-Dec 2014 and the emissions increases based on PTE from the addition of the auxiliary boiler. Only PM10, NOx, CO, and CO2e were included in the netting analysis. **Carbon dioxide equivalents as defined in Minn. R. 7007.0100.

Table 4. Facility classification

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

1.6 Changes to permit

1. Due to the switch to a new permitting database (Tempo) from the old database (Delta) all subject items were

assigned a new designation and number. Emission units (EUs) and monitors (MRs) are now called ‘Equipment’, designated by the abbreviation EQUI. Stack Vents (SVs) are now ‘Structures’ (STRU), and groups (GPs) are now ‘Component Groups’ (COMG).

2. Updated requirement for submittal of a Risk Management Plan at the total facility with information about when the most recent Risk Management Plan update was submitted (3/27/2012).

3. Removed total facility requirements related to coal cleanup and the fugitive emissions control plan. 4. Removed total facility requirements related to PM10 and NOx modeling conducted in 1998 and 2002, a

remodeling submittal requirement, and a requirement related to equivalent or better dispersion characteristics. See discussion at Section 3.2 for more information.

5. Removed requirements for all decommissioned sources: Boiler Units 3 and 4, Electrostatic Precipitators CE006-CE009, Fabric Filters CE016-CE021 and CE023-CE025, Break Building Stack SV006, Stacking hopper EU005, Dumper Unloading Building EU006, Yard Agglomerator Silo EU007, Breaker Building EU008, Transfer Tower EU009, Breakers (Crushers) EU010, Tripper Area EU011, Unit 3 Coal Silo EU012, Unit 4 Coal Silo EU013, Units 3 and 4 Ash Silo Vent EU019, Emergency Reclaim Hopper FS003, All Coal Storage Piles FS004, Ash Hauling Traffic FS013, Coal Yard Traffic FS014, Coal Conveyors 7, 7B, 7C, Coal Conveyor 8 FS016, Dumper Unloading Building FS017, and Boiler 3 and 4 Opacity Monitor MR016.


6. Requirements at COMG1 (Emergency Engine Generators) that apply to the engines individually were moved to EQUI60 and EQUI61.

7. All CEMS requirements for the existing CEMS (COMG3 Unit 5/2 CEMS) and the new CEMS (COMG11 Unit 6 CEMS) are at their respective COMG. This was done because the majority of the monitoring requirements apply to the continuous monitoring system consisting of the NOx and O2 CEMS as a group and NOx emissions reporting is dependent on both monitors working in tandem. Certification and testing will be done on the same or very similar schedule for each NOx/O2 monitor pair.

8. Created new group (COMG10) for HAP limits to avoid major source with compliance demonstration based on tracking of emissions from Unit 5/2 combustion turbine/duct burner and Unit 6 combustion turbine.

9. Moved general acid rain requirements from COMG7 (formerly GP008) to the individual acid rain sources (Unit 5/2 EQUI1 and Unit 6 EQUI92).

10. Added Transport Rule requirements to combustion turbine Unit 5/2 (EQUI1). See more information at Section 2.6.

11. Updated language at EQUI90 (Fire Pump) to reflect the decision by the District of Columbia Circuit Court to vacate provisions of 40 CFR § 63.6640(f)(2) which allow operation of an emergency generator without emission controls for up to 100 hours per year as part of an emergency demand-response program. See more information at Section 2.4.

12. Removed insignificant activities related to coal use: Load out of dewatered bottom ash and coal unloading and handling equipment.

2. Regulatory and/or statutory basis

2.1 New source review (NSR) The facility is an existing major source under New Source Review regulations and will continue to be a major source after changes authorized by this permit are made.

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) New Source Performance Standards (NSPS) apply to the operations at this facility. The new combustion turbine EQUI92 will be subject to 40 CFR pt. 60 subpart KKKK Standards of Performance for Stationary Combustion Turbines because this standard applies to any stationary combustion turbine with heat input capacity greater than or equal to 10 MMBtu/hr. The stated heat input capacity of EQUI92 will be 2,011 MMBtu/hr. NSPS subp. TTTT Standards of Performance for Greenhouse Gas Emissions will also apply to the new combustion turbine EQUI92. This standard applies to any stationary combustion turbine that commenced construction after January 8, 2014, that has a base load rating greater than 250 MMBtu/hr of fossil fuel and serves a generator capable of selling greater than 25 MW of electricity to a utility power distribution system (40 CFR§60.5509(a)). Maximum output for the Unit 6 turbine will be approximately 215 MW. 40 CFR pt. 60 subpart Dc Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units applies to the auxiliary boiler EQUI91. This standard applies to steam generating units for which construction commenced after June 9th, 1989 that have a maximum design heat input capacity greater than or equal to 10 MMBtu/hr and less than 100 MMBtu/hr. EQUI91 was constructed in 2015 and has a heat input of 46.7 MMBtu/hr.

2.4 National emission standards for hazardous air pollutants (NESHAP)


The facility will become a synthetic area source of HAPs upon issuance of this permit, when limits to avoid major source status added with this permit action become enforceable. The Permittee has stated that no area source NESHAPs will apply to the operations at Black Dog when the source is re-designated. The facility was designated as a major source of HAPs when the compliance date of 40 CFR pt. 63, subp. DDDDD, National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters, passed on January 31st, 2016. Therefore, the auxiliary boiler is subject and will continue to be subject to the requirements of NESHAP, subp. DDDDD after permit #03700003-101 is issued. The subpart applies to any industrial, commercial, institutional boiler or process heater that is located at a major source of HAP. Several requirements at the existing Fire Pump (EQUI90), which is subject to 40 CFR pt. 63, subp. ZZZZ, were modified to reflect the decision by the District of Columbia Circuit Court to vacate certain provisions of 40 CFR § 63.6640(f)(2) which allow operation of an emergency generator without emission controls for up to 100 hours per year as part of an emergency demand-response program. On July 21, 2015 the court amended the May 1, 2015 decision to specify that the decision would vacate only those portions of the regulations addressed to emergency demand response (40 CFR § 63.6640(f)(2)(ii)-(iii)), and would leave in effect the provisions that allow emergency engines to operate for maintenance checks and readiness testing (40 CFR § 63.6640(f)(2)(i)). On August 14, 2015, the court granted EPA’s July 15, 2015 motion to stay issuance of the court’s mandate until May 1, 2016. Since this permit will be issued after May 1, 2016, language was added to the permit explaining that the engine may no longer be operated according to the provisions at 40 CFR § 63.6640(f)(2)(ii) or (iii) as part of the 100 hours per calendar year allowed by 40 CFR § 63.6640(f)(2).

2.5 Acid rain program

The new combustion turbine EQUI92 will be an affected unit under the Acid Rain program. The Acid Rain Program applies as indicated at 40 CFR §72.6 because EQUI92 is a utility unit that is a new unit.

2.6 Compliance assurance monitoring (CAM)

CAM does not apply to the Unit 6 combustion turbine EQUI92 or to the auxiliary boiler EQUI91 because they do not have any add-on control equipment. The combustion turbine will have low-NOx burners, but these do not fit the definition of a control device under the CAM definitions at 40 CFR §64.1.

2.7 Cross-State Air Pollution Rule (CSAPR) The new turbine EQUI92 and the existing turbine EQUI1 are subject to CSAPR (also known as the Transport Rule or TR) because they are stationary fossil-fuel-fired combustion turbines that serve, on or after January 1, 2005, a generator with a nameplate capacity of more than 25 MWe producing electricity for sale. Specifically, the facility is subject to the requirements of the TR NOx Annual Program (40 CFR pt. 97 subp. AAAAA) and the TR SO2 Group 2 Trading Program (40 CFR pt. 97, subp. DDDDD) because Minnesota is subject to the TR NOx Annual Trading Program pursuant to 40 CFR §52.38(a)(2) and Minnesota is subject to the requirements of the TR SO2 Group 2 Trading program pursuant to 40 CFR §52.39(c). This permit incorporates the requirements of 40 CFR pt. 97 subps. AAAAA and DDDDD into the permit. EPA issued a memorandum on May 13, 2015 to provide guidance to the regions and the states on incorporating CSAPR requirements into Title V permits. The guidance includes a template to be used in permits, which was added to the existing turbine EQUI1 and to the requirements for the new turbine EQUI91. The template also prescribed the use of a table for each unit that shows how the Permittee will monitor for SO2, NOx, and heat input. These tables were added as Appendix C: Description of TR Monitoring Provisions to the permit. All CSAPR requirements incorporated into the permit adhere to EPA’s guidance and template, with one exception. The permit does not include the requirements from 40 CFR Section 97.406(d) and 40 CFR Section 97.706(d) which address Title V permit revision requirements. These requirements were not


included in the permit because they refer to the permit modifications procedures under 40 CFR pt. 70 that a Permittee may use to make changes to the monitoring provisions table in the permit appendix. However, under Minnesota rules, in order to make changes to the monitoring provisions table the Permittee must follow Minn. R. 7007.1150-1500.

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

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

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

Applicable regulations Rationale

COMG10 (HAP Limits)

Title I limit to avoid NESHAPs National Emission Standards for Hazardous Air Pollutants. Limits of 22.5 tpy of HAPs – Total and 9.0 tpy of HAPs – Single are set on HAPs emissions from EQUI1, EQUI63, and EQUI92 to avoid major source classification under 40 CFR Part 63. Combined PTE from all other units at the source are 0.405 tpy HAPs – Total and 0.375 tpy HAPs – Single, therefore only HAP emissions from the turbine/duct burner Unit 5/2 and turbine Unit 6 are considered in the compliance calculation.

COMG11 (Unit 6 CEMS)

CEMS requirements under 40 CFR pt. 60, pt. 75, and Minn. R.

Requirements for installation, operation, and maintenance for NOx CEMS (NOx and O2 monitors EQUI93 and EQUI94) required by 40 CFR pt. 60 subp. KKKK and Acid Rain Program regulations.

EQUI1 (Unit 5/2 Combustion Turbine)

CSAPR/TR Cross-State Air Pollution Rule or Transport Rule.

EQUI91 (Auxiliary Boiler)

40 CFR pt. 60, subp. Dc Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units. Determination of applicable requirements from rule: · the heat input capacity is 47.6 MMBtu/yr; and · the boiler burns natural gas only

40 CFR pt. 63, subp. DDDDD National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters. Determination of applicable requirements from rule: · the unit was installed in 2015; · the heat input capacity is 47.6 MMBtu/yr; · the boiler burns natural gas only, and belongs in the subcategory

of units designed to burn gas 1 fuel. EQUI92 (Unit 6 Simple Cycle Combustion Turbine)

Acid Rain Program EQUI92 is subject to the U.S. EPA Acid Rain Program codified at 40 CFR pts. 72, 73, and 75. EQUI92 is a utility unit that also is a gas-fired unit and a new unit, as defined in 40 CFR Section 72.2

Limits to avoid major modification under 40 CFR § 52.21(b)(2)

The Permittee has accepted the following limits to avoid the major modification thresholds under NSR: · an annual heat input limit; · limits on annual Start-up Shut-down (SUSD) operating hours; and · combustion of natural gas only.

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

40 CFR pt. 60, subp. KKKK Standards of Performance for Stationary Combustion Turbines. Determination of applicable limits from rule: · combustion of natural gas only.

40 CFR pt. 60, subp. TTTT Standards of Performance for Greenhouse Gas Emissions. Determination of applicable requirements from rule: · combustion of natural gas only.


Subject item*

Applicable regulations Rationale

CSAPR/TR Cross-State Air Pollution Rule or Transport Rule. *Location of the requirement in the permit (e.g., EQUI1, STRU2,etc.).

3. Technical information

3.1 Combustion Turbine Unit 6 Technical Information The combustion turbine EQUI92 will have a maximum output at approximately 215 megawatts (MW) of natural gas fired generating capacity. EQUI92 will operate as a peaking service at no more than a third of its annual capacity on a heat input basis. The turbine will be a simple cycle general electric (GE) 7F5 Series model equipped with low-NOx burners. A simple cycle facility refers to a generation block with one combustion turbine generator. The F-Class model turbine utilizes compressed air and fuel to produce electricity and high temperature exhaust gas. These turbines have fast start capabilities, reaching 150 MW in 10 minutes from a cold start, and operate in at 50 to 100 percent load with faster ramp rates over the load range. The combustion turbine consists of the following equipment in series:

· An inlet air filter; · a compressor, where air is drawn in and compressed; · a combustor, where fuel is mixed with the compressed air and burned; · a power turbine, where the combusted gases expand to rotate a turbine; · an electric generator; and · an evaporative cooler.

Air pollution control equipment for EQUI92 consists of low-NOx burners. These burners are designed to maintain a stoichiometric fuel-to-oxygen ratio by premixing and introducing the minimum amount of oxygen containing air into the combustion chamber allowing the fuel to burn. This lean ratio results in a relatively cool combustion zone and results in less NOx and CO formation.

3.2 Combustion turbine shakedown period The Permittee requested that the limit on SUSD hours of operation to avoid major modification under NSR not apply until after the combustion turbine shakedown period is over. This was requested due to the unpredictable nature of operation during the shakedown period where the turbine may be started up and shut down many times while preparing it for normal operation. This was a cause of some debate, since initially our position was that the limit to avoid NSR had to apply upon initial startup of the turbine, or there had to be some other demonstration that the major modification thresholds were not exceeded during the period including the shakedown. However, the current language about the shakedown period with regards to calculating the net emissions increase is easy to misinterpret. At 40 CFR § 52.21(b)(3)(viii) it says, in reference to the meaning of Net emission increase, that “An increase that results from a physical change at a source occurs when the emissions unit on which construction occurred becomes operational and begins to emit a particular pollutant. Any replacement unit that requires shakedown becomes operational only after a reasonable shakedown period, not to exceed 180 days.” And Replacement Unit is very specifically defined at 40 CFR Section 52.21(b)(33) and it is clear from the definition that the Unit 6 turbine cannot be officially defined as a Replacement Unit. However, if you look at the relevant Federal Register notice, which expounds upon the definition of “Net Emissions Increase”, it includes the following statement:

The definitions of "net emissions increase" specify which increases and decreases in "actual emissions" are contemporaneous. Under the definition in the Part 52 PSD regulations, increases or decreases are contemporaneous with a proposed change only if they occur between two dates: first, the date five years before construction "commences" on the proposed physical or operational change in question and, second, the date the increase from that change "occurs." An increase from a


physical change "occurs" when the affected emissions unit becomes operational and begins to emit a particular pollutant. Any unit that requires shakedown becomes operational only after a reasonable shakedown period (not to exceed 180 days). [45 FR 52698; August 7, 1980]

As discussed previously, the current rules include the word “replacement” before unit at 40 CFR § 52.21(b)(3)(viii). However, a “replacement unit” was not specifically defined in the part 51 regulations until 2002, so either the word “replacement” in the current rule was not supposed to be part of the definition (since it is not used in the Federal Rule excerpt) or “replacement unit” was much more loosely defined. Either way, we have concluded that the intention was that any unit that requires a shakedown period is not considered operational until after the shakedown period ends. Consequently, the shakedown period has been defined in the permit at EQUI92 as the period of time commencing on the date of initial startup and terminating: 1. 180 days after initial startup of the unit; 2. 60 days after achieving maximum production of EQUI92; or 3. Upon submittal of successful compliance test and CEMS certification reports for EQUI92; whichever is earliest. And the statement “This limit does not apply until after the shakedown period ends” has been added to the limitation requirements that were taken to avoid major modification: the limit on heat input and the limit on SUSD hours of operation.

3.3 Calculations of potential to emit and emissions increase analysis

Attachment 1 to this TSD contains detailed spreadsheets and supporting information prepared by the MPCA and the Permittee. Emissions for PM, PM10, PM2.5, NOx, CO, and VOCs were calculated using the worst-case emission rates derived from the GE turbine vendor data including all ambient temperatures and load and operating scenarios. Annual NOx, CO, and VOC emissions include the contribution of emissions from SUSD events. For all other pollutants AP-42 emission factors or global warming potentials from 40 CFR pt. 98 (for greenhouse gases, GHGs) were used for the combustion turbine calculations. GHG emission calculations for the modification also include methane and CO2 emissions from the additional natural gas piping (FUGI15) that will be installed for the new unit and sulfur hexafluoride (SF6) emissions from breaker leakage (FUGI16). Attachment 1 also contains the Title I net emissions increase calculations for this modification. The calculations demonstrate that this modification is not a major modification for PSD. Based on unrestricted emissions the projected emissions from the combustion turbine (EQUI92) and ancillary equipment (FUGI15 and 16) exceed the NSR significant emissions increase thresholds for PM, PM10, PM2.5, NOx, CO, and CO2e. However, Black Dog proposed limits on annual heat consumption and annual start-up and shut-down hours. With these limits, projected emissions for PM2.5, NOx, CO, and CO2e are still over the significant emissions increase thresholds. Therefore, Black Dog conducted a netting analysis for these pollutants. The past-actual-to-future-potential test was applied to EQUI92 and the associated fugitives FUGI15 and FUGI16 including the auxiliary boiler EQUI91 as a contemporaneous increase and the decommissioning of coal-fired boiler EU003 and EU004 as contemporaneous decreases. The selected baseline period for the emissions from the coal-fired boilers was January 2013 to December 2014. For the auxiliary boiler emissions increase the unit’s potential to emit was used. The netting analysis demonstrated a net emissions increase of 0 for PM2.5, NOx, CO, and CO2e. The emissions decreases associated with shutting down the boilers are creditable only if the decrease is contemporaneous with the addition of the new turbine Unit 6. At 40 CFR 52.21(b)(3)(i)(b)(ii) it says “An increase or decrease in actual emissions is contemporaneous with the increase from the particular change only if it occurs between: (a) The date five years before construction on the particular change commences; and (b) The date that the increase from the particular change occurs.” Therefore, construction of the new combustion turbine must commence within 5 years of the decommissioning of the boilers. Both boiler Units 3 and 4 were decommissioned on April 16, 2015, so construction of turbine Unit 6 must commence by April


16, 2020. This should not be a problem for the facility since construction is planned to begin in June of 2016. Nevertheless, there is a requirements at EQUI92 stating that construction must commence by April 16, 2020. An analysis of HAP emissions is included in Attachment 2 to this TSD. With the decommissioning of the coal-fired boilers, the facility would like to be designated as an area source of HAPs upon issuance of permit #03700003-101. The calculations include HAP PTE from all the remaining and future equipment. Total facility uncontrolled HAP emissions are 32.5 tpy HAPs-total and 21.6 tpy HAPs-single. Total facility HAP PTE is 10.9 tpy for HAPs-total and 6.75 tpy for HAPs-single. Despite HAP PTE below the major source thresholds, a limit was set at COMG10 at 9.0 tpy HAP-single and 22.5 tpy HAPs-total for the combined emissions from the combustion turbines and duct burner (EQUI1, EQUI62, and EQUI92). This was done because there was an existing limit to avoid major source for HAP emissions from EQUI1 and EQUI62 along with performance testing requirements for formaldehyde (see TSD for permit #03700003-002 for more information). Performance testing conducted in 2002 for formaldehyde emissions from the Unit 5/2 combustion turbine resulted in formaldehyde emission rates ranging from 15.1 lb/hr at 40% load to 0.045 lb/hr at 100% load. Since this is such a huge range of emission rates, and tracking of HAP emissions from Unit 5/2 based on the emissions rates from performance testing is already automated at Black Dog, the limit and recordkeeping is maintained to ensure that the major source thresholds are not exceeded through excess formaldehyde emissions. Since the PTE for all other HAPs are well below the HAP-single threshold, the limit is set on formaldehyde emissions to demonstrate that HAPs-single emissions are below the major source threshold. The combined PTE from all other units (besides the combustion turbines and duct burner) at the facility is 1.20 tpy for HAPs-total and 0.416 tpy for HAPs-single, therefore the limits to avoid major source are protective of the emissions thresholds even though only emissions from the combustion turbines and duct burner will be tracked.

3.4 Dispersion modeling Full dispersion modeling was completed in 1998 for 24-hour PM10 and in 2002 for annual NOx. Permit #03700003-101 required the Permittee to re-model for any changes that affect the modeled parameters or emission rates for the previous modeling. Therefore, the Permittee conducted an air dispersion modeling analysis to determine whether emissions from EQUI92 would result in maximum ambient concentrations of NOx and PM10 above significant impact levels (SIL). Table 5 summarizes the results of the SIL analysis. Table 6. Summary of EQUI92 SIL analysis Pollutant Averaging Period SIL (ug/m3) Total Modeled Concentration (ug/m3) Percent of Standard

NO2 Annual 1 0.07 6.59% PM10 24-hr 5 0.11 2.17% PM10 Annual 1 0.11 0.62%

The results demonstrate that the ambient impacts from EQUI92 are well below the SIL. Therefore no further modeling or re-modeling requirements are necessary and the parameters used for the analysis are included as permit Appendix B for reference only. Even though the SIL analysis only included the ambient air quality impacts from the new combustion turbine, not the total facility impacts, it is reasonably certain that no further total facility modeling requirements are necessary because of the extreme reduction in emissions after the cessation of coal use: -8,070 tpy PM10 and -13,975 tpy NOx.

3.5 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.


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 7. Monitoring

Subject item* Requirement (rule basis)

Monitoring Discussion

COMG10 (HAP Limits)

HAPs - Total: ≤ 22.5 tpy; HAPs - SIngle: ≤ 9.0 tpy on 12-month rolling sum basis (Limit to avoid NESHAP)

Recordkeeping: Daily records of hours of operation; Monthly calculations of HAPs – Total and HAPs – Single emissions.

The Permittee will calculate the 12-month rolling sum of HAP emissions on a monthly basis using the daily hours of operation records and AP-42 emissions factors for all HAPs except for formaldehyde from EQUI1/EQUI62. For formaldehyde from EQUI1/EQUI62 the Permittee will track the hours spent at each of four loads ranges and use the associated emissions factor from the most recent MPCA-approved performance test to calculate formaldehyde emissions.

EQUI92 (Unit 6 Simple Cycle Combustion Turbine)

Heat input: ≤ 6,458 trillion Btu per year on a 12-month rolling sum basis (limit to avoid major modification under NSR)

Monitoring and Recordkeeping: Continuous monitoring and recordkeeping of natural gas flow rate to the combustion turbine using a flow rate monitor; Monthly recordkeeping of total heat input for the previous month and the 12-month rolling sum heat input.

The Permittee will use a continuous monitoring system to record the natural gas usage of EQUI92. The 12-month rolling sum heat input will be calculated monthly by multiplying the total fuel usage for each month by the energy content of the fuel using either the energy content listed on fuel supplier specifications, or a conservative value of 1020 Btu/scf and summing the data for the previous 12-month period.

SUSD hours of operation: ≤ 260 hours per year on a 12-month rolling sum basis (limit to avoid major modification under NSR)

Recordkeeping: Automated recordkeeping of the start and stop times for start-ups and shut-downs; Monthly recordkeeping of the hours spent in SUSD mode during the calendar month, and the 12-month rolling sum SUSD operating hours.

For each SUSD event the Permittee shall automatically record the start time and stop time of the event. The start time of a startup event occurs when fuel flow to the combustion chamber starts, and ends when the control parameter "L83MECL" reads "TRUE". The start time of a shutdown event begins when the control parameter "L83MECL" reads "FALSE", and ends when fuel flow to the combustion chamber ceases. On a monthly basis the Permittee will use the record of the start and stop times for each SUSD event to calculate the total hours for the previous calendar month and the 12-month rolling sum of SUSD hours by summing the previous 12-months of SUSD hours.


Subject item* Requirement (rule basis)

Monitoring Discussion

Fuel type: Natural gas only (limit to avoid major modification under NSR)

Recordkeeping The Permittee will maintain purchase records of all fuel used by EQUI92 to demonstrate that the turbine combusts natural gas only.

SO2: ≤ 0.060 lbs/MMBTU; NOx: ≤ 4.7 lbs/MWhr (96 ppm by volume at 15% O2) on a 4-hour rolling average basis at < 75% peak load or ambient temperatures < 0°F; NOx: ≤ 0.43 lbs/MWhr (15 ppm by volume at 15% O2) on a 4-hour rolling average basis at ≥ 75% peak load and ambient temperatures ≥ 0°F (NSPS subp. KKKK)

NOx emissions monitoring, Recordkeeping, Performance Testing, Proper Operation and Maintenance

The monitoring, recordkeeping, performance testing, and maintenance according to an operation and maintenance plan as required by 40 CFR pt. 60, subp. KKKK is considered sufficient to ensure compliance with these limits.

CO2: ≤ 120 lbs/MMBTU (NSPS subp. TTTT)

Recordkeeping The recordkeeping requirements under 40 CFR pt. 60, subp. TTTT are considered sufficient to ensure compliance with this limit.

Opacity: ≤ 20% once operating temperatures are reached; SO2: ≤ 0.50 lbs/MMBtu (Minn. R. 7011.2300)

None EQUI92 uses natural gas; therefore, the likelihood of violating either of the emission limits is very small. The Permittee can demonstrate that these units will continue to operate such that emissions are well below the emission limits by only burning natural gas. Design based SO2 PTE for EQUI92, using AP-42, is 0.0034 lb/MMBtu.

*Location of the requirement in the permit (e.g., EQUI1, STRU2,etc.).

3.6 Insignificant activities Xcel Energy - Black Dog Generating Plant has several operations which are classified as insignificant activities under the MPCA’s permitting rules. These are listed in Appendix A to the permit. Insignificant activities related to emissions for coal-related operations were removed with this permit action. No additions to the insignificant activities are included in this modification.

3.7 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.


Another area that deviates from the guidance is in the use of groups where the requirements in the group apply to the members of the group individually. This was done where there were limits that required tracking emissions from a group of units, as for the HAP limits at COMG10 (HAP Limits) or where requirements applied to a group of equipment, as at COMG11 (Unit 6 CEMS).

3.8 Comments received The MPCA plans to issue this draft permit under the provisions of Minn. R. 7007.0750, subp. 7. This rule allows the MPCA to issue permits in two stages. The requirements issued in the first stage - the Stage 1 conditions - are the portions of the draft permit that relate to the construction activities authorized by the draft permit. Examples of Stage 1 conditions include emissions limits, restrictions on hours of operation and the recordkeeping associated with that restriction, and requirements to demonstrate initial compliance. In this draft permit, many Stage 1 conditions are identified as Title I Conditions to avoid classification as a major modification and can be found at the requirements for the new combustion turbine Unit 6, EQUI92. Stage 1 conditions are denoted in the permit by “[Stage 1]” at the beginning of the Stage 1 requirement. This section will be completed after the referenced review periods. Public Notice Period: [start date] – [end date] EPA Review Period: [start date] – [end date]

4. Permit fee assessment

Attachment 3 to this TSD contains the MPCA’s assessment of Application and Additional Points used to determine the permit application fee for this permit action as required by Minn. R. 7002.0019. The permit action includes two permit applications, both received after the effective date of the rule (July 1, 2009). Additional points were applied for a modeling review for the review of the SIL analysis for NOx and PM10, for adding CAIR requirements to the permit, for the addition of NSPS subparts KKKK and TTTT and NESHAP subpart DDDDD to the permit, for review of the netting analysis for PM2.5, NOx, CO, and CO2e, and for addition of a limit to avoid NESHAPs and limits to avoid major modification under NSR.

5. Conclusion Based on the information provided by Xcel Energy - Black Dog Generating Plant the MPCA has reasonable assurance that the proposed operation of the emission facility, as described in the Air Emission Permit No. 03700003-101 and this TSD, will not cause or contribute to a violation of applicable federal regulations and Minnesota Rules. Staff members on permit team: Rachel Yucuis (permit engineer)

Tarik Hanafy (peer reviewer) Marc Severin (compliance) Dan Dietrich (enforcement) Andy Place (compliance) Daniel Dix (modeling) Beckie Olson (permit writing assistant) Laurie O’Brien (administrative support)

TEMPO360 Activities: Permit Change – Major (IND20150002), Permit Change – Minor (IND20150001)

Attachments: 1. PTE summary and emissions increase calculation spreadsheets

2. HAP PTE analysis spreadsheets


3. Points calculator 4. Requirements development report 5. SI detail report

TSD Attachments Attachment 1: PTE summary and emissions increase calculations spreadsheets

Xcel Energy - Black Dog Generating Plant Permit Number: 03700003-101

Xcel Energy Black Dog, Calculations for Permit #03700003 101EQUI92, FUGI15, and FUGI16 Emissions Summary

Description: Description: Description: Description:

Delta ID No.: EU 030 Delta ID No.: FS 018 Delta ID No.: FS 019Tempo ID No.: EQUI92 Tempo ID No.: FUGI15 Tempo ID No.: FUGI16Delta SV ID No: SV 023 Delta SV ID No: NA Delta SV ID No: NA

PollutantCAS #

(if applicable)Max rate(lb/hr)

Uncontrolledtpy

Limitedtpy

Actualtpy

Max rate(lb/hr)

Uncontrolledtpy

Limitedtpy

Actualtpy

Max rate(lb/hr)

Uncontrolledtpy

Limitedtpy

Actualtpy

Max rate(lb/hr)

Uncontrolledtpy

Limitedtpy

Actualtpy

PM 7.1 31.1 10.26 7.1 31.1 10.26PM10 7.1 31.1 10.26 7.1 31.1 10.26PM2.5 7.1 31.1 10.26 7.1 31.1 10.26SO2 7446 09 5 7.6 33.27 10.98 7.6 33.27 10.98NOx 70.0 308.94 103.52 70.0 308.94 103.52VOC 3.3 31.71 22.02 3.3 31.71 22.02CO 630 08 0 35.0 280.05 177.34 35.0 280.05 177.34Pb 7439 92 1 1.10E 03 4.80E 03 1.58E 03 1.10E 03 4.80E 03 1.58E 03H2SO4 9.34E 04 4.09E 03 1.35E 03 9.34E 04 4.09E 03 1.35E 03CO2 261,314 1,144,555 377,703 3.86E 02 1.69E 01 1.69E 01 261,314 1,144,555 377,703CH4 4.92 21.57 7.12 3.67 16.10 16.10 8.6 37.67 23.21N2O 0.49 2.157 0.712 0.49 2.157 0.712SF6 4.38E 04 1.92E 03 1.92E 03 4.38E 04 1.92E 03 1.92E 03CO2e 261,583.81 1,145,737 378,093 91.91 403 403 9.99 43.78 44 261,685.71 1,146,183.4 378,540

Acetaldehyde 75 07 0 8.94E 02 3.91E 01 1.29E 01 8.94E 02 3.91E 01 1.29E 01Acrolein 107 02 8 1.43E 02 6.26E 02 2.07E 02 1.43E 02 6.26E 02 2.07E 02Arsenic 7440 38 2

Benzene 71 43 2 2.68E 02 1.17E 01 3.87E 02 2.68E 02 1.17E 01 3.87E 021,3 Butadiene 106 99 0 9.58E 04 4.20E 03 1.39E 03 9.58E 04 4.20E 03 1.39E 03

Beryllium 7440 41 7Cadmium 7440 43 9

Chromium 7440 47 3Cobalt 7440 48 4

Dichlorobenzene 25321 22 6Ethylbenzene 100 41 4 7.15E 02 3.13E 01 1.03E 01 7.15E 02 3.13E 01 1.03E 01

Formaldehyde 50 00 0 1.59E+00 6.95E+00 2.29E+00 1.59E+00 6.95E+00 2.29E+00Hexane 110 54 3 3.94E+00 1.73E+01 5.70E+00 3.94E+00 1.73E+01 5.70E+00

Manganese 7439 96 5Mercury 7439 97 6

Naphthalene 91 20 3 2.90E 03 1.27E 02 4.20E 03 2.90E 03 1.27E 02 4.20E 03Nickel 7440 02 0

PAH 4.91E 03 2.15E 02 7.10E 03 4.91E 03 2.15E 02 7.10E 03POM

Propylene Oxide 75 56 9 6.48E 02 2.84E 01 9.36E 02 6.48E 02 2.84E 01 9.36E 02Selenium 7782 49 2Toluene 108 88 3 2.90E 01 1.27E+00 4.20E 01 2.90E 01 1.27E+00 4.20E 01Xylenes 1330 20 7 1.43E 01 6.26E 01 2.07E 01 1.43E 01 6.26E 01 2.07E 01

Max Single HAP 3.94E+00 1.73E+01 5.70E+00Total HAPs 6.24 27.32 9.02 6.24 27.32 9.02

GE Simple Cycle Combustion Turbine NG Connections Modification Increase Existing Breaker Fugitives Total Emissions

H:\Xcel Energy Black Dog\TSD Attachments\Major Calculations (TSD Attachments 1 and 2).xlsx[Mod Emissions Summary]

Xcel Energy Black Dog, Calculations for Permit #03700003 101PSD Netting Calculations CH 04a

GE 7F5 Series Simple Cycle Gas Combustion TurbineTable 3, New EU

Pollutant

NG ConnectorsFS 018

PTE(tpy)

NG ConnectorsFS 018

Baseline(tpy)

NG ConnectorsFS 018

Increase(tpy)

Unit 6 CTEU 030

PTE(tpy)

Total Nettpy

PSD SignificantThreshold

tpyThreshold

exceeded?*PM 10.26 10.26 25 noPM10 10.26 10.26 15 noPM2.5 10.26 10.26 10 yesNOx 103.52 103.52 40 yesSO2 10.98 10.98 40 noCO 177.34 177.34 100 yesVOC 22.02 22.02 40 noPb 1.58E 03 1.58E 03 0.6 noH2SO4 1.35E 03 1.35E 03 7.0 noCO2e 6,559 6,156 403 378093 378496 75,000 yes

* see CH 04d form for Net Emissions Increase calculations. The project will not be subject to PSD

Table 4, SummaryTable 1, Modified FS

H:\Xcel Energy Black Dog\TSD Attachments\Major Calculations (TSD Attachments 1 and 2).xlsx[CH 04a]

Xcel Energy Black Dog, Calculations for Permit #03700003 101Total Facility GHG PTE and PSD Netting

Current Total Facility GHG Potential to Emit Summary

PollutantTotal PTE

(tpy)CO2 1.32E+06CH4 24.85N2O 2.58SF6 1.92E 03

Mass Sum tpy 1.32E+06CO2e tpy 1.32E+06

Current Total Facility GHG Potential to Emit Data

Emission Unit ID Unit Name PollutantMax Process

RateProcess Rate

UnitsEmissionFactor1

Emission FactorUnits

Emission Rate(lb/hr)

Uncontrolled Potentialto Emit(ton/yr)

EQUI60 Emergency Engine Generator (Diesel) CO2 16.58 MMBtu/hr 163.00 lb/MMBtu 2,703 11,837EQUI61 Emergency Engine Generator (Diesel) CO2 16.58 MMBtu/hr 163.00 lb/MMBtu 2,703 11,837EQUI90 Fire Pump (Diesel) CO2 1.42 MMBtu/hr 163.00 lb/MMBtu 231 1,014EQUI1 Combustion Turbine (NG) CO2 1917.46 MMBtu/hr 120.00 lb/mmBtu 230,095 1,007,817EQUI62 Supplemental Duct Firing Burners (NG) CO2 509.6 MMBtu/hr 119.00 lb/mmBtu 60,642 265,614EQUI91 Auxiliary Boiler CO2 47.6 mmbtu/hr 117.00 lb/mmbtu 5,569 24,393

EQUI60 Emergency Engine Generator (Diesel) Methane 16.58 MMBtu/hr 6.61E 03 lb/MMBtu 1.10E 01 4.80E 01EQUI61 Emergency Engine Generator (Diesel) Methane 16.58 MMBtu/hr 6.61E 03 lb/MMBtu 1.10E 01 4.80E 01EQUI90 Fire Pump (Diesel) Methane 1.42 MMBtu/hr 6.61E 03 lb/MMBtu 9.39E 03 4.11E 02EQUI1 Combustion Turbine (NG) Methane 1917.46 MMBtu/hr 2.20E 03 lb/mmBtu 4.22E+00 1.85E+01EQUI62 Supplemental Duct Firing Burners (NG) Methane 509.6 MMBtu/hr 2.20E 03 lb/mmBtu 1.12E+00 4.91E+00EQUI91 Auxiliary Boiler CH4 47.6 mmbtu/hr 2.20E 03 lb/mmbtu 1.05E 01 4.59E 01

EQUI60 Emergency Engine Generator (Diesel) Nitrous oxides 16.58 MMBtu/hr 1.32E 03 lb/MMBtu 2.19E 02 9.59E 02EQUI61 Emergency Engine Generator (Diesel) Nitrous oxides 16.58 MMBtu/hr 1.32E 03 lb/MMBtu 2.19E 02 9.59E 02EQUI90 Fire Pump (Diesel) Nitrous oxides 1.42 MMBtu/hr 1.32E 03 lb/MMBtu 1.87E 03 8.21E 03EQUI1 Combustion Turbine (NG) Nitrous oxides 1917.46 MMBtu/hr 2.20E 04 lb/mmBtu 4.22E 01 1.85E+00EQUI62 Supplemental Duct Firing Burners (NG) Nitrous oxides 509.6 MMBtu/hr 2.20E 04 lb/mmBtu 1.12E 01 4.91E 01EQUI91 Auxiliary Boiler N2O 47.6 mmbtu/hr 2.20E 04 lb/mmbtu 1.05E 02 4.59E 02

EQUI60 Emergency Engine Generator (Diesel) CO2e 16.58 MMBtu/hr 163.56 lb/MMBtu 2,712 11,878EQUI61 Emergency Engine Generator (Diesel) CO2e 16.58 MMBtu/hr 163.56 lb/MMBtu 2,712 11,878EQUI90 Fire Pump (Diesel) CO2e 1.42 MMBtu/hr 163.56 lb/MMBtu 232 1,017EQUI1 Combustion Turbine (NG) CO2e 1917.46 MMBtu/hr 120.12 lb/mmBtu 230,326 1,008,829EQUI62 Supplemental Duct Firing Burners (NG) CO2e 509.6 MMBtu/hr 119.12 lb/mmBtu 60,704 265,883EQUI91 Auxiliary Boiler CO2e 47.6 MMBtu/hr 117.12 lb/mmbtu 5,575 24,4181Emission factors from 40 CFR 98 Tables C 1 [78 FR 71950, Nov. 29, 2013] and C 2 [78 FR 71952, Nov. 29, 2013]Global Warming Potentials from 40 CFR 98 Table A 1 [79 FR 73779, Dec. 11, 2014]

GHG Global Warming PotentialsPollutant GWP1

CO2 1CH4 25N2O 298

1Global Warming Potentials from 40 CFR 98 Table A 1 [79 FR 73779, Dec. 11, 2014]

Note for CH 04c: Unit 3 and 4 boilers were not included in the total facility GHG potential to emit as they have been decomissioned for most of theyear, and furthermore both CO2e and mass sum GHG emissions exceed threshold values without their inclusion.

Carbon Dioxide

Methane

Nitrous Oxides

CO2e

H:\Xcel Energy Black Dog\TSD Attachments\Major Calculations (TSD Attachments 1 and 2).xlsx[CH 04c ]

Xcel Energy Black Dog, Calculations for Permit #03700003 101Total Facility GHG PTE and PSD Netting

Xcel Energy Black Dog, Calculations for Permit #03700003 101Current Total Facility Breaker Fugitives (FUGI16)Potential Operating Time

8760 hr

Breaker TypeQuantity of SF6

(lb/breaker)Number ofBreakers

Leakage Rate1

(per year)SF6

(lb/hr)SF6

(tpy)Global Warming

Potential2CO2e

(lb/hr)CO2e(tpy)

SF6 Breakers 128 6 0.5% 4.38E 04 1.92E 03 22,800 10.0 43.8Total SF6: 4.38E 04 1.92E 03 Total CO2e: 10.0 43.8


PSD Netting Calculations CH 04cGE 7F5 Series Simple Cycle Gas Combustion Turbine

Table 6, New EU

Pollutant

NG ConnectorsFUGI15

PTE(tpy)

NG ConnectorsFUGI15Baseline

(tpy)

NG ConnectorsFUGI15Increase

(tpy)

Unit 6 CTEQUI92

PTE(tpy)

Total Nettpy

PSD SignificantThreshold

tpyThreshold

exceeded?*CO2 2.75 2.58 0.17 377703 377703CH4 262.3 246.2 16.1 7.12 23.2N2O 0.71 0.71HFCPFCSF6CO2e 6,559 6,156 403 378093 378496 75,000 yes

1 Breaker leakage rate obtained from: IEC, International Electrotechnical Commission Standard 62271 1, 2004; As referenced in SF6 Leak Rates from High Voltage Circuit Breakers by U.S. EPA.

* see CH 04d form for Net Emissions Increase calculations. The project will not be subject toPSD

Table 4, Modified FS Table 7, Summary

H:\Xcel Energy Black Dog\TSD Attachments\Major Calculations (TSD Attachments 1 and 2).xlsx[CH 04c ]

Xcel Energy Black Dog, Calculations for Permit #03700003 101PSD Netting Calculations CH 04d

GE 7F5 Series Simple Cycle Gas Combustion TurbineCreditable Contemporaneous Emissions Decreases

Column A Column B Column C Column D Column E Column F Column G Column H

a) Emission Source b) Project Name c) Permit Number d) Project Date

e) BaselineActual

Emissions f) Potential to Emitg) Creditable

Decrease h) Rationale

EU003 NR 4/16/2015 30 NA 30 Unit Decommissioned

EU004 NR 4/16/2015 27 NA 27Unit

Decommissioned

57Unit

Decommissioned

Creditable Contemporaneous Emissions Increases



e) BaselineActual

Emissionsf) Potential to

Emitg) Creditable

Increase h) Rationale

EQUI91 Aux Boiler Amend. NA Feb. 2015 NA 1.58 1.58 New Unit

1.58 New Unit

Creditable Contemporaneous Emissions Decreases



e) BaselineActual


Emitg) Creditable


EU003 NR 4/16/2015 2475 NA 2475Unit

Decommissioned

EU004 NR 4/16/2015 3652 NA 3652Unit

Decommissioned

6127Unit

Decommissioned




e) BaselineActual


Emitg) Creditable


EQUI91 Aux Boiler Amend. NA Feb. 2015 NA 6.67 6.67 New Unit

6.67 New Unit

i) Total Creditable Decrease:

Pollutant: PM2.5 Table Number: 1 of 4

Unit 3 and 4Decommissioning


Pollutant: PM2.5 Table Number: 1 of 4

Pollutant: NOx


Table Number: 2 of 4

Pollutant: NOx Table Number: 2 of 4



H:\Xcel Energy Black Dog\TSD Attachments\Major Calculations (TSD Attachments 1 and 2).xlsx[CH 04d ]

Xcel Energy Black Dog, Calculations for Permit #03700003 101PSD Netting Calculations CH 04dCreditable Contemporaneous Emissions Decreases



e) BaselineActual


Emitg) Creditable


EU003 NR 4/16/2015 87 NA 87Unit

Decommissioned

EU004 NR 4/16/2015 126 NA 126Unit

Decommissioned

213Unit

Decommissioned




e) BaselineActual


Emitg) Creditable


EQUI91 Aux Boiler Amend. NA Feb. 2015 17.5 17.5 New Unit

17.5 New Unit

Creditable Contemporaneous Emissions Decreases



e) BaselineActual


Emitg) Creditable


EU003 NR 4/16/2015 625,478 NA 625,478Unit

Decommissioned

EU004 NR 4/16/2015 972,868 NA 972,868Unit

Decommissioned

1,598,346Unit

Decommissioned


Column A Column B Column C Column D Column F Column G Column H


e) BaselineActual


Emitg) Creditable


EQUI91 Aux Boiler Amend. NA Feb. 2015 NA 24362 24,362 New Unit

24,362 New Unit



Pollutant: CO Table Number: 3 of 4



Table Number: 4 of 4



Pollutant: CO2e Table Number: 4 of 4

Pollutant: CO2e

Pollutant: CO Table Number: 3 of 4


Xcel Energy Black Dog, Calculations for Permit #03700003 101PSD Netting Calculations CH 04dNet Emissions Increases

Column A Column B Column C Column D Column F Column G

a) Pollutant b) Emissions Increase

d) CreditableContemporaneousEmissions Decrease

d) CreditableContemporaneousEmissions Increase

e) NetEmissionsIncrease

f) SignificantThresholds forMajor Sources

g) MajorModification?

PM2.5 10.26 56.7 1.58 0 10 no 55.2NOx 103.5 6127 6.67 0 40 no 6120.3CO 177.3 213.3 17.50 0 100 no 195.8

CO2e 378,496 1,598,346 24,362 0 75,000 no 1573984.0


Xcel Energy Black Dog, Calculations for Permit #03700003 101EQUI1 Potential to Emit Calculations

GE 7F5 Series Simple Cycle Gas Combustion TurbinePrimary Fuel Natural Gas

Heat Consumption (LHV)1 2010.5 MMBTU/hr 5811953 MMBtu/yr

Heat Consumption (HHV)1 2233.9 MMBTU/hr 6457726 MMBtu/yrCapacity Factor2 33.00%Primary Fuel Heat Value 1020 BTU/scf

Hours Uncontrolled 8760Hours Limited 2890.81Heat consumption is the maximum value from a range of operating conditions per vendor data, and LHV is assumed to be 90% of HHV2For permitting purposes the capacity factor shown in calculations is converted to an annual fuel usage limit

SUSD Vendor Data Emissions

Pollutant SU FuelSU

(lb/event)SD

(lb/event)NOx Natural Gas 23 21VOC Natural Gas 49 19CO Natural Gas 316 189

Data based on worst case from vendor data, Natural Gas used as a worst case fue

Durations

Event Type Fuel SU SD Total SUSD HoursLimited

Non SUSD Hours

Events per year1 Natural Gas 520 520Hours per event2 Natural Gas 0.3 0.2Total Event Hours Natural Gas 173.3 86.7 260.0 2630.8

1Start up events per year estimated at 520 as per use as peaking turbine2Hours per event specified by vendor dataThese values are used to calculate annual SUSD emissions and are not operating limits.

Annual SUSD Emissions

Pollutant Fuel typeSU

(tpy)SD

(tpy)Total(tpy)

NOx Natural Gas 5.980 5.460 11.440VOC Natural Gas 12.740 4.940 17.680CO Natural Gas 82.160 49.140 131.300

Calculated from lb/event values and number of events per year

Criteria Pollutants

PollutantCombustionTurbine Fuel

Emission Factor1

(lb/MMscf)Emission Factor2

(lb/MMBtu)Emission Rate3

(lb/hr)Uncontrolled Emissions4

(tpy)Uncontrolled Emissions

with SUSD (tpy) Control EfficiencyControlled Emissions

(tpy)

Controlled Emissionswith SUSD

(tpy)

Limited Emissionswith SUSD

(tpy)PM Natural Gas NA NA 7.1 31.1 31.1 0.0% 31.1 31.1 10.3PM10 Natural Gas NA NA 7.1 31.1 31.1 0.0% 31.1 31.1 10.3PM2.5 Natural Gas NA NA 7.1 31.1 31.1 0.0% 31.1 31.1 10.3SOx Natural Gas NA 3.40E 03 7.6 33.3 33.3 0.0% 33.3 33.3 11.0NOx Natural Gas NA NA 70.0 306.6 308.9 0.0% 306.6 308.9 103.5VOC Natural Gas NA NA 3.3 14.5 31.7 0.0% 14.5 31.7 22.0CO Natural Gas NA NA 35.0 153.3 280.1 0.0% 153.3 280.1 177.3Lead Natural Gas 0.0005 4.9E 07 1.10E 03 4.80E 03 4.80E 03 0.0% 4.80E 03 4.80E 03 1.58E 03H2SO4

5 Natural Gas NA NA 9.34E 04 4.09E 03 4.09E 03 0.0% 4.09E 03 4.09E 03 1.35E 031 Lead data is not 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

3Emission rates are worst case determined by vendor data on a pollutant specific basis for all criteria polutants except SOx, lead, and H2SO44Conservatively estimated using maximum hourly emission rate5H2SO4 emission rate equation was determined using EPRI'sEstimating Total Sulfuric Acid Emissions from Stationary Power Plants (03/12) document. See H2SO4 spreadsheet for more details

H2SO4 (lb/hr) = 1.23E 04 * SO2 (lb/hr)

2SO2 emission factor was obtained from AP 42 Section 3.1 "Stationary Gas Turbines" (rev 04/00) Table 3.1 2a as 0.0034 lb/MMBtu when the sulfur content of fuel is unknown. This emission factor assumes 100% S conversion to SO2 for a worst case.

H:\Xcel Energy Black Dog\TSD Attachments\Major Calculations (TSD Attachments 1 and 2).xlsx[EQUI1 PTE]

Xcel Energy Black Dog, Calculations for Permit #03700003 101EQUI1 Potential to Emit Calculations

GE 7F5 Series Simple Cycle Gas Combustion TurbineXcel Energy Black Dog, Calculations for Permit #03700003 101

GHG

Pollutant GWP1Emission Factor2

(kg/MMBtu)Emission Factor

(lb/MMBtu)Emission Rate

(lb/hr)Uncontrolled Emissions

(tpy) Control EfficiencyControlled Emissions

(tpy)Limited Emissions

(tpy)CO2 1 53.06 116.98 261,314 1,144,555 0.00% 1,144,555 377,703CH4 25 1.00E 03 2.20E 03 4.92 21.57 0.00% 21.57 7.12N2O 298 1.00E 04 2.20E 04 0.49 2.16 0.00% 2.16 0.71CO2e 117.10 261,584 1,145,737 0.00% 1,145,737 378,093

1Global Warming Potentials from 40 CFR 98 Table A 1 [79 FR 73779, Dec. 11, 2014]2Emission factors from 40 CFR 98 Tables C 1 [78 FR 71950, Nov. 29, 2013] and C 2 [78 FR 71952, Nov. 29, 2013]

HAPs

Pollutant CAS #Emission Factor1

(lb/MMBtu)Emission Rate

(lb/hr)

UncontrolledEmissions

(tpy) Control EfficiencyControlled Emissions

(tpy)Limited Emissions

(tpy)Acetaldehyde 75 07 0 4.00E 05 8.94E 02 3.91E 01 0.00% 3.91E 01 1.29E 01Acrolein 107 02 8 6.40E 06 1.43E 02 6.26E 02 0.00% 6.26E 02 2.07E 02Arsenic 7440 38 2 0.00%Benzene 71 43 2 1.20E 05 2.68E 02 1.17E 01 0.00% 1.17E 01 3.87E 021,3 Butadiene 106 99 0 4.29E 07 9.58E 04 4.20E 03 0.00% 4.20E 03 1.39E 03Beryllium 7440 41 7 0.00%Cadmium 7440 43 9 0.00%Chromium 7440 47 3 0.00%Cobalt 744 48 4 0.00%Dichlorobenzene 25321 22 6 0.00%Ethylbenzene 100 41 4 3.20E 05 7.15E 02 3.13E 01 0.00% 3.13E 01 1.03E 01Formaldehyde 50 00 0 7.10E 04 1.59E+00 6.95E+00 0.00% 6.95E+00 2.29E+00Hexane 110 54 3 1.76E 03 3.94E+00 1.73E+01 0.00% 1.73E+01 5.70E+00Manganese 7439 96 5 0.00%Mercury 7439 97 6 0.00%Naphthalene 91 20 3 1.30E 06 2.90E 03 1.27E 02 0.00% 1.27E 02 4.20E 03Nickel 7440 02 0 0.00%PAH 2.20E 06 4.91E 03 2.15E 02 0.00% 2.15E 02 7.10E 03POM 0.00%Propylene Oxide 75 56 9 2.90E 05 6.48E 02 2.84E 01 0.00% 2.84E 01 9.36E 02Selenium 7782 49 2 0.00%Toluene 108 88 3 1.30E 04 2.90E 01 1.27E+00 0.00% 1.27E+00 4.20E 01Xylenes 1330 20 7 6.40E 05 1.43E 01 6.26E 01 0.00% 6.26E 01 2.07E 01Total 27.32 27.32 9.021Emission Factors obtained from AP 42 Sec on 3.1 "Sta onary Gas Turbines" (rev 04/00); Table 3.1 3 for all polutants except Hexane which was obtained from Sec on 1.4 "Natural Gas Combus on" (rev07/98); Table 1.4 3.

H:\Xcel Energy Black Dog\TSD Attachments\Major Calculations (TSD Attachments 1 and 2).xlsx[EQUI1 PTE]

Xcel Energy Black Dog, Calculations for Permit #03700003 101Fugitive Sources Potential to Emit

Fugitive Whole Gas Emissions Estimates for Natural Gas (FS 018)

Density: 0.043 lb/scf vol % of CO2 in natural gas 0.93% from natural gas contract gauranteeConversion: 2.2046 lb/kg vol % of CH4 in natural gas 88.60% from natural gas contract gauranteeThe 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

Existing NG Distribution Connections (Baseline)CO2 Methane

0.557 (scf/hr/comp.) 0.023951 (lb/hr/comp.) 6.68E 02 2.93E 01 6.37 27.889.34 (scf/hr/comp.) 0.40162 (lb/hr/comp.) 8.22E 02 3.60E 01 7.83 34.290.772 (scf/hr/comp.) 0.033196 (lb/hr/comp.) 4.32E 03 1.89E 02 0.41 1.800.212 (scf/hr/comp.) 0.009116 (lb/hr/comp.) 1.70E 04 7.43E 04 0.02 0.071.69 (scf/hr/comp.) 0.07267 (lb/hr/comp.) 4.35E 01 1.91E+00 41.46 181.610.27 (scf/hr/comp.) 0.01161 (lb/hr/comp.) 1.19E 03 5.20E 03 0.11 0.50

Total: 5.90E 01 2.58E+00 56.20 246.16Global Warming Potentials: 1 1 25 25

CO2e Emissions: 0.59 2.58 1405.00 6153.90Total CO2e emissions: 1405.59 6156.48

Unit 6 Connections (New Increase)CO2 Methane

0.557 (scf/hr/comp.) 0.023951 (lb/hr/comp.) 6.68E 03 2.93E 02 0.64 2.799.34 (scf/hr/comp.) 0.40162 (lb/hr/comp.) 1.87E 02 8.18E 02 1.78 7.790.772 (scf/hr/comp.) 0.033196 (lb/hr/comp.) 6.17E 04 2.70E 03 0.06 0.261.69 (scf/hr/comp.) 0.07267 (lb/hr/comp.) 1.22E 02 5.33E 02 1.16 5.080.27 (scf/hr/comp.) 0.01161 (lb/hr/comp.) 4.32E 04 1.89E 03 0.04 0.18

Total: 3.86E 02 1.69E 01 3.67 16.10Global Warming Potentials: 1 1 25 25


Facility Total (PTE)CO2 Methane

0.557 (scf/hr/comp.) 0.023951 (lb/hr/comp.) 7.35E 02 3.22E 01 7.00 30.679.34 (scf/hr/comp.) 0.40162 (lb/hr/comp.) 1.01E 01 4.42E 01 9.61 42.080.772 (scf/hr/comp.) 0.033196 (lb/hr/comp.) 4.94E 03 2.16E 02 0.47 2.060.212 (scf/hr/comp.) 0.009116 (lb/hr/comp.) 1.70E 04 7.43E 04 0.02 0.071.69 (scf/hr/comp.) 0.07267 (lb/hr/comp.) 4.47E 01 1.96E+00 42.62 186.690.27 (scf/hr/comp.) 0.01161 (lb/hr/comp.) 1.62E 03 7.09E 03 0.15 0.68

Total: 6.28E 01 2.75E+00 59.87 262.25Global Warming Potentials: 1 1 25 25


1 Population emissions factors were obtained from Table W 7 of Subpart W of 40 CFR Part 98—Default Methane Emission Factors for Natural Gas Distribution, and the emission rates of CH4 and CO2 were calculated using equation W31.

Emission Rate(tpy)


Emission Rate(tpy)Emission Factor1 Emission FactorService

Control Valves 27Regulating Valves 16

Component Type Component Count

Connectingcomponentsserving CT

Block Valves 330

Flanges/Connectors 662Relief Valves 15

Orifice Meters 2

Emission Factor1 Emission Factor


Emission Factor1 Emission FactorService Component Type Component Count

Regulating Valves 14Orifice Meters 2

Emission Rate(tpy)


Emission Rate(tpy)

Connectingcomponentsserving CT

Block Valves 300

Flanges/Connectors 644Relief Valves 11

Service Component Type

22Control Valves


Component Count

Emission Rate(tpy)


Emission Rate(tpy)

Block Valves 30


Connectingcomponentsserving CT Flanges/Connectors 18

Relief Valves 4

2Regulating ValvesControl Valves 5

H:\Xcel Energy Black Dog\TSD Attachments\Major Calculations (TSD Attachments 1 and 2).xlsx[FUGI15 PTE]

Xcel Energy Black Dog, Calculations for Permit #03700003 101Creditable Contemporaneous Emissions Decrease/Increase

Summary of Contemporaneous Decrease and IncreasesEmissions Increase

Pollutant

U3 AEIR 20122013tpy

U3 AEIR 20132014tpy

U3 Selected Baselinetpy

U4 AEIR2012 2013

tpy

U4 AEIR2013 2014

tpyU4 Selected Baseline

tpyEU029 (Aux

Boiler) PTE1 tpyPM 108.45 115.64 115.64 96.09 101.89 101.89 1.58 215.95

PM10 108.45 115.64 115.64 96.09 101.89 101.89 1.58 215.95

PM2.5 28.29 30.17 30.17 25.07 26.58 26.58 1.58 55.17

SO2 1085 1332 1331.50 1756 1725 1756.00 0.13 3087.37

NOx 2331.5 2475 2475.00 3652 3476 3652.00 6.67 6120.33VOC 9.48425 10.3052 10.31 14.1658 14.7393 14.74 0.26 24.78CO 80.653 87.391 87.39 120.745 125.938 125.94 17.5 195.83Pb 8.58E 03 9.50E 03 0.0095 1.29E 02 1.37E 02 0.0137 0.00 0.0232

H2SO4 3.15735 3.874665 3.8747 5.10996 5.01975 5.1100 8.9846

GHG 0.00CO2 566966 620985 620985 912996 966429 966429 24300 1563114.00CH4 62 65 65 93 93 93 11.5 146.77N2O 9.0 9.6 9.6 13.5 13.8 13.8 13.7 9.71SF6

CO2e 571,187 625,478 625,478 919,356 972,868 972,868 24362 1573983.98

Selected Baseline Period Jan 2013 Dec 2014 Jan 2013 Dec 20141 Values obtained from the Aux Boiler Amendment PTE

Unit 3 and 4 Boilers Past Actual Data

PollutantU3 NG

tpyU3 coal

tpy U3 BaselineU4 NG

tpyU4 coal

tpy U4 BaselineU3 NG

tpyU3 coal

tpyU3

BaselineU4 NG

tpyU4 coal

tpyU4

BaselineU3 NG

tpyU3 coal

tpyU3

BaselineU4 NG

tpyU4 coal

tpy U4 BaselinePM 1.76E 05 60.96 60.96 2.33E 05 102.80 102.80 89.38 66.56 155.94 4.87E 05 89.38 89.38 1.52E 05 75.34 75.34 3.39E 05 114.40 114.40PM10 1.76E 05 60.96 60.96 2.33E 05 102.80 102.80 89.38 66.56 155.94 4.87E 05 89.38 89.38 1.52E 05 75.34 75.34 3.39E 05 114.40 114.40PM2.5 9.69E 06 15.90 15.90 1.28E 05 26.82 26.82 23.32 17.36 40.68 2.68E 05 23.32 23.32 8.33E 06 19.65 19.65 1.87E 05 29.84 29.84SO2 0.00 1009.00 1009.00 0.00 1787.00 1787.00 0.00 1161.00 1161.00 0.00 1725.00 1725.00 0.00 1502.00 1502.00 0.00 1725.00 1725.00NOx 0.00 2216.00 2216.00 0.00 3828.00 3828.00 0.00 2447.00 2447.00 0.00 3476.00 3476.00 0.00 2503.00 2503.00 0.00 3476.00 3476.00VOC 0.19 8.71 8.90 0.26 14.67 14.93 0.27 9.79 10.06 0.54 12.87 13.41 0.17 10.38 10.55 0.37 15.70 16.07CO 2.96 72.59 75.55 3.91 122.20 126.11 4.17 81.59 85.76 8.18 107.20 115.38 2.55 86.48 89.03 5.70 130.80 136.50Pb 1.44E 05 8.19E 03 8.20E 03 1.91E 05 1.38E 02 1.38E 02 2.04E 05 8.93E 03 8.95E 03 4.01E 05 1.20E 02 1.20E 02 1.26E 05 1.00E 02 1.00E 02 2.83E 05 1.52E 02 1.53E 02H2SO4

1 0.00 2.94 2.94 0.00 5.20 5.20 0.00 3.38 3.38 0.00 5.02 5.02 0.00 4.37 4.37 0.00 5.02 5.02CO2e 4.34 545700.25 545704.59 5.74 965030.60 965036.34 6.15 596662.58 596668.73 12.08 873663.11 873675.19 3.81 654283.14 654286.95 8.53 1072052.56 1072061.09

CO2 0.00 541670.00 541670.00 0.00 958237.00 958237.00 0.000 592262.00 592262.00 0.000 867754.00 867754.00 0.00 649708.00 649708.00 0.00 1065104.00 1065104.00CH4 0.08 59.02 59.10 0.10 99.50 99.60 0.112 64.44 64.55 0.220 86.53 86.75 0.07 65.51 65.58 0.16 99.50 99.66N2O 0.01 8.57 8.58 0.01 14.45 14.46 0.011 9.36 9.37 0.022 12.57 12.59 0.01 9.86 9.86 0.02 14.97 14.99

1H2SO4 emission rate equation was determined using EPRI'sEstimating Total Sulfuric Acid Emissions from Stationary Power Plants (03/12)document. See H2SO4 spreadsheet for more details.H2SO4 (lb/hr) = 2.91E 03 * SO2 (lb/hr)

GHG Global Warming PotentialsPollutant GWP1

CO2 1CH4 25N2O 298


Emissions Decrease

From 2012 AEIR From 2013 AEIR From 2014 AEIR

H:\Xcel Energy Black Dog\TSD Attachments\Major Calculations (TSD Attachments 1 and 2).xlsx[Netting Data]

Xcel Energy Black Dog, Calculations for Permit #03700003 101Derivation used in equation for H2SO4 emission estimations

Used in Unit 6 CT Future Potentials:

H2SO4 (lb/hr) = K * F1 * SO2 (lb/hr)WhereK = 98.07 / 64.04 = 1.531F1 = 0.00008 1

For a min. Stack Temp of:1076 °F (based on vendor data)

1As a conservative estimate, the F1 value for 1050 ºF was chosen.

Fuel Impact (F1) Factors for a Simple CTStack T, °F F1300 0.055400 0.055500 0.047600 0.022700 0.0055750 0.0027800 0.0013850 0.00071900 0.00039950 0.000221000 0.000131050 0.000081100 0.000051150 0.000031200 0.00002

From EPRI's Estimating Total Sulfuric Acid Emissions from Stationary Power Plants (03/12) document:

*Note: K value is modified to convert from lb SO2/hr to lb H2SO4/hrinstead of ton SO2/yr to lb H2SO4/yr

H2SO4 Emission Rate from GE Simple Cycle Turbine:

H2SO4 (lb/hr) = 1.23E 04 * SO2 (lb/hr)

H:\Xcel Energy Black Dog\TSD Attachments\Major Calculations (TSD Attachments 1 and 2).xlsx[H2SO4 eqn]

Xcel Energy Black Dog, Calculations for Permit #03700003 101Derivation used in equation for H2SO4 emission estimationsXcel Energy Black Dog, Calculations for Permit #03700003 101Derivation used in equation for H2SO4 emission estimationsCoal Units

Used in Unit 3 and 4 Past Actuals:

H2SO4 (lb/hr) = K * F1 * SO2 (lb/hr)WhereK = 98.07 / 64.04 = 1.531F1 = 0.0019 for subbituminous coal

H2SO4 Emission Rate from Units 3 and 4 Boilers:

H2SO4 (lb/hr) = 2.91E 03 * SO2 (lb/hr)

*Note: K value is modified to convert from lb SO2/hr to lb H2SO4/hrinstead of ton SO2/yr to lb H2SO4/yr

H:\Xcel Energy Black Dog\TSD Attachments\Major Calculations (TSD Attachments 1 and 2).xlsx[H2SO4 eqn]

Xcel Energy Black Dog, Calculations for Permit #03700003 101GE Vendor Specification Summary

Performance Data SummaryHeat consumption

(input) 2010.5LHV

MMBtu/hr

EmissionsNOx 70 lb/hrVOC 3.3 lb/hr

CO 35 lb/hrTotal PM 7.1 lb/hr

Exhaust ConditionsFlow rate 1954222 acfm

Temperature 1076 ºF

Startup and Shutdown Data Summary

PollutantMax. lb/event

SUMax. lb/event

SDPM

PM10PM2.5

SOxNOx 23 21VOC 49 19

CO 316 189Lead

H2SO4

hr/event1 0.33 0.171 Duration of SU and SD given by vendor specs for turning gearto 50% baseload, and 50% baseload to fuel shut off as aconservative estimate

H:\Xcel Energy Black Dog\TSD Attachments\Major Calculations (TSD Attachments 1 and 2).xlsx[Vendor Data Used]

Xcel Energy Black Dog, Calculations for Permit #03700003 101Modeling Emission Rates Summary

GE Performance Data Summary GE Startup and Shutdown Data Summary Emission Rates Calculated for Pollutants Not Specified in Vendor DataHeat consumption

(input) 2010.5LHV

MMBtu/hr PollutantMax. lb/event

SUMax. lb/event

SD PollutantCombustionTurbine Fuel

EmissionFactor1

(lb/MMscf)

EmissionFactor2

(lb/MMBtu)

GE EmissionRate3

(lb/hr)

2233.9HHV

MMBtu/hrPM SOx Natural Gas NA 3.40E 03 7.6

Emissions PM10

Total PM 7.1 lb/hr PM2.5

NOx 70 lb/hr SOxVOC 3.3 lb/hr NOx 23 21

CO 35 lb/hr VOC 49 19Exhaust Conditions CO 316 189

Flow rate 1,954,222 acfm min/event1 20.00 10.00Temperature 1076 ºF Exhaust Conditions2

Flow rate (acfm) 1,306,573 1,186,454Temperature (ºF) 900 775

2 For flow rate conversion calculations and temperature information see the graphs and corresponding chart in GE SUSD tab

Maximum Emission Rates Used in Modeling

PollutantMax 1 hr with SU

lb/hrMax 1 hr with SD

lb/hrMax 3 hr with

SU lb/hrMax 3 hr with SD

lb/hrMax 8 hr with

SU lb/hrMax 8 hr with SD

lb/hrMax 24 hr with

SU lb/hrMax 24 hr with

SD lb/hrTotal PM 7.10 7.10 21.30 21.30 56.80 56.80 170.40 170.40

SOx 7.60 7.60 22.79 22.79 60.76 60.76 182.29 182.29NOx 69.67 79.3 209.67 219.33 559.67 569.33 1679.67 1689.33VOC 51.2 21.8 57.80 28.35 74.30 44.85 127.10 97.65

CO 339 218.17 409.33 288.17 584.33 463.17 1144.33 1023.17

Flow rate acfm 1,738,339 1,826,260

Temperature ºF 1017 1026Note: All cases assume a single startup or shutdown event as applicable, and those emissions are averaged with the remaining time attributed to normal operation at 100% loa

1 Duration of SU and SD given by vendor specs for turning gear to 50% baseload, and 50% baseload to fuelshut off as a conservative estimate

2SO2 emission factor was obtained from AP 42 Section 3.1 "Stationary Gas Turbines"(rev 04/00) Table 3.1 2a as 0.0034 lb/MMBtu when the sulfur content of fuel isunknown This emission factor assumes 100% S conversion to SO for a worst case

Exhaust Condition Minimums

H:\Xcel Energy Black Dog\TSD Attachments\Major Calculations (TSD Attachments 1 and 2).xlsx[Modeling]

TSD Attachments Attachment 2: HAP PTE analysis spreadsheets


Xcel Energy Black Dog, Calculations for Permit #03700003 101HAP emissions analysis for all units for reference in setting the limits to avoid major srource under 40 CFR Section 63.2

EQUI90 is limited to 500 hours per yearEQUI1 has limit of 9.0 tpy formaldehyde and 24.0 tpy total HAPs (though PTE when stack testing EF is used is 0.206 tpy formaldehyde and 2.87 tpy total HAPs)EQUI91 is limited to 1500 hours/year

Emission UnitID Pollutant


UncontrolledPotential to Emit

(ton/yr)

LimitedPotential to

Emit (ton/yr)EQUI60/61 Acetaldehyde 3.049E 03 1.336E 02 1.336E 02EQUI60/61 Acrolien 9.535E 04 4.176E 03 4.176E 03EQUI60/61 Benzene 9.390E 02 4.113E 01 4.113E 01EQUI60/61 Formaldehyde 9.547E 03 4.182E 02 4.182E 02EQUI60/61 Naphthalene 1.573E 02 6.890E 02 6.890E 02EQUI60/61 Toluene 3.400E 02 1.489E 01 1.489E 01EQUI60/61 Xylenes 2.335E 02 1.023E 01 1.023E 01EQUI60/61 TOTAL HAPs 1.805E 01 7.907E 01 7.907E 01EQUI60/61 Max Single HAP 9.390E 02 4.113E 01 4.113E 01EQUI90 Acetaldehyde 1.271E 02 3.179E 03 3.179E 03EQUI90 Acrolien 7.667E 04 1.917E 04 1.917E 04EQUI90 1,3 Butadiene 3.241E 04 8.102E 05 8.102E 05EQUI90 Benzene 1.547E 02 3.867E 03 3.867E 03EQUI90 Formaldehyde 1.956E 02 4.890E 03 4.890E 03EQUI90 Naphthalene 1.406E 03 3.514E 04 3.514E 04EQUI90 Toluene 6.780E 03 1.695E 03 1.695E 03EQUI90 Xylenes 4.724E 03 1.181E 03 1.181E 03EQUI90 Total HAPs 6.174E 02 1.544E 02 1.544E 02EQUI90 Max Single HAP 1.956E 02 4.890E 03 4.890E 03EQUI1 Acetaldehyde 7.519E 05 3.294E 04 3.294E 04EQUI1 Acrolein 1.203E 05 5.270E 05 5.270E 05EQUI1 Benzene 2.256E 05 9.881E 05 9.881E 05EQUI1 1,3 Butadiene 8.083E 07 3.541E 06 3.541E 06EQUI1 Ethylbenzene 6.016E 05 2.635E 04 2.635E 04EQUI1 Formaldehyde 4.608E 05 2.018E 04 2.018E 04EQUI1 Naphthalene 2.444E 06 1.070E 05 1.070E 05EQUI1 PAHs 4.136E 06 1.811E 05 1.811E 05EQUI1 Propylene Oxide 5.452E 05 2.388E 04 2.388E 04EQUI1 Toluene 2.444E 04 1.070E 03 1.070E 03EQUI1 Xylenes 1.203E 04 5.270E 04 5.270E 04EQUI1 Total HAP 6.426E 04 2.815E 03 2.815E 03Table continued on next page...

EQUI60 and EQUI61 are limited to 816 hours per year combined and have the same heat input rating and fuel type. Therefore the listed uncontrolled andcontrolled PTE is for each unit individually and limited PTE is for the combined emissions.

Emission Factors obtained from AP 42 Section 3.1 "Stationary Gas Turbines" (rev 04/00); Table 3.1 3 for all polutants except Hexane which was obtained fromSection 1.4 "Natural Gas Combustion" (rev07/98); Table 1.4 3.

Xcel Energy Black Dog, Calculations for Permit #03700003 101HAP emissions summary analysis continued

Emission UnitID Pollutant



(ton/yr)

LimitedPotential to

Emit (ton/yr)

Row Labels Sum ofEmission Rate

(lb/hr)

Sum of UncontrolledPotential to Emit

(ton/yr)

Sum of LimitedPotential to

Emit (ton/yr)Pollutant Emission Rate Uncontrolled

Potential to Emit

LimitedPotential to

Emit (ton/yr)

EQUI1 Max Single HAP 2.444E 04 1.070E 03 1.070E 03 1,3 Butadiene 1.28E 03 4.28E 03 1.47E 03 1,3 Butadiene 3.24E 04 8.10E 05 8.10E 05EQUI62 Cobalt 4.077E 05 1.786E 04 3.058E 05 Acetaldehyde 1.052E 01 4.082E 01 1.460E 01 Acetaldehyde 1.58E 02 1.65E 02 1.65E 02EQUI62 Beryllium 5.096E 06 2.232E 05 3.822E 06 Acrolein 1.603E 02 6.704E 02 2.509E 02 Acrolien 1.72E 03 4.37E 03 4.37E 03EQUI62 Cadmium 2.038E 05 8.928E 05 Arsenic 9.520E 06 4.170E 05 4.170E 05 Arsenic 9.52E 06 4.17E 05 4.17E 05EQUI62 Manganese 2.038E 04 8.928E 04 1.529E 04 Benzene 1.363E 01 5.331E 01 4.544E 01 Benzene 1.10E 01 4.16E 01 4.16E 01EQUI62 Mercury 4.077E 07 1.786E 06 3.058E 07 Beryllium 5.667E 06 2.482E 05 6.324E 06 Beryllium 5.71E 07 2.50E 06 2.50E 06EQUI62 Nickel 1.223E 03 5.357E 03 9.173E 04 Cadmium 7.274E 05 3.186E 04 2.293E 04 Cadmium 5.24E 05 2.29E 04 2.29E 04EQUI62 Chromium 5.606E 04 2.455E 03 4.204E 04 Chromium 6.272E 04 2.747E 03 7.123E 04 Chromium 6.66E 05 2.92E 04 2.92E 04EQUI62 Formaldehyde 1.066E 02 4.669E 02 7.996E 03 Cobalt 4.477E 05 1.961E 04 4.809E 05 Cobalt 4.00E 06 1.75E 05 1.75E 05EQUI62 Hexane 8.993E 01 3.939E+00 6.745E 01 Dichlorobenzene 5.712E 05 2.502E 04 2.502E 04 Dichlorobenzene 5.71E 05 2.50E 04 2.50E 04EQUI62 Lead 2.498E 04 1.094E 03 1.874E 04 Ethylbenzene 7.154E 02 3.134E 01 1.036E 01 Formaldehyde 3.27E 02 6.23E 02 6.23E 02EQUI62 Naphthalene 3.048E 04 1.335E 03 2.286E 04 Formaldehyde 1.629E+00 7.056E+00 2.363E+00 Hexane 8.57E 02 3.75E 01 3.75E 01EQUI62 POMs 4.322E 05 1.893E 04 3.241E 05 Hexane 4.927E+00 2.158E+01 6.748E+00 Manganese 1.81E 05 7.92E 05 7.92E 05EQUI62 Toluene 5.096E 03 2.232E 02 3.822E 03 Lead 2.498E 04 1.094E 03 1.874E 04 Mercury 1.24E 05 5.42E 05 5.42E 05EQUI62 Selenium 1.019E 05 4.464E 05 7.644E 06 Manganese 2.219E 04 9.720E 04 2.321E 04 Naphthalene 1.72E 02 6.94E 02 6.94E 02EQUI62 Total HAP 9.177E 01 4.020E+00 6.883E 01 Mercury 1.278E 05 5.599E 05 5.451E 05 Nickel 1.00E 04 4.38E 04 4.38E 04EQUI62 Max Single HAP 8.993E 01 3.939E+00 6.745E 01 Naphthalene 2.038E 02 8.345E 02 7.382E 02 POM 3.96E 06 1.74E 05 1.74E 05EQUI92 Acetaldehyde 8.936E 02 3.914E 01 1.292E 01 Nickel 1.323E 03 5.795E 03 1.355E 03 Pyrene 2.38E 07 1.04E 06 1.04E 06EQUI92 Acrolein 1.430E 02 6.262E 02 2.066E 02 PAHs 4.919E 03 2.154E 02 7.122E 03 Selenium 1.14E 06 5.00E 06 5.00E 06EQUI92 Benzene 2.681E 02 1.174E 01 3.875E 02 POMs 4.718E 05 2.066E 04 4.976E 05 Toluene 4.09E 02 1.51E 01 1.51E 01EQUI92 1,3 Butadiene 9.583E 04 4.198E 03 1.385E 03 Propylene Oxide 6.484E 02 2.840E 01 9.388E 02 Xylenes 2.81E 02 1.04E 01 1.04E 01EQUI92 Ethylbenzene 7.148E 02 3.131E 01 1.033E 01 Pyrene 2.380E 07 1.042E 06 1.042E 06 Total HAP 0.3321 1.2 1.2EQUI92 Formaldehyde 1.586E+00 6.947E+00 2.292E+00 Selenium 1.133E 05 4.964E 05 1.265E 05 Max Single HAP 0.1095 0.4156 0.4156EQUI92 Hexane 3.942E+00 1.727E+01 5.698E+00 Toluene 3.367E 01 1.447E+00 5.760E 01EQUI92 Naphthalene 2.904E 03 1.272E 02 4.198E 03 Xylenes 1.712E 01 7.302E 01 3.106E 01EQUI92 PAH 4.915E 03 2.153E 02 7.103E 03 Grand Total 7.488E+00 3.254E+01 1.091E+01EQUI92 Propylene Oxide 6.478E 02 2.837E 01 9.364E 02 Max Single HAP 4.93E+00 2.16E+01 6.75E+00EQUI92 Toluene 2.904E 01 1.272E+00 4.198E 01EQUI92 Xylenes 1.430E 01 6.262E 01 2.066E 01EQUI92 Total HAP 6.237E+00 2.732E+01 9.015E+00EQUI92 Max Single HAP 3.942E+00 1.727E+01 5.698E+00EQUI91 Arsenic 9.520E 06 4.170E 05 4.170E 05EQUI91 Benzene 9.996E 05 4.378E 04 4.378E 04EQUI91 Beryllium 5.712E 07 2.502E 06 2.502E 06EQUI91 Cadmium 5.236E 05 2.293E 04 2.293E 04EQUI91 Chromium 6.664E 05 2.919E 04 2.919E 04EQUI91 Cobalt 3.998E 06 1.751E 05 1.751E 05EQUI91 Dichlorobenzene 5.712E 05 2.502E 04 2.502E 04EQUI91 Formaldehyde 3.570E 03 1.564E 02 1.564E 02EQUI91 Hexane 8.568E 02 3.753E 01 3.753E 01EQUI91 Manganese 1.809E 05 7.923E 05 7.923E 05EQUI91 Mercury 1.238E 05 5.421E 05 5.421E 05EQUI91 Naphthalene 3.046E 05 1.334E 04 1.334E 04EQUI91 Nickel 9.996E 05 4.378E 04 4.378E 04EQUI91 POM 3.960E 06 1.735E 05 1.735E 05EQUI91 Pyrene 2.380E 07 1.042E 06 1.042E 06EQUI91 Selenium 1.142E 06 5.004E 06 5.004E 06EQUI91 Toluene 1.618E 04 7.089E 04 7.089E 04EQUI91 Total HAPS 8.987E 02 3.936E 01 3.936E 01EQUI91 Max Single HAP 0.086 0.375 0.375

Total HAP 32.54 10.91

HAP Emissions for all units by pollutant HAP emissions for all units excluding EQUI1, EQUI62, and EQUI92

Xcel Energy Black Dog, Calculations for Permit #03700003 101HAP PTE for emergency generatorsEQUI60 Emergency Engine Generator (Diesel) 121.000 gal/hr

Emergency Engine Generator (Diesel) 16.577 MMBtu/hrEmergency Engine Generator (Diesel) 2598 HP

EQUI61 Emergency Engine Generator (Diesel) 121.000 gal/hrEmergency Engine Generator (Diesel) 16.577 MMBtu/hr

EQUI90 Fire Pump 1.425 MMBtu/hrFire Pump 208 HP

Emission Unit ID Unit Name PollutantMax Process

RateProcess Rate

Units

Emission Factor Emission

Factor Units Emission Factor Source

EmissionRate

(lb/hr)


(ton/yr)

PollutionControl

Efficiency (%)

ControlledPotential to Emit (ton/yr)

LimitedPotential to Emit (ton/yr)

EQUI60 Emergency Engine Generator (Diesel) Acetaldehyde 121.00 MMBtu/hr 2.52E-05 lb/MMBtu AP-42 Table 3.4-3 (10/96) 0.0030 0.0134 0 0.0134 0.0012EQUI60 Emergency Engine Generator (Diesel) Acrolien 121.00 MMBtu/hr 7.88E-06 lb/MMBtu AP-42 Table 3.4-3 (10/96) 0.0010 0.0042 0 0.0042 0.0004EQUI60 Emergency Engine Generator (Diesel) Benzene 121.00 MMBtu/hr 7.76E-04 lb/MMBtu AP-42 Table 3.4-3 (10/96) 0.0939 0.4113 0 0.4113 0.0383EQUI60 Emergency Engine Generator (Diesel) Formaldehyde 121.00 MMBtu/hr 7.89E-05 lb/MMBtu AP-42 Table 3.4-3 (10/96) 0.0095 0.0418 0 0.0418 0.0039EQUI60 Emergency Engine Generator (Diesel) Naphthalene 121.00 MMBtu/hr 1.30E-04 lb/MMBtu AP-42 Table 3.4-4 (10/96) 0.0157 0.0689 0 0.0689 0.0064EQUI60 Emergency Engine Generator (Diesel) Toluene 121.00 MMBtu/hr 2.81E-04 lb/MMBtu AP-42 Table 3.4-3 (10/96) 0.0340 0.1489 0 0.1489 0.0139EQUI60 Emergency Engine Generator (Diesel) Xylenes 121.00 MMBtu/hr 1.93E-04 lb/MMBtu AP-42 Table 3.4-3 (10/96) 0.0234 0.1023 0 0.1023 0.0095EQUI60 Emergency Engine Generator (Diesel) TOTAL HAPs 0.1805 0.7907 0 0.7907 0.0737

EQUI61 Emergency Engine Generator (Diese Acetaldehyde 121.00 MMBtu/hr 2.52E-05 lb/MMBtu AP-42 Table 3.4-3 (10/96) 0.0030 0.0134 0 0.0134 0.0012EQUI61 Emergency Engine Generator (Diese Acrolien 121.00 MMBtu/hr 7.88E-06 lb/MMBtu AP-42 Table 3.4-3 (10/96) 0.0010 0.0042 0 0.0042 0.0004EQUI61 Emergency Engine Generator (Diese Benzene 121.00 MMBtu/hr 7.76E-04 lb/MMBtu AP-42 Table 3.4-3 (10/96) 0.0939 0.4113 0 0.4113 0.0383EQUI61 Emergency Engine Generator (Diese Formaldehyde 121.00 MMBtu/hr 7.89E-05 lb/MMBtu AP-42 Table 3.4-3 (10/96) 0.0095 0.0418 0 0.0418 0.0039EQUI61 Emergency Engine Generator (Diese Naphthalene 121.00 MMBtu/hr 1.30E-04 lb/MMBtu AP-42 Table 3.4-4 (10/96) 0.0157 0.0689 0 0.0689 0.0064EQUI61 Emergency Engine Generator (Diese Toluene 121.00 MMBtu/hr 2.81E-04 lb/MMBtu AP-42 Table 3.4-3 (10/96) 0.0340 0.1489 0 0.1489 0.0139EQUI61 Emergency Engine Generator (Diese Xylenes 121.00 MMBtu/hr 1.93E-04 lb/MMBtu AP-42 Table 3.4-3 (10/96) 0.0234 0.1023 0 0.1023 0.0095EQUI61 Emergency Engine Generator (Diese TOTAL HAPs 0.1805 0.7907 0 0.7907 0.0737

EQUI90 Fire Pump (Diesel) Acetaldehyde 16.58 MMBTU/hr 7.67E-04 lb/MMBtu AP-42 Table3.3-2 (10/96) 1.27E-02 3.18E-03 0 0.0032EQUI90 Fire Pump (Diesel) Acrolien 16.58 MMBTU/hr 4.63E-05 lb/MMBtu AP-42 Table3.3-2 (10/96) 7.67E-04 1.92E-04 0 0.0002EQUI90 Fire Pump (Diesel) 1,3-Butadiene 16.58 MMBTU/hr 1.96E-05 lb/MMBtu AP-42 Table3.3-2 (10/96) 3.24E-04 8.10E-05 0 0.0001EQUI90 Fire Pump (Diesel) Benzene 16.58 MMBTU/hr 9.33E-04 lb/MMBtu AP-42 Table3.3-2 (10/96) 1.55E-02 3.87E-03 0 0.0039EQUI90 Fire Pump (Diesel) Formaldehyde 16.58 MMBTU/hr 1.18E-03 lb/MMBtu AP-42 Table3.3-2 (10/96) 1.96E-02 4.89E-03 0 0.0049EQUI90 Fire Pump (Diesel) Naphthalene 16.58 MMBTU/hr 8.48E-05 lb/MMBtu AP-42 Table3.3-2 (10/96) 1.41E-03 3.51E-04 0 0.0004EQUI90 Fire Pump (Diesel) Toluene 16.58 MMBTU/hr 4.09E-04 lb/MMBtu AP-42 Table3.3-2 (10/96) 6.78E-03 1.69E-03 0 0.0017EQUI90 Fire Pump (Diesel) Xylenes 16.58 MMBTU/hr 2.85E-04 lb/MMBtu AP-42 Table3.3-2 (10/96) 4.72E-03 1.18E-03 0 0.0012EQUI90 Fire Pump (Diesel) Total HAPs 0.0617 1.54E-02 0 0.0154

Xcel Energy Black Dog, Calculations for Permit #03700003 101HAP PTE for Combustion Turbine Unit 5/2 (EQUI1)

Combustion Turbine (NG) 1.88 MMCF/hrCombustion Turbine (NG) 1020.00 Btu/cfCombustion Turbine (NG) 1917.46 MMBtu/hrCombustion Turbine (NG) 83960.00 lb/hr 0.0034

PollutantMax Process

RateProcess Rate

Units

EmissionFactor Emission

Factor Units Emission Factor SourceEmission Rate

(lb/hr)Uncontrolled Potential to Emit

(ton/yr)

PollutionControl

Efficiency(%)

ControlledPotential to

Emit(ton/yr)

Acetaldehyde 1.88 MMBtu/hr 4.00E 05 lb/mmBtu AP 42 Table 3.1 3 (4/00) 7.52E 05 3.29E 04 3.29E 04Acrolein 1.88 MMBtu/hr 6.40E 06 lb/mmBtu AP 42 Table 3.1 3 (4/00) 1.20E 05 5.27E 05 5.27E 05Benzene 1.88 MMBtu/hr 1.20E 05 lb/mmBtu AP 42 Table 3.1 3 (4/00) 2.26E 05 9.88E 05 9.88E 051,3 Butadiene 1.88 MMBtu/hr 4.30E 07 lb/mmBtu AP 42 Table 3.1 3 (4/00) 8.08E 07 3.54E 06 3.54E 06Ethylbenzene 1.88 MMBtu/hr 3.20E 05 lb/mmBtu AP 42 Table 3.1 3 (4/00) 6.02E 05 2.63E 04 2.63E 04Formaldehyde 1.88 MMBtu/hr 2.45E 05 lb/mmBtu Test Results from 6/27/02 4.61E 05 2.02E 04 2.02E 04Naphthalene 1.88 MMBtu/hr 1.30E 06 lb/mmBtu AP 42 Table 3.1 3 (4/00) 2.44E 06 1.07E 05 1.07E 05PAHs 1.88 MMBtu/hr 2.20E 06 lb/mmBtu AP 42 Table 3.1 3 (4/00) 4.14E 06 1.81E 05 1.81E 05Propylene Oxide 1.88 MMBtu/hr 2.90E 05 lb/mmBtu AP 42 Table 3.1 3 (4/00) 5.45E 05 2.39E 04 2.39E 04Toluene 1.88 MMBtu/hr 1.30E 04 lb/mmBtu AP 42 Table 3.1 3 (4/00) 2.44E 04 1.07E 03 1.07E 03Xylenes 1.88 MMBtu/hr 6.40E 05 lb/mmBtu AP 42 Table 3.1 3 (4/00) 1.20E 04 5.27E 04 5.27E 04Total HAP 6.43E 04 2.81E 03 2.81E 03

Xcel Energy Black Dog, Calculations for Permit #03700003 101HAP PTE for EQUI62 Duct Burner

EQUI62 Supplemental Duct Firing Burners (NG) 0.5 MMCF/hrSupplemental Duct Firing Burners (NG) 1020.0 Btu/cfSupplemental Duct Firing Burners (NG) 509.6 MMBTU/hr

Xcel Energy Black Dog Generating PlantPotential to Emit

EmissionUnit ID Unit Name Pollutant

Max ProcessRate

ProcessRateUnits

EmissionFactor Emission Factor

Units Emission Factor SourceEmission Rate

(lb/hr)

UncontrolledPotential to

Emit(ton/yr)

PollutionControl

Efficiency (%)

ControlledPotential toEmit (ton/yr)

LimitedPotentialto Emit(ton/yr)

EQUI62 Supplemental Duct Firing Burners (NG) Benzene 509.6 MMBtu/hr 8.00E 01 lb/10^12 Btu EPRI Emissions Factor Handbook Table 3 1 (4/02) 4.08E 04 1.79E 03 1.79E 03 3.06E 04EQUI62 Supplemental Duct Firing Burners (NG) Arsenic 509.6 MMBtu/hr 2.30E 01 lb/10^12 Btu EPRI Emissions Factor Handbook Table 3 1 (4/02) 1.17E 04 5.13E 04 5.13E 04 8.79E 05EQUI62 Supplemental Duct Firing Burners (NG) Cobalt 509.6 MMBtu/hr 8.00E 02 lb/10^12 Btu EPRI Emissions Factor Handbook Table 3 1 (4/02) 4.08E 05 1.79E 04 1.79E 04 3.06E 05EQUI62 Supplemental Duct Firing Burners (NG) Beryllium 509.6 MMBtu/hr 1.00E 02 lb/10^12 Btu EPRI Emissions Factor Handbook Table 3 1 (4/02) 5.10E 06 2.23E 05 2.23E 05 3.82E 06EQUI62 Supplemental Duct Firing Burners (NG) Cadmium 509.6 MMBtu/hr 4.00E 02 lb/10^12 Btu EPRI Emissions Factor Handbook Table 3 1 (4/02) 2.04E 05 8.93E 05 8.93E 05 1.53E 05EQUI62 Supplemental Duct Firing Burners (NG) Manganese 509.6 MMBtu/hr 4.00E 01 lb/10^12 Btu EPRI Emissions Factor Handbook Table 3 1 (4/02) 2.04E 04 8.93E 04 8.93E 04 1.53E 04EQUI62 Supplemental Duct Firing Burners (NG) Mercury 509.6 MMBtu/hr 8.00E 04 lb/10^12 Btu EPRI Emissions Factor Handbook Table 3 1 (4/02) 4.08E 07 1.79E 06 1.79E 06 3.06E 07EQUI62 Supplemental Duct Firing Burners (NG) Nickel 509.6 MMBtu/hr 2.40E+00 lb/10^12 Btu EPRI Emissions Factor Handbook Table 3 1 (4/02) 1.22E 03 5.36E 03 5.36E 03 9.17E 04EQUI62 Supplemental Duct Firing Burners (NG) Chromium 509.6 MMBtu/hr 1.10E+00 lb/10^12 Btu EPRI Emissions Factor Handbook Table 3 1 (4/02) 5.61E 04 2.46E 03 2.46E 03 4.20E 04EQUI62 Supplemental Duct Firing Burners (NG) Formaldehyde 509.6 MMBtu/hr 2.09E 05 lb/mmBtu Test Data from 6/27/02 1.07E 02 4.67E 02 4.67E 02 8.00E 03EQUI62 Supplemental Duct Firing Burners (NG) Hexane 0.5 MMCF/hr 1.80E+00 lb/MMCF AP 42 Table 1.4 3 (7/98) 8.99E 01 3.94E+00 3.94E+00 6.74E 01EQUI62 Supplemental Duct Firing Burners (NG) Lead 0.5 MMCF/hr 5.00E 04 lb/MMCF EPRI Emissions Factor Handbook Table 3 1 (4/02) 2.50E 04 1.09E 03 1.09E 03 1.87E 04EQUI62 Supplemental Duct Firing Burners (NG) Naphthalene 0.5 MMCF/hr 6.10E 04 lb/MMCF AP 42 Table 1.4 3 (7/98) 3.05E 04 1.33E 03 1.33E 03 2.29E 04EQUI62 Supplemental Duct Firing Burners (NG) POMs 0.5 MMCF/hr 8.65E 05 lb/MMCF AP 42 Table 1.4 3 (7/98) sum of all POMs listed 4.32E 05 1.89E 04 1.89E 04 3.24E 05EQUI62 Supplemental Duct Firing Burners (NG) Toluene 509.6 MMBtu/hr 1.00E+01 lb/10^12 Btu EPRI Emissions Factor Handbook Table 3 1 (4/02) 5.10E 03 2.23E 02 2.23E 02 3.82E 03EQUI62 Supplemental Duct Firing Burners (NG) Selenium 509.6 MMBtu/hr 2.00E 02 lb/10^12 Btu EPRI Emissions Factor Handbook Table 3 1 (4/02) 1.02E 05 4.46E 05 4.46E 05 7.64E 06EQUI62 Supplemental Duct Firing Burners (NG) TOTAL HAPs 9.18E 01 4.02E+00 4.02E+00 6.89E 01

Xcel Energy Black Dog, Calculations for Permit #03700003 101

EQUI91 Auxiliary Boiler 47600.000 cf/hr0.048 mmcf/hr47.6 mmbtu/hr1000 Btu/cf

EmissionUnit ID Unit Name Pollutant

MaxProcess

Rate

ProcessRateUnits

[3]Emission

FactorEmission

Factor Units Emission Factor Source

EmissionRate

(lb/hr)


(ton/yr)

PollutionControl

Efficiency (%)

ControlledPotential to Emit

(ton/yr) Existing Permit LimitEQUI91 Auxiliary Boiler CO 0.048 mmcf/hr 8.40E+01 lb/mmcf AP 42 Table 1.4 1(7/98) 4.00E+00 1.75E+01 1.75E+01 NoneEQUI91 Auxiliary Boiler NOx 0.048 mmcf/hr 3.20E+01 lb/mmcf AP 42 Table 1.4 1(7/98) 1.52E+00 6.67E+00 6.67E+00EQUI91 Auxiliary Boiler Chromium 0.048 mmcf/hr 1.40E 03 lb/mmcf AP 42 Table 1.4 4 (7/98) 6.66E 05 2.92E 04 2.92E 04EQUI91 Auxiliary Boiler Cobalt 0.048 mmcf/hr 8.40E 05 lb/mmcf AP 42 Table 1.4 4 (7/98) 4.00E 06 1.75E 05 1.75E 05EQUI91 Auxiliary Boiler Dichlorobenzene 0.048 mmcf/hr 1.20E 03 lb/mmcf AP 42 Table 1.4 3 (7/98) 5.71E 05 2.50E 04 2.50E 04EQUI91 Auxiliary Boiler Formaldehyde 0.048 mmcf/hr 7.50E 02 lb/mmcf AP 42 Table 1.4 3 (7/98) 3.57E 03 1.56E 02 1.56E 02EQUI91 Auxiliary Boiler Hexane 0.048 mmcf/hr 1.80E+00 lb/mmcf AP 42 Table 1.4 3 (7/98) 8.57E 02 3.75E 01 3.75E 01EQUI91 Auxiliary Boiler Manganese 0.048 mmcf/hr 3.80E 04 lb/mmcf AP 42 Table 1.4 4 (7/98) 1.81E 05 7.92E 05 7.92E 05EQUI91 Auxiliary Boiler Mercury 0.048 mmcf/hr 2.60E 04 lb/mmcf AP 42 Table 1.4 4 (7/98) 1.24E 05 5.42E 05 5.42E 05EQUI91 Auxiliary Boiler Naphthalene 0.048 mmcf/hr 6.40E 04 lb/mmcf AP 42 Table 1.4 3 (7/98) 3.05E 05 1.33E 04 1.33E 04EQUI91 Auxiliary Boiler Nickel 0.048 mmcf/hr 2.10E 03 lb/mmcf AP 42 Table 1.4 4 (7/98) 1.00E 04 4.38E 04 4.38E 04EQUI91 Auxiliary Boiler POM 0.048 mmcf/hr 8.32E 05 lb/mmcf AP 42 Table 1.4 3 (7/98) 3.96E 06 1.73E 05 1.73E 05EQUI91 Auxiliary Boiler Pyrene 0.048 mmcf/hr 5.00E 06 lb/mmcf AP 42 Table 1.4 3 (7/98) 2.38E 07 1.04E 06 1.04E 06EQUI91 Auxiliary Boiler Selenium 0.048 mmcf/hr 2.40E 05 lb/mmcf AP 42 Table 1.4 4 (7/98) 1.14E 06 5.00E 06 5.00E 06EQUI91 Auxiliary Boiler Toluene 0.048 mmcf/hr 3.40E 03 lb/mmcf AP 42 Table 1.4 3 (7/98) 1.62E 04 7.09E 04 7.09E 04EQUI91 Auxiliary Boiler Total HAPS 8.97E 02 3.93E 01 3.93E 01

GWP GWP SourceUnlimitedCO2e (tpy)

EQUI91 Auxiliary Boiler CO2 47.6 mmbtu/hr 1.17E+02 lb/mmbtu 40 CFR 98, Subpart C, Table C 1 5.56E+03 2.43E+04 2.43E+04 1 40 CFR 98, Subpart A, Table A 1 24,337.22EQUI91 Auxiliary Boiler CH4 47.6 mmbtu/hr 2.20E 03 lb/mmbtu 40 CFR 98, Subpart C, Table C 2 1.05E 01 4.59E 01 4.59E 01 25 40 CFR 98, Subpart A, Table A 1 11.5

Greenhouse Gas Emissions

Major Calculations (TSD Attachments 1 and 2).xlsxPrinted on: 4/13/2016 at 3:06 PM

Page 6 of 6EQUI91 PTE

TSD Attachments Attachment 3: Points Calculator


Points Calculator

1) AI ID No.: 2351 Total Points 1442) Facility Name: Xcel Energy - Black Dog Generating Plant3) Small business? y/n? n 4) Air Project Tracking Numbers (including 5384, 5127 5) Date of each Application Received: 10/15/2015, 3/2/20156) Final Permit No. 03700003-1017) Permit Staff Rachel Yucuis

Total TotalApplication Type Air Project Tempo Activity ID Qty. Points Points Additionl Cost DetailsAdministrative Amendment 1 0 -$ Minor Amendment 5127 IND2015002 1 4 4 1,140.00$ Applicability Request 10 0 -$ Moderate Amendment 15 0 -$ Major Amendment 5384 IND2015001 1 25 25 7,125.00$ Individual State Permit (not reissuance) 50 0 -$ Individual Part 70 Permit (not reissuance) 75 0 -$

Additional PointsModeling Review 5384 IND2015001 1 15 15 4,275.00$ Annual NOx, annual and hourly PM10, NAAQS

BACT Review 15 0 -$ LAER Review 15 0 -$ CAIR/Part 75 CEM analysis 5384 IND2015001 1 10 10 2,850.00$ NSPS Review 5384 IND2015001 2 10 20 5,700.00$ KKKK, TTTTNESHAP Review 5127 IND2015002 1 10 10 2,850.00$ DDDDDCase-by-case MACT Review 20 0 -$ Netting 5384 IND2015001 4 10 40 11,400.00$ PM2.5, NOx, CO, CO2eLimits to remain below threshold 5384 IND2015001 2 10 20 5,700.00$ NESHAPs, major mod under NSRPlantwide Applicability Limit (PAL) 20 0 -$ AERA review 15 0 -$ Variance request under 7000.7000 35 0 -$ Confidentiality request under 7000.1300 2 0 -$ EAW reviewPart 4410.4300, subparts 18, item A; and 29 15 0 -$ Part 4410.4300, subparts 8, items A & B; 10, items A to C; 16, items A & D; 17, items A to C & E to G; and 18, items B & C

35 0 -$

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

70 0 -$

Add'l Points 115

NOTES:

(DQ Points)

TSD Attachments Attachment 4: Requirements development report


TFAC 02 03700003 Permit Appendices: This permit contains appendices as listed in the permit Table of Contents. The Permittee shall comply with all requirements contained in Appendices A (Insignificant Activities and General Applicable Requirements), C (Transport Rule (TR) Trading Program Title V Requirements), and D (Acid Rain Applications and Retired Unit Exemptions). Modeling parameters in Appendix B (Parameters used for SIL analysis) are included for reference only. [Minn. R. 7007.0800, subp. 2]

TFAC 02 03700003 PERMIT SHIELD: Subject to the limitations in Minn. R. 7007.1800, compliance with the conditions of this permit shall be deemed compliance with the specific provision of the applicable requirement identified in the permit as the 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, any person (including the Permittee) may also use other credible evidence to establish compliance or noncompliance with applicable requirements. This permit shall not alter or affect the liability of the Permittee for any violation of applicable requirements prior to or at the time of permit issuance. [Minn. R. 7007.1800, (A)(2)]

TFAC 02 03700003 These requirements apply if a reasonable possibility (RP) as defined in 40 CFR Section 52.21(r)(6)(vi) exists that a proposed project, analyzed using the actual-to-projected-actual (ATPA) test (either by itself or as part of the hybrid test at Section 52.21(a)(2)(iv)(f)) and found to not be part of a major modification, may result in a significant emissions increase (SEI). If the ATPA test is not used for the project, or if there is no RP that the proposed project could result in a SEI, these requirements do not apply to that project. The Permittee is only subject to the Preconstruction Documentation requirement for a project where a RP occurs only within the meaning 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 that a proposed project could result in a SEI, a permit amendment, recordkeeping, or notification may still be required by Minn. R. 7007.1150 - 7007.1500. [Minn. R. 7007.0800, subp. 2, Title I Condition: 40 CFR 52.21(r)(6) and Minn. R. 7007.3000]

TFAC 02 03700003 Preconstruction Documentation -- Before beginning actual construction on a project, the Permittee shall document the following: 1. Project description 2. Identification of any emission unit whose emissions of an NSR pollutant could be affected 3. Pre-change potential emissions of any affected existing emission unit, and the projected post-change potential 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 any regulated NSR pollutant, including the baseline actual emissions, the projected actual emissions, the amount of emissions excluded due to increases not associated with the modification and that the emission unit could have accommodated during the baseline period, an explanation of why the amounts were excluded, and any creditable contemporaneous increases and decreases that were considered in the determination. The Permittee shall maintain records of this documentation. [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]

TFAC 02 03700003 The Permittee shall monitor the actual emissions of any regulated NSR pollutant that could increase as a result of the project and that were analyzed using the ATPA test, and the potential emissions of any regulated NSR pollutant that could increase as a result of the project and that were analyzed using potential emissions in the hybrid test. The Permittee shall calculate and maintain a record of the sum of the actual and potential (if the hybrid test was used in the analysis) emissions of the regulated pollutant, in tons per year on a calendar year basis, for a period of 5 years following resumption of regular operations after the change, or for a period of 10 years following resumption of regular operations after the change if the project increases the design capacity of or potential to emit of any unit associated with the project. [Minn. R. 7007.0800, subps. 4-5, Title I Condition: 40 CFR 52.21(r)(6) and Minn. R. 7007.3000]

TFAC 02 03700003 Before 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 under Preconstruction Documentation, above) to the Agency. [Minn. R. 7007.0800, subps. 4-5, Title I Condition: 40 CFR 52.21(r)(6)(ii) and Minn. R. 7007.3000]

TFAC 02 03700003 For any project which includes any EUSGU, the Permittee must submit an annual report to the Agency, within 60 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 with the 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 preconstruction projection, if that is the case. [Minn. R. 7007.0800, subps. 4-5, Title I Condition: 40 CFR 52.21(r)(6)and Minn. R. 7007.3000]

TFAC 02 03700003 For any project which does not include any EUSGU, the Permittee must submit a report to the Agency if the annual summed (actual, plus potential used in hybrid test) emissions differ from the preconstruction projection and 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 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) for each pollutant for which the preconstruction projection and significant emissions rate is exceeded. c. Any other information, such as an explanation as to why the summed emissions differ from the preconstruction projection. [Minn. R. 7007.0800, subps. 4-5, Title I Condition: 40 CFR 52.21(r)(6)and Minn. R. 7007.3000]

TFAC 02 03700003 The 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 be demonstrated upon written request by the MPCA. [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]

TFAC 02 03700003 Circumvention: Do not install or use a device or means that conceals or dilutes emissions, which would otherwise violate a federal or state air pollution control rule, without reducing the total amount of pollutant emitted. [Minn. R. 7011.0020]

TFAC 02 03700003 Air Pollution Control Equipment: Operate all pollution control equipment whenever the corresponding process equipment and emission units are operated. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2]

TFAC 02 03700003 Operation and Maintenance Plan: Retain at the stationary source an operation and maintenance plan for all air pollution control equipment. At a minimum, the O & M plan shall identify all air pollution control equipment and control practices and shall include a preventative maintenance program for the equipment and practices, a description of (the minimum but not necessarily the only) corrective actions to be taken to restore the equipment and practices to proper operation to meet applicable permit conditions, a description of the employee training program for proper operation and maintenance of the control equipment and practices, and the records kept to demonstrate plan implementation. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 16(J)]

TFAC 02 03700003 Operation Changes: In any shutdown, breakdown, or deviation the Permittee shall immediately take all practical steps to modify operations to reduce the emission of any regulated air pollutant. The Commissioner may require feasible and practical modifications in the operation to reduce emissions of air pollutants. No emissions units that have an unreasonable shutdown or breakdown frequency of process or control equipment shall be permitted to operate. [Minn. R. 7019.1000, subp. 4]

TFAC 02 03700003 Fugitive Emissions: Do not cause or permit the handling, use, transporting, or storage of any material in a manner which may allow avoidable amounts of particulate matter to become airborne. Comply with all other requirements listed in Minn. R. 7011.0150. [Minn. R. 7011.0150]

TFAC 02 03700003 Noise: The Permittee shall comply with the noise standards set forth in Minn. R. 7030.0010 to 7030.0080 at all times during the operation of any emission units. This is a state only requirement and is not enforceable by the EPA Administrator or citizens under the Clean Air Act. [Minn. R. 7030.0010-7030.0080]

TFAC 02 03700003 Inspections: The Permittee shall comply with the inspection procedures and requirements as found in Minn. R. 7007.0800, subp. 9(A). [Minn. R. 7007.0800, subp. 9(A)]

TFAC 02 03700003 The Permittee shall comply with the General Conditions listed in Minn. R. 7007.0800, subp. 16. [Minn. R. 7007.0800, subp. 16]

TFAC 02 03700003 Performance Testing: Conduct all performance tests in accordance with Minn. R. ch. 7017 unless otherwise noted in this permit. [Minn. R. ch. 7017]

TFAC 02 03700003 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 Performance Test Report: due 45 days after each Performance Test Performance Test Report - Microfiche Copy: due 105 days after each Performance Test The Notification, Test Plan, and Test Report may be submitted in an alternative format as allowed by Minn. R. 7017.2018. [Minn. R. 7017.2018, Minn. R. 7017.2030, subps. 1-4, Minn. R. 7017.2035, subps. 1-2]

TFAC 02 03700003 Limits set as a result of a performance test (conducted before or after permit issuance) apply until superseded as stated in the MPCA's Notice of Compliance letter granting preliminary approval. Preliminary approval is based on 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. [Minn. R. 7017.2025, subp. 3]

TFAC 02 03700003 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 any corrective action that resulted. The Permittee shall include the calibration frequencies, procedures, and manufacturer's specifications (if applicable) in the Operations and Maintenance Plan. Any requirements applying to continuous emission monitors are listed separately in this permit. [Minn. R. 7007.0800, subp. 4(D)]

TFAC 02 03700003 Operation of Monitoring Equipment: Unless noted elsewhere in this permit, monitoring a process or control equipment connected to that process is not necessary during periods when the process is shutdown, or during checks of the monitoring systems, such as calibration checks and zero and span adjustments. If monitoring records are required, they should reflect any such periods of process shutdown or checks of the monitoring system. [Minn. R. 7007.0800, subp. 4(D)]

TFAC 02 03700003 The Permittee shall submit an application for permit reissuance : Due 180 calendar days before Permit Expiration Date. [Minn. R. 7007.0400, subp. 2]

TFAC 02 03700003 Recordkeeping: Retain all records at the stationary source, unless otherwise specified within this permit, for a period of five (5) years from the date of monitoring, sample, measurement, or report. Records which must be retained at this location include all calibration and maintenance records, all original recordings for continuous monitoring instrumentation, and copies of all reports required by the permit. Records must conform to the requirements listed in Minn. R. 7007.0800, subp. 5(A). [Minn. R. 7007.0800, subp. 5(C)]

TFAC 02 03700003 Recordkeeping: 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 records of the emissions resulting from those changes. [Minn. R. 7007.0800, subp. 5(B)]

TFAC 02 03700003 If the Permittee determines that no permit amendment or notification is required prior to making a change, the Permittee must retain records of all calculations required under Minn. R. 7007.1200. For expiring permits, these records 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 operation and may be kept at the stationary source or office of the stationary source for all other years. The records may be maintained in either electronic or paper format. [Minn. R. 7007.1200, subp. 4]

TFAC 02 03700003 Shutdown Notifications: Notify the Commissioner at least 24 hours in advance of a planned shutdown of any control equipment or process equipment if the shutdown would cause any increase in the emissions of any regulated air pollutant. If the owner or operator does not have advance knowledge of the shutdown, notification shall be made to the Commissioner as soon as possible after the shutdown. However, notification is not required in 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 shutdown and the estimated duration. The owner or operator shall notify the Commissioner when the shutdown is over. [Minn. R. 7019.1000, subp. 3]

TFAC 02 03700003 Breakdown Notifications: Notify the Commissioner within 24 hours of a breakdown of more than one hour duration of any control equipment or process equipment if the breakdown causes any increase in the emissions of any regulated air pollutant. The 24-hour time period starts when the breakdown was discovered or reasonably should have been discovered by the owner or operator. However, notification is not required in the circumstances outlined in Items A, B and C of Minn. R. 7019.1000, subp. 2. At the time of notification or as soon as possible thereafter, the owner or operator shall inform the Commissioner of the cause of the breakdown and the estimated duration. The owner or operator shall notify the Commissioner when the breakdown is over. [Minn. R. 7019.1000, subp. 2]

TFAC 02 03700003 Notification of Deviations Endangering Human Health or the Environment: As soon as possible after discovery, notify the Commissioner or the state duty officer, either orally or by facsimile, of any deviation from permit conditions which could endanger human health or the environment. [Minn. R. 7019.1000, subp. 1]

TFAC 02 03700003 Notification of Deviations Endangering Human Health or the Environment Report: Within 2 working days of discovery, notify the Commissioner in writing of any deviation from permit conditions which could endanger human 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 5. steps taken or planned to reduce, eliminate, and prevent reoccurrence of the deviation. [Minn. R. 7019.1000, subp. 1]

TFAC 02 03700003 The Permittee shall submit a semiannual deviations report : Due semiannually, by the 30th of January and July The first semiannual report submitted by the Permittee shall cover the calendar half-year in which the permit is issued. The first report of each calendar year covers January 1 - June 30. The second report of each calendar year covers July 1 - December 31. If no deviations have occurred, the Permittee shall submit the report stating no deviations. [Minn. R. 7007.0800, subp. 6(A)(2)]

TFAC 02 03700003 Application for Permit Amendment: If a permit amendment is needed, submit an application in accordance with the requirements of Minn. R. 7007.1150 through Minn. R. 7007.1500. Submittal dates vary, depending on the type of amendment needed. Upon adoption of a new or amended federal applicable requirement, and if there are more than 3 years remaining in the permit term, the Permittee shall file an application for an amendment within nine months of promulgation of the applicable requirement, pursuant to Minn. R. 7007.0400, subp. 3. [Minn. R. 7007.0400, subp. 3, Minn. R. 7007.1150 - 7007.1500]

TFAC 02 03700003 Extension Requests: The Permittee may apply for an Administrative Amendment to extend a deadline in a permit 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. 63 are examples of deadlines for which the MPCA does not have authority to grant extensions and therefore do not meet the requirements of Minn. R. 7007.1400, subp. 1(H). [Minn. R. 7007.1400, subp. 1(H)]

TFAC 02 03700003 The Permittee shall submit a compliance certification : Due annually, by the 31st of January (for the previous calendar year). The Permittee shall submit this to the Commissioner on a form approved by the Commissioner. This report covers all deviations experienced during the calendar year. [Minn. R. 7007.0800, subp. 6(C)]

TFAC 02 03700003 Emission Inventory Report: due on or before April 1 of each calendar year following permit issuance, to be submitted on a form approved by the Commissioner. [Minn. R. 7019.3000-7019.3100]

TFAC 02 03700003 Emission Fees: due 30 days after receipt of an MPCA bill. [Minn. R. 7002.0005-7002.0095] TFAC 02 03700003 The Permittee must submit a Risk Management Plan (RMP) under 40 CFR pt. 68. Each owner or

operator of a stationary source, at which a regulated substance is present above a threshold quantity in a process, shall design and implement an accidental release prevention program. A full update and resubmission of the RMP is required at least once every five years. The five-year anniversary date is reset whenever the Permittee fully updates and resubmits their RMP. The last full update of the RMP was completed on March 27, 2012. Submit RMPs to the Risk Management Plan Reporting Center, P.O. Box 1515, Lanham-Seabrook, Maryland 20703-1515. RMP information may be obtained at http://www.epa.gov/swercepp or by calling 1-800-424-9346. [40 CFR pt. 68]

TFAC 02 03700003 The Permittee shall not have engines that meet section (1)(iii) under the definition of Nonroad Engine at 40 CFR Section 1068.30 in one location within the stationary source for more than 12 consecutive months. A location is any single site at a building, structure, facility, or installation. Any engine, or engines, that replaces an engine at a location and that is intended to perform the same or similar function as the engine it replaced will be included in calculating the consecutive time period. [40 CFR 1068.30]

TFAC 02 03700003 For a nonroad engine that is excluded from any requirements of 40 CFR Part 1068 because it is a stationary engine, the Permittee may not move it or install it in any mobile equipment, except as allowed by the provisions of 40 CFR Part 1068. The Permittee may not circumvent or attempt to circumvent the residence-time requirements of Section (2)(iii) of the Nonroad Engine definition at 40 CFR Section 1068.30. [40 CFR 1068.101(b)(3)]

TFAC 02 03700003 The Permittee shall conduct an inventory of all engines on-site that meet section (1)(iii) under the definition of Nonroad Engine at 40 CFR Section 1068.30, once each calendar quarter; inventories shall not take place in consecutive months. This applies to nonroad engines that are owned by the Permittee, or rented and operated by the Permittee, or brought onsite and operated by a vendor or contractor. The inventory shall include the following: 1) Date that the nonroad engine is inventoried. 2) Identification number. 3) Function of the nonroad engine (e.g. compressor, welder). 4) Location of the engine within the stationary source. 5) Statement that the nonroad engine has not been located in a single location for 12 consecutive months, and movement between locations has not been for purposes of circumvention of residence time requirements of section (2)(iii) under the definition of Nonroad Engine at 40 CFR Section 1068.30. [40 CFR 1068.30(nonrd engn)(1)(iii), Minn. R. 7007.0800, subps. 4-5]

TFAC 02 03700003 A nonroad engine ceases to be a nonroad engine and becomes a new stationary engine if: 1. At any time, it meets the criteria specified in section (2)(iii) under the definition of Nonroad Engine in 40 CFR Section 1068.30. For example, a portable generator engine ceases to be a nonroad engine if it is used or will be used in a single specific location for 12 months or longer. If the Administrator or the Permitting authority determines that an engine will be or has been used in a single specific location for 12 months or longer, it ceased to be a nonroad engine when it was placed in that location. OR 2. It is otherwise regulated by a federal New Source Performance Standard promulgated under section 111 of the Clean Air Act (42 U.S.C. 7411). [40 CFR 1068.31(e)]

TFAC 02 03700003 The Permittee shall submit excess emission/downtime report : Due by 30 days after the end of each calendar quarter following permit issuance. Submit Deviations Reporting Form DRF-1 as amended. The EER shall indicate all periods of monitor bypass and all periods of exceedances of the limit including exceedances allowed by an applicable standard, i.e. during startup, shutdown, and malfunctions. The EER must be submitted even if there were no excess emissions, downtime or bypasses during the quarter. [40 CFR 60.7(c), Minn. R. 7017.1110, subp. 1-2]

COMG 01 GP001 Operating Hours <= 816 hours per year 12-month rolling sum for the combined operating hours of EQUI60 and EQUI61. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2) and Minn. R. 7007.3000]

COMG 01 GP001 Nitrogen Oxides <= 35.3 tons per year 12-month rolling sum for the combined NOx emissions from EQUI60 and EQUI61. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2) and Minn. R. 7007.3000]

COMG 01 GP001 Operating Hours: Daily Recordkeeping: For each engine, on each day that the engine is operated, record the number of hours operated. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2) and Minn. R. 7007.3000]

COMG 01 GP001 Daily Recordkeeping: Each day that the engine is operated, record the number of operating hours that were non-emergency and were not routine testing and maintenance. [Minn. R. 7007.0800, subps. 4-5]

COMG 01 GP001 Operating Hours: Monthly Recordkeeping: By the 20th day of each month, the Permittee shall calculate and record the following: 1) The total Operating Hours for the previous calendar month using the daily records. 2) The 12 month rolling sum Operating Hours for the previous 12 month period ("OO" in the equation below) by summing the monthly Operating Hours data for the previous 12 months. 3) The total non-emergency, non-routine testing and maintenance hours operated during the previous calendar month. 4) The total non-emergency, non-routine testing and maintenance hours operated during the previous 12 calendar months. [Minn. R. 7007.0800, subps. 4-5]

COMG 01 GP001 Nitrogen Oxides: Monthly Recordkeeping: By the 20th day of each month, the Permittee shall calculate and record the 12-month rolling sum Nitrogen Oxides using the following equation: NOx = OO x EF x 16.58 x 0.0005 Where: NOx = the 12-month rolling sum NOx emissions (tons/year) OO = the 12-month rolling sum operating hours, calculated as described above (hours/year) . EF = the most current emission factor published in AP-42 (4.41 lb/MMBtu at the time of permit issuance) 16.58 = engine capacity (MMBtu/hour) 0.0005 = 1 ton/2000 lb. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

COMG 03 GP005 The CEMS requirements listed below outline the typical standards of 40 CFR pt. 60 and pt. 75 when combined with Minn. R. Additional monitoring requirements may also apply to the facility based on this combination of standards and it is the responsibility of the Facility to meet all applicable requirements. [Minn. R. 7007.0800, subp. 2]

COMG 03 GP005 Continuous Operation: CEMS must be operated and data recorded during all periods of emission unit operation including periods of emission unit start-up, shutdown, or malfunction except for periods of acceptable monitor downtime. This requirement applies whether or not a numerical emission limit applies during these periods. A CEMS must not be bypassed except in emergencies where failure to bypass would endanger human health, safety, or plant equipment. Acceptable monitor downtime includes reasonable periods as listed in Items A, B, C and D of Minn. R. 7017.1090, subp. 2. [40 CFR 60.13(e), Minn. R. 7017.1090, subp. 1]

COMG 03 GP005 CEMS Monitor Design: Each CEMS shall be designed to complete a minimum of one cycle of sampling, analyzing, and data recording in each 15-minute period. [40 CFR 60.13(e)(2), 40 CFR 75.10(d)(1)]

COMG 03 GP005 CEMS Certification/Recertification Test: due 120 days after the first calendar quarter following CEMS installation/reinstallation. [40 CFR 60.13(b), Minn. R. 7017.1050, subp. 1]

COMG 03 GP005 CEMS Certification/Recertification: The Permittee shall ensure that each CEMS required by 40 CFR pt. 75 meets the initial certification requirements of 40 CFR section 75.20 and shall ensure that all applicable initial certification tests under 40 CFR Section 75.20(c) are completed by the deadlines specified in 40 CFR Section 75.4 and prior to use in the Acid Rain Program. In addition, whenever the Permittee installs a continuous emission monitoring system in order to meet the requirements of Sections 75.11 through 75.18, where no continuous emission monitoring system was previously installed, initial certification is required. The Permittee shall certify all CEMS required by the Acid Rain Program in accordance with 40 CFR pt. 75, Appendix A, Section 6. [40 CFR 75.20, 40 CFR pt. 75, Appendix A(Sect 6)]

COMG 03 GP005 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. [40 CFR 60.7(a)(5), 40 CFR 75.61, Minn. R. 7017.1060, subp. 1-3, Minn. R. 7017.1080, subp. 1-4]

COMG 03 GP005 Certification Application: The Permittee shall apply for certification of each continuous emission monitor used under the Acid Rain Program. The Permittee shall submit the certification application in accordance with 40 CFR Section 75.60 and each complete certification application shall include the information specified in 40 CFR Section 75.63. [40 CFR 75.20(a)(2), 40 CFR 75.60(b)(1), 40 CFR 75.63]

COMG 03 GP005 CEMS QA/QC: The Permittee is subject to the performance specifications listed in 40 CFR pt. 60, Appendix B and shall operate, calibrate, and maintain each CEMS according to the QA/QC procedures in 40 CFR pt. 60, Appendix F as amended and maintain a written QA/QC program available in a form suitable for inspection. (Note 40 CFR Part 75 has a standard regarding this requirement as well). [40 CFR 60.13(a), 40 CFR pt. 60, Appendix F]

COMG 03 GP005 CEMS QA/QC: The Permittee shall operate, calibrate, and maintain each CEMS according to the QA/QC procedures in 40 CFR pt. 75, Appendix B as amended. (Note 40 CFR Part 60 has a standard regarding this requirement as well). [40 CFR 75.21]

COMG 03 GP005 40 CFR Pt. 75 Monitoring Data: Hourly averages shall be computed using at least one data point in each fifteen minute quadrant of an hour, where the unit combusted fuel during that quadrant of an hour. Notwithstanding this requirement, an hourly average may be computed from at least two data points separated by a minimum of 15 minutes (where the unit operates for more than one quadrant of an hour) if data are unavailable as a result of the performance of calibration, quality assurance, or preventive maintenance activities pursuant to 40 CFR Section 75.21 and pt. 75, Appendix B, or backups of data from the data acquisition and handling system, or recertification, pursuant to Section 75.20. The owner or operator shall use all valid measurements or data points collected during an hour to calculate the hourly averages. All data points collected during an hour shall be, to the extent practicable, evenly spaced over the hour. (Note 40 CFR pt. 60 has a standard regarding this requirement) [40 CFR 75.10(d)(1)]

COMG 03 GP005 NSPS Monitoring Data: Reduce all NSPS-required continuous monitoring systems other than COMS data to 1-hour averages, in accordance with 40 CFR Section 60.13(h). (Note 40 CFR pt. 75 has a standard regarding this requirement as well) [40 CFR 60.13(h), Minn. R. 7017.1160, subps. 1-2]

COMG 03 GP005 CEMS Daily Calibration Drift Test: Check the zero (low level value between 0 and 20 percent of span value) and span (50 to 100 percent of span value) calibration drifts at least once daily. The zero and span must, at a minimum, be adjusted whenever the drift exceeds two times the limit specified in 40 CFR pt. 60, Appendix B. 40 CFR pt. 60, Appendix F, Section 4.3.1 shall be used to determine out-of-control periods for CEMS. [40 CFR 60.13(d)(1), 40 CFR pt. 60, Appendix F, 4.1, Minn. R. 7017.1170, subp. 3]

COMG 03 GP005 Daily Calibration Error (CE) Test: Conduct daily CE testing of each gas monitoring system according to the procedures in Section 6.3.1 of 40 CFR pt. 75, Appendix A and of each flow monitoring system according to the procedures in Section 6.3.2 of Appendix A. (Note 40 CFR pt. 60 has a standard regarding this requirement as well.). [40 CFR pt. 75, Appendix B (Sect 2.1)]

COMG 03 GP005 40 CFR pt. 60 Cylinder Gas Audit (CGA): The Permittee shall conduct a cylinder gas audit : Due by the end of each three of four calendar quarters but no more than three quarters in succession. A CGA is not required during any calendar quarter in which a RATA was performed. [40 CFR pt. 60, Appendix F, 5.1.2, Minn. R. 7017.1170, subp. 4]

COMG 03 GP005 40 CFR pt. 75 Linearity and Leak Check Test: The Permittee shall conduct linearity and leak check : Due by the end of each QA operating quarter (calendar quarter in which there are at least 168 unit operating hours) in accordance with procedures in 40 CFR pt. 75, Appendix B, Sections 2.2.1 and 2.2.2, and Appendix A, Section 6.2. Perform a leak check at least once during each QA operating quarter. [40 CFR pt. 75, Appendix B, 2.2]

COMG 03 GP005 40 CFR pt. 75 CEMS Relative Accuracy Test Audit (RATA): The Permittee shall conduct CEMS relative accuracy test audit (RATA) : Due semiannually. In accordance with 40 CFR pt. 75, Appendix B, this means once every two successive QA operating quarters (calendar quarter in which there are at least 168 unit operating hours) on all CEMS required by the Acid Rain Program. Relative accuracy test audits may be performed annually (i.e., once every four successive QA operating quarters, rather than once every two successive QA operating quarters) if any of the conditions listed in 40 CFR pt. 75, Appendix B, Sections 2.3.1.2(a) through 2.3.1.2(i) are met. [40 CFR pt. 75, Appendix B, 2.3]

COMG 03 GP005 40 CFR pt. 60 CEMS Relative Accuracy Test Audit (RATA): The Permittee shall conduct a relative accuracy test audit : Due one of each four calendar quarters. [40 CFR pt. 60, Appendix F, 5.1.1]

COMG 03 GP005 RATA Notification: due 30 days before CEMS Relative Accuracy Test Audit (RATA). [Minn. R. 7017.1180, subp. 2]

COMG 03 GP005 Cylinder Gas Audit (CGA) Results Summary: due 30 days after end of each calendar quarter in which a CGA was conducted. [Minn. R. 7017.1180, subp. 1]

COMG 03 GP005 The Permittee shall submit a Linearity Test Results Summary: due 30 days after end of each calendar quarter in which a Linearity Test was conducted. [Minn. R. 7017.1180, subp. 4]

COMG 03 GP005 Relative Accuracy Test Audit (RATA) Results Summary: due 30 days after end of each calendar quarter in which a RATA was conducted. [Minn. R. 7017.1180, subp. 3]

COMG 03 GP005 Recordkeeping: The Permittee 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 least three (3) years from the date of each record. The file shall contain all information required by 40 CFR Section 75.57. [40 CFR 75.57]

COMG 03 GP005 Recordkeeping: The Permittee shall retain records of all CEMS monitoring data and support information for a period of five years from the date of the monitoring sample, measurement or report. Records shall be kept at the source. [40 CFR 60.7(f), Minn. R. 7017.1130]

COMG 03 GP005 Quarterly Reports: Electronically report the data and information in 40 CFR Section 75.64 (a), (b), and (c) to the Administrator quarterly. [40 CFR 75.64]

COMG 08 GP007 Nitrogen Oxides <= 4.5 parts per million 3-hour block average by volume on a dry basis at 15% oxygen. This limit applies at all times under all operating conditions, except during startup, shutdown, and malfunction. Each calendar day is composed of eight consecutive 3-hour time blocks starting at midnight. Each 3-hour block average is determined by averaging all 1-minute averages during operation other than startup, shutdown, or malfunction, to determine the 15-minute average. The 15-minute averages are averaged to produce a 1-hour average, and the 1-hour averages are used to calculate the 3-hour block average. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

COMG 08 GP007 Nitrogen Oxides <= 100 parts per million by volume on a dry basis at 15% oxygen. This limit applies only during startup, shutdown, and malfunction. If the startup process ends with a failed start, then a NOx ppmvd concentration limit does not apply. However, NOx mass emissions (lb/hr) during a failed start are included in the 12-month rolling sum NOx emissions calculations. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

COMG 08 GP007 Nitrogen Oxides <= 305 tons per year 12-month rolling sum. This limit applies at all times under all operating conditions, including startup, shutdown, and malfunction. [Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

COMG 08 GP007 Carbon Monoxide <= 25 parts per million 3-hour block average by volume on a dry basis at 15% oxygen, during operation of EQUI1 (combustion turbine) except during startup, shutdown, or malfunction, and EQUI62 is in operation during the same 3-hour time block. Each calendar day is composed of eight consecutive 3-hour time blocks starting at midnight. Each 3-hour block average is determined by averaging all 1-minute averages during operation other than startup, shutdown, or malfunction, to determine the 15-minute average. The 15-minute averages are averaged to produce a 1-hour average, and the 1-hour averages are used to calculate the 3-hour block average. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

COMG 08 GP007 Carbon Monoxide <= 18 parts per million 3-hour block average by volume on a dry basis at 15% oxygen during operation of EQUI1 (combustion turbine) except during startup, shutdown, or malfunction, and EQUI62 is not in operation during the same 3-hour time block. Each calendar day is composed of eight consecutive 3-hour time blocks starting at midnight. Each 3-hour block average is determined by averaging all 1-minute averages during operation other than startup, shutdown, or malfunction, to determine the 15-minute average. The 15-minute averages are averaged to produce a 1-hour average, and the 1-hour averages are used to calculate the 3-hour block average. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

COMG 08 GP007 Carbon Monoxide <= 400 tons per year 12-month rolling sum. This limit applies at all times under all operating conditions, except during startup and shutdown. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

COMG 08 GP007 PM < 10 micron <= 29.4 pounds per hour 3-hour average. This limit applies at all times under all operating conditions, except during startup, shutdown, or malfunction. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

COMG 08 GP007 Volatile Organic Compounds <= 0.0073 pounds per million Btu heat input when EQUI1 (combustion turbine) is operating at or above 70% load, with or without EQUI62 in operation. When EQUI62 is operating simultaneously with EQUI1, the limit is equal to 17.7 lb/hr; the calculated potential to emit of EQUI1 and EQUI62 combined is approximately 17.5 lb/hr. When only EQUI1 is operating, the limit is equal to 14.0 lb/hr; the calculated potential to emit of EQUI1 is approximately 4.8 lb/hr. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

COMG 08 GP007 Startup, Shutdown, and Malfunction have the same meanings as in 40 CFR Section 60.2; see Subject Item EQUI1 for further startup/shutdown definitions for the combustion turbine. For any emission limit not applicable during startup and shutdown, that limit does not apply: 1. during the initial 180 minutes after fuel combustion commences in the combustion turbine if the steam turbine-generator was offline for less than 12 hours; 2. during the initial 300 minutes after fuel combustion commences in the combustion turbine if the steam turbine-generator was offline for 12 to 60 hours; 3. during the initial 480 minutes after fuel combustion commences in the combustion turbine if the steam turbine-generator was offline for more than 60 hours; 4. during the final 120 minutes of turbine fuel combustion. Steam turbine-generator online operation of less than 60 minutes duration shall be considered offline for startup determination purposes and is not included in items 1, 2, and 3 above. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

COMG 08 GP007 The Permittee shall operate and maintain TREA37 at all times that EQUI1 and/or EQUI62 is in operation. The Permittee shall document periods of non-operation of the control equipment. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2, Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000, Title I Condition: 40 CFR 52.21(k)(modeling)& Minn. R. 7007.3000]

COMG 08 GP007 Measure or calculate SO2 and CO2 emission rates for EQUI1 and EQUI62 in accordance with 40 CFR pt. 75. [40 CFR 75.10, Minn. R. 7007.0800, subp. 4]

COMG 08 GP007 Emissions Monitoring: The owner or operator shall use a NOx CEMS to measure NOx emissions from STRU32. Additional monitoring requirements are also located at Subject Item COMG3. [40 CFR 60.334(c), 40 CFR 72.9(b), Minn. R. 7011.0560, Minn. R. 7011.2350, Minn. R. 7017.1010, subp. 1, Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

COMG 08 GP007 Emissions Monitoring: The owner or operator shall use a CO CEMS to measure CO emissions from STRU32. Additional monitoring requirements are also located at Subject Item COMG3. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

COMG 08 GP007 Operating Load and Operating Conditions Monitoring: Continuously monitor (at the same frequency as the CO monitor sampling rate) and record the heat input (mmBtu/hr) for EQUI1 and EQUI62 using the method specified at 40 CFR Part 75, Appendix F. Calculate and record the average hourly operating load as a percent of maximum possible load for the specific compressor inlet conditions. Monitor and record the times and duration of any "off normal" operating condition (startup, shutdown, or malfunction) defined above. Record the start and stop time of all steam turbine-generator on-line and off-line operation. [Minn. R. 7007.0800, subp. 4, Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

COMG 08 GP007 By the 15th day of each month, calculate and record monthly NOx emissions and the annual 12-month rolling sum. The rolling sum shall be calculated by adding the current month's emission totals with those for the previous 11 months. [Minn. R. 7007.0800, subps. 4-5]

COMG 08 GP007 By the 15th day of each month, calculate and record monthly CO emissions and the annual 12-month rolling sum. The rolling sum shall be calculated by adding the current month's emission totals with those for the previous 11 months. [Minn. R. 7007.0800, subps. 4-5]

COMG 08 GP007 PM < 10 micron : The Permittee shall conduct a performance test : Due before 07/02/2017 every 60 months thereafter to measure PM10 emissions. The first test is due by the date specified and all subsequent tests are due by the end of each 60-month period following that date. The performance test shall be conducted at worst 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. Testing conducted during the 60 days prior to the performance test due date satisfies the performance test due date, 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 3) within a Notice of Compliance letter. Testing conducted more than two months prior to the performance test due date satisfies this test due date requirement and will reset the performance test due date. [Minn. R. 7017.2020, subp. 1, Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

COMG 08 GP007 Volatile Organic Compounds : The Permittee shall conduct a performance test : Due before 07/02/2017 every 60 months thereafter to measure VOC emissions. The first test is due by the date specified and all subsequent tests are due by the end of each 60-month period following that date. The performance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 25A, or other method approved by MPCA in the performance test plan approval. Testing conducted during the 60 days prior to the performance test due date satisfies the performance test due date, 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 3) within a Notice of Compliance letter. Testing conducted more than two months prior to the performance test due date satisfies this test due date requirement and will reset the performance test due date. [Minn. R. 7017.2020, subp. 1, Title I Condition: 40 CFR pt. 52, 21(j)(BACT) & Minn. R. 7007.3000]

COMG 08 GP007 Recordkeeping: Maintain records of the occurrence and duration of any startup, shutdown, or malfunction in the operation of the facility including malfunction of the air pollution control equipment or any periods during which a continuous monitoring system or monitoring device is inoperative. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000, Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

COMG 08 GP007 Recordkeeping: The Permittee must retain records of all CEMS monitoring data and support information for a period of five years from the date of the monitoring sample, measurement or report. Records shall be kept at the source. [Minn. R. 7017.1130]

COMG 08 GP007 Excess emissions and monitoring system performance reports shall include the information required in 40 CFR Section 60.7(c) and (d), Section 60.49a and Section 60.334(j). MPCA Forms DRF-1 and DRF-2 may be used to meet this requirement. [40 CFR 60.334(j), 40 CFR 60.49(a), 40 CFR 60.7, Minn. R. 7007.0800, subp. 2]

COMG 10 The Permittee shall limit HAPs - Total <= 22.5 tons per year 12-month rolling sum basis to be calculated by the 15th day of the month for the previous calendar month as described later in this permit. [Minn. R. 7011.7000, Title I Condition: Avoid major source under 40 CFR 63.2]

COMG 10 The Permittee shall limit Formaldehyde <= 9.0 tons per year 12-month rolling sum basis to be calculated by the 15th day of the month for the previous calendar month as described later in this permit. [Minn. R. 7011.7000, Title I Condition: Avoid major source under 40 CFR 63.2]

COMG 10 EQUI1 Daily Recordkeeping: On each day of operation of EQUI1 the Permittee shall record and maintain a record of the number of hours spent at each of the following load ranges: 1. >90% load: 0.045 lb/hr 2. >70%-90% load: 0.038 lb/hr 3. 50%-70% load: 0.223 lb/hr 4.

COMG 10 EQUI92 Daily Recordkeeping: On each day of operation the Permittee shall record and maintain a record of the hours of operation EQUI92. [Minn. R. 7007.0800, subps. 4-5, Minn. R. 7011.7000, Title I Condition: Avoid major source under 40 CFR 63.2]

COMG 10 Monthly Recordkeeping: By the 15th of the month, the Permittee shall calculate and record the following: 1) The HAPs - Total emissions from EQUI1, EQUI62, and EQUI92 for the previous calendar month. 2) The Formaldehyde emissions from EQUI1, EQUI62, and EQUI92 for the previous calendar month. To calculate the emissions from EQUI1/EQUI62, the Permittee shall use emission factors for formaldehyde established by the most recent MPCA-approved stack test for the EQUI1/EQUI62 formaldehyde emissions at the associate load ranges. The most recent approved emission factors are listed below. For EQUI92 emission calculations, the Permittee shall use AP-42 emissions factors. [Minn. R. 7007.0800, subps. 4-5, Minn. R. 7011.7000, Title I Condition: Avoid major source under 40 CFR 63.2]

COMG 10 Formaldehyde: EQUI1/EQUI62 Formaldehyde Emission Factor/Rate Testing: Emission factors and rates shall be determined by using Agency approved stack test methods at the following loads and operating conditions with the SCR system online: 1. EQUI1 operating at less than 50 percent of full load. 2. EQUI1 operating at 50 to 70 percent of full load. 3. EQUI1 operating at 70 to 90 percent of full load. 4. EQUI1 and EQUI62 combined operating at 90 to 100 percent of full load. Until the formaldehyde emission factors for EQUI1 based on the tests completed July 2, 2002 (100%, 70%, and 50% loads) and November 11, 2002, (40% load) are replaced by further MPCA-approved performance testing, the Permittee shall use the following values to calculate formaldehyde emissions at the associated load ranges: >90% load: 0.045 lb/hr >70%-90% load: 0.038 lb/hr 50%-70% load: 0.223 lb/hr

COMG 10 Formaldehyde: EQUI1/EQUI62 Testing Frequency to Update Formaldehyde Emission Factors: Within 60 days of calculating 12-month rolling sum formaldehyde emissions of greater than 8.9 tons, the Permittee shall perform a stack test to redevelop emission factors for formaldehyde emissions from EQUI1/EQUI62 over the previously tested load ranges. [Minn. R. 7017.2020, subp. 1]

COMG 11 The CEMS requirements listed below outline the typical standards of 40 CFR pt. 60, 40 CFR pt. 75, and Minnesota Rules. Additional monitoring requirements may also apply to the Facility based on this combination of standards and it is the responsibility of the Facility to meet all applicable requirements. [Minn. R. 7007.0800, subp. 4(A)]

COMG 11 Nitrogen Oxides: Emissions Monitoring: The Permittee shall use CEMS to measure NOx emissions from EQUI92. [40 CFR 75.10(a), 40 CFR pt. 60, subp. KKKK, Minn. R. 7017.1010, subp 1]

COMG 11 40 CFR pt. 75 Emissions Monitoring Requirement: The Permittee shall use a Continuous Emissions Monitoring System (CEMS) to measure NOx emissions, and measure or calculate SO2 and CO2 in accordance with 40 CFR pt. 75 for emissions from STRU35. The Permittee shall measure NOx emissions in ppmvd corrected to 15% oxygen and automatically calculate and record the 1-hour average NOx emission rates. NOx ppmvd emission data shall also be converted to lb/mmBtu as required by pt. 75. [40 CFR 75.10, Minn. R. 7007.0800, subp. 4]

COMG 11 40 CFR pt. 60 Emissions Monitoring Requirement: The Permittee shall install, calibrate, maintain, and operate a continuous monitoring system (CEMS) consisting of a NOx monitor and a diluent gas (oxygen) monitor to determine the hourly NOx emission rate in parts per million (ppm) or pounds per million British thermal units (lb/MMBtu). [40 CFR 60.4335(b)(1), 40 CFR 60.4340(b), Minn. R. 7017.1006]

COMG 11 40 CFR pt. 60 CEMS Installation: The Permittee shall install and certify each NOx diluent CEMS according to Performance Specification 2 (PS 2) in 40 CFR 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 diluent CEMS that is installed and certified according to 40 CFR pt. 75, Appendix A is acceptable for use under 40 CFR pt. 60, subp. KKKK. The relative accuracy test audit (RATA) of the CEMS shall be performed on a lb/MMBtu basis. All continuous monitoring systems shall be installed such that representative measurements of emissions are obtained. Additional procedures for location of continuous monitoring systems contained in the applicable Performance Specifications of 40 CFR pt. 60, Appendix B shall be used. [40 CFR 60.13(a), 40 CFR 60.13(f), 40 CFR 60.4345(a), Minn. R. 7017.1010, subp. 1(A)]

COMG 11 40 CFR pt. 60 CEMS Operation: CEMS must be operated and data recorded during all periods of emission unit operation including periods of emission unit start-up, shutdown, or malfunction except for periods of acceptable monitor downtime. This requirement applies whether or not a numerical emission limit applies during these periods. A CEMS must not be bypassed except in emergencies where failure to bypass would endanger human health, safety, or plant equipment. [40 CFR 60.13(a), 40 CFR 60.13(e), Minn. R. 7017.1010, subp. 1(A), Minn. R. 7017.1090]

COMG 11 40 CFR pt. 75 Monitoring Data: Hourly averages shall be computed using at least one data point in each fifteen minute quadrant of an hour, where the unit combusted fuel during that quadrant of an hour. Notwithstanding this requirement, an hourly average may be computed from at least two data points separated by a minimum of 15 minutes (where the unit operates for more than one quadrant of an hour) if data is unavailable as a result of the performance of calibration, quality assurance, or preventive maintenance activities pursuant to 40 CFR Section 75.21 and appendix B of pt. 75, or backups of data from the data acquisition and handling system, or recertification, pursuant to Section 75.20. The owner or operator shall use all valid measurements or data points collected during an hour to calculate the hourly averages. All data points collected during an hour shall be, to the extent practicable, evenly spaced over the hour. [40 CFR 75.10(d)(1)]

COMG 11 40 CFR pt. 60 Valid Unit Operating Hour: As specified in 40 CFR Section 60.13(e)(2), during each full unit operating hour, both the NOx monitor and the diluent monitor must complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each 15-minute quadrant of the hour, to validate the hour. For partial unit operating hours, at least one valid data point must be obtained with each monitor for each quadrant of the hour in which the unit operates. For unit operating hours in which required quality assurance and maintenance activities are performed on the CEMS, a minimum of two valid data points (one in each of two quadrants) are required for each monitor to validate the NOx emission rate for the hour. If the unit operates in only one quadrant of the hour, at least one valid data point is required to calculate the NOx emission rate for the hour. [40 CFR 60.13(a), 40 CFR 60.13(e)(2), 40 CFR 60.13(h)(2)(iii), 40 CFR 60.4345(a), Minn. R. 7017.1010, subp. 1(A)]

COMG 11 40 CFR pt. 60 Hourly average calculation: For a full operating hour (any clock hour with 60 minutes of unit operation), at least four valid data points are required to calculate the hourly average, i.e., one data point in each of the 15-minute quadrants of the hour, except as provided for any operating hour in which required maintenance or quality-assurance activities are performed. For a partial operating hour (any clock hour with less than 60 minutes of unit operation), at least one valid data point in each 15-minute quadrant of the hour in which the unit operates is required to calculate the hourly average, except as provided for any operating hour in which required maintenance or quality-assurance activities are performed. If a daily calibration error check is failed during any operating hour, all data for that hour shall be invalidated, unless a subsequent calibration error test is passed in the same hour and the requirements of 40 CFR Section 60.13(h)(2)(iii) are met, based solely on valid data recorded after the successful calibration. Data recorded during periods of continuous monitoring system breakdown, repair, calibration checks, and zero and span adjustments shall not be included in the data averages computed under this paragraph, unless the Permittee is complying with the requirements of 40 CFR Section 60.7(f)(1) or (2), in which case the Permittee must include any data recorded during periods of monitor breakdown or malfunction in the data averages. For each full or partial operating hour, all valid data points shall be used to calculate the hourly average. Either arithmetic or integrated averaging of all data may be used to calculate the hourly averages. The data may be recorded in reduced or nonreduced form (e.g., ppm pollutant and percent O2 or ng/J of pollutant). [40 CFR 60.13(h)(2), 40 CFR 60.13(h)(2)(iv)-(ix), Minn. R. 7017.1010, subp. 1(A)]

COMG 11 Identification of Excess Emissions Under 40 CFR pt. 60, subp. KKKK: a) The Permittee shall reduce all CEMS data to hourly averages as specified in 40 CFR Section 60.13(h). The Permittee shall convert all excess emissions into units of the standard using the applicable conversion procedures specified in 40 CFR pt. 60, subp. KKKK. After conversion into units of the standard, the data may be rounded to two significant digits. b) The Permittee shall calculate and record the hourly NOx emission rate in units of ppm or lb/MMBtu (using the appropriate equation from method 19 in 40 CFR pt. 60, Appendix A) for each unit operating hour in which a valid hourly average is obtained for both NOx and diluent monitors. A valid hourly average is as described in 40 CFR Section 60.4345(b). For any hour in which the hourly average O2 concentration exceeds 19.0 percent O2, a diluent cap value of 19.0 percent O2 may be used in the emission calculations. c) The Permittee shall not correct measured NOx concentrations to 15 percent O2 when calculating emissions in lb/MMBtu. d) For periods where the missing data substitution procedures of 40 CFR pt. 75, subpart D are applied, the Permittee shall report those periods as monitor downtime in the excess emissions and monitoring performance report required under 40 CFR Section 60.7(c). e) The Permittee shall reduce any required fuel flow rate, steam flow rate, temperature, pressure, or megawatt data to hourly averages. f) The Permittee shall calculate the hourly average NOx emission rates, in ppm for units complying with the concentration limit, or in lb/MWh, using the equation at 40 CFR Section 60.4350(f)(1), for units complying with the output based standard. g) The Permittee shall use the calculated hourly average emissions rate described in 40 CFR Section 60.4350(f) to assess excess emissions on a 4-hour rolling average basis, as described in 40 CFR Section 60.4380(b)(1). [40 CFR 60.13(a), 40 CFR 60.13(h)(3), 40 CFR 60.4350(a)-(g), Minn. R. 7017.1010, subp. 1(A), Minn. R. 7017.1160, subps. 1-2]

COMG 11 40 CFR pt. 60 QA Plan: The Permittee shall develop and keep on-site a quality assurance (QA) plan for all of the continuous monitoring equipment described in 40 CFR Section 60.4345(a), (c), and (d). For the CEMS and fuel flow meters, the Permittee may, with state approval, satisfy the requirements of this paragraph by implementing the QA program and plan described in 40 CFR pt. 75, Appendix B, Section 1. [40 CFR 60.4345(e), Minn. R. 7017.1170, subp. 3]

COMG 11 40 CFR pt. 60 QA Plan: Develop and implement a written quality assurance plan that covers each CEMS. The plan shall be on site and available for inspection within 30 days after monitor certification. The plan shall contain all of the information required by 40 CFR Part 60, Appendix F, Section 3. The plan shall include the manufacturer's spare parts list for each CEMS and require that those parts be kept at the facility, or readily available from another of the Permittee's facilities, unless the Commissioner gives written approval to exclude specific spare parts from the list. [40 CFR pt. 60, Appendix F(3), Minn. R. 7017.1010, subp. 1(C), Minn. R. 7017.1170, subp. 2]

COMG 11 40 CFR pt. 60 CEMS QA/QC: The Permittee is subject to the performance specifications listed in 40 CFR pt. 60, Appendix B and shall operate, calibrate, and maintain each CEMS according to the QA/QC procedures in 40 CFR pt. 60, Appendix F as amended and maintain a written QA/QC program available in a form suitable for inspection. [40 CFR 60.13(a), 40 CFR pt. 60, Appendix F, Minn. R. 7017.1010, subp. 1]

COMG 11 40 CFR pt. 75 CEMS QA/QC: The Permittee shall operate, calibrate, and maintain each CEMS according to the QA/QC procedures in 40 CFR pt. 75, Appendix B as amended. [40 CFR 75.21(a)]

COMG 11 40 CFR pt. 75 Certification Application: The Permittee shall apply for certification of each continuous emission monitoring system used under the Acid Rain Program. The Permittee shall submit the certification application in accordance with 40 CFR Section 75.60 and each complete certification application shall include the information specified in Section 75.63. [40 CFR 75.20(a)(2), 40 CFR 75.60(b)(1), 40 CFR 75.63]

COMG 11 40 CFR pt. 60 CEMS Certification: 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. [40 CFR 60.7(a)(5), Minn. R. 7017.1060, subp. 1-3, Minn. R. 7017.1080, subp. 1-4, Minn. R. 7019.0100, subp. 1]

COMG 11 40 CFR pt. 60 CEMS Daily Calibration Drift Test: Check the zero (low level value between 0 and 20 percent of span value) and span (50 to 100 percent of span value) calibration drifts at least once daily. The zero and span must, at a minimum, be adjusted whenever the drift exceeds two times the limit specified in 40 CFR pt. 60, Appendix B. 40 CFR pt. 60, Appendix F, Section 4.3.1 shall be used to determine out-of-control periods for CEMS. [40 CFR 60.13(d)(1), 40 CFR pt. 60, Appendix F(4.1), Minn. R. 7017.1010, subp. 1, Minn. R. 7017.1170, subp. 3]

COMG 11 40 CFR pt. 60 Performance Evaluation: The Permittee shall conduct a performance evaluation of the continuous emission monitoring system (CEMS) during any performance test required under 40 CFR Section 60.8 or within 30 days thereafter in accordance with the applicable performance specification in 40 CFR pt. 60, Appendix B. The owner or operator of an affected facility shall conduct CEMS performance evaluations at such other times as may be required by the Administrator under section 114 of the Act. [40 CFR 60.13(c), Minn. R. 7017.1010, subp. 1(A)]

COMG 11 40 CFR pt. 60 CEMS Certification/Recertification Test: due 90 days after the first excess emissions report required for the CEMS or any change which invalidates the monitor's certification status as outlined in Minn. R. 7017.1050, subp. 2. [40 CFR 60.13(b), Minn. R. 7017.1010, subp. 1(A)]

COMG 11 Minn. R. Installation Notification: The Permittee shall notify MPCA : Due 60 calendar days before Installation Date of the continuous emissions monitoring system. The notification shall include plans and drawings of the CEMS. [Minn. R. 7017.1040, subp. 1]

COMG 11 The Permittee shall submit start-up notification : Due 10 working days after Startup of Monitor Date. [Minn. R. 7007.0800, subp. 2]

COMG 11 40 CFR pt. 60 Performance Demonstration Notification: The Permittee shall notify MPCA : Due 30 calendar days before Demonstration Commencement Date. The Permittee shall notify MPCA of the date upon which demonstration of the continuous monitoring system performance commences in accordance with 40 CFR Section 60.13(c). [40 CFR 60.7(a)(5), Minn. R. 7019.0100, subp. 1]

COMG 11 40 CFR pt. 60 CGA: The Permittee shall conduct CEMS cylinder gas audit (CGA) : Due after CEMS Certification Test Date quarterly but no more than three quarters in succession. A CGA is not required during any calendar quarter in which a RATA was performed. [40 CFR pt. 60, Appendix F, 5.1.3, Minn. R. 7017.1010, subp. 1(C)]

COMG 11 40 CFR pt. 60 RATA: The Permittee shall conduct CEMS relative accuracy test audit (RATA) : Due after CEMS Certification Test Date annually meaning by the end of every one of four calendar quarters. [40 CFR pt. 60, Appendix F(sec. 5.1.1), Minn. R. 7017.1010, subp. 1(C)]

COMG 11 40 CFR pt. 75 Linearity and Leak Test Check: The Permittee shall conduct linearity and leak check : Due after Startup of Monitor Date quarterly in accordance with procedures in 40 CFR pt. 75, Appendix B, Sections 2.2.1 and 2.2.2, and Appendix A, Section 6.2. This means once every calendar quarter in which there are at least 168 unit operating hours. Perform a leak check at least once during each QA operating quarter. [40 CFR pt. 75, Appendix B, 2.2]

COMG 11 40 CFR pt. 75 CEMS Relative Accuracy Test Audit (RATA): The Permittee shall conduct CEMS relative accuracy test audit (RATA) : Due semiannually. In accordance with 40 CFR pt. 75, Appendix B, this means once every two successive QA operating quarters (calendar quarter in which there are at least 168 unit operating hours) on all CEMS required by the Acid Rain Program. Relative accuracy test audits may be performed annually (i.e., once every four successive QA operating quarters, rather than once every two successive QA operating quarters) if any of the conditions listed in 40 CFR pt. 75, Appendix B, Sections 2.3.1.2(a) through 2.3.1.2(i) are met. [40 CFR pt. 75, Appendix B, 2.3]

COMG 11 Relative Accuracy Test Audit (RATA) Results Summary: due 30 days after end of each calendar quarter in which a RATA was conducted. [Minn. R. 7017.1180, subp. 3]

COMG 11 Linearity Test Results Summary: due 30 days after end of each calendar quarter in which a Linearity Test was conducted. [Minn. R. 7017.1180, subp. 4]

COMG 11 Cylinder Gas Audit (CGA) Results Summary: due 30 days after end of each calendar quarter in which a CGA was conducted. [Minn. R. 7017.1180, subp. 1]

COMG 11 40 CFR pt. 60 Recordkeeping: The Permittee shall retain records of all CEMS monitoring data and support information for a period of five years from the date of the monitoring sample, measurement or report. Records shall be kept at the source. [40 CFR 60.7(f), Minn. R. 7017.1130, Minn. R. 7019.0100, subp. 1]

COMG 11 40 CFR pt. 75 Recordkeeping: The Permittee shall maintain a file of all measurements, data, reports, and other information required by 40 CFR pt. 75 at the source in a form suitable for inspection for at least three (3) years from the date of each record. The file shall contain all information required by 40 CFR Section 75.57. [40 CFR 75.57]

COMG 11 40 CFR pt. 60 Excess Emissions and Monitor Downtime Report: The Permittee shall submit reports of excess emissions and monitor downtime for in accordance with 40 CFR Section 60.7(c). Excess emissions must be reported for all periods of unit operation, including start-up, shutdown, and malfunction. [40 CFR 60.4375]

COMG 11 40 CFR pt. 60 Excess Emission and Monitor Downtime Report: For the purpose of reports required under 40 CFR Section 60.7(c), periods of excess emissions and monitor downtime that must be reported are defined as follows: (1) An excess emissions is any unit operating period in which the 4-hour rolling average NOx emission rate exceeds the applicable emission limit in 40 CFR Section 60.4320. A 4-hour rolling average NOx emission rate under 40 CFR pt. 60, subp. KKKK is the arithmetic average of the average NOx emission rate in ppm or ng/J (lb/MWh) measured by the continuous emission monitoring equipment for a given hour and the three unit operating hour average NOx emission rates immediately preceding that unit operating hour. The Permittee shall calculate the rolling average if a valid NOx emission rate is obtained for at least 3 of the 4 hours. (2) A period of monitor downtime is any unit operating hour in which the data for any of the following parameters are either missing or invalid: NOx concentration, O2 concentration, fuel flow rate, or megawatts. The steam flow rate, steam temperature, and steam pressure are only required if you will use this information for compliance purposes. (3) For operating periods during which multiple emissions standards apply, the applicable standard is the average of the applicable standards during each hour. For hours with multiple emissions standards, the applicable limit for that hour is determined based on the condition that corresponded to the highest emissions standard. [40 CFR 60.4380, 40 CFR 60.4380(b)]

COMG 11 40 CFR pt. 75 Quarterly Reports: Electronically report the data and information in 40 CFR Section 75.64 (a), (b), and (c) to the Administrator quarterly. [40 CFR 75.64]

EQUI 01 EU026 This source is subject to the U.S. EPA Acid Rain Program codified at 40 CFR pts. 72, 73, and 75. Combustion turbine EQUI1 is a utility unit that also is a gas-fired unit and a new unit, as defined in 40 CFR Section 72.2. The Permittee's application for an acid rain permit for the combustion turbines is attached in Appendix D to this permit. [40 CFR pt. 72, 40 CFR pt. 73, 40 CFR pt. 75]

EQUI 01 EU026 The Permittee shall comply with the applicable Acid Rain emissions limitation for sulfur dioxide. [40 CFR 72.9(c)(1)(ii), 40 CFR 72.9(g)(4)]

EQUI 01 EU026 The Permittee shall hold allowances as of the allowance transfer deadline, in the unit's compliance subaccount, not less than the total annual emissions of sulfur dioxide for the previous calendar year. Allowances shall be held in, deducted from, or transferred among Allowance Tracking System accounts in accordance with the Acid Rain Program. [40 CFR 72.9(c)(1)(i), 40 CFR 72.9(g)(4)]

EQUI 01 EU026 If EQUI1 has excess emissions, the designated representative shall submit a proposed offset plan in accordance with 40 CFR Section 72.9(e). [40 CFR 72.9(e)]

EQUI 01 EU026 The Permittee shall certify Acid Rain Program submittals. Each submission under the Acid Rain Program shall be submitted, signed, and certified by the designated representative or the alternative designated representative for all sources on behalf of which the submission is made in accordance with 40 CFR Section 72.21. [40 CFR 72.21, 40 CFR 72.22]

EQUI 01 EU026 The Permittee shall keep on site or readily accessible at another site each of the following documents for a period of 5 years from the date the document is created: - The certificate of representation; - All emission monitoring information; - Copies of all reports, compliance certifications, and other submissions or records made under the Acid Rain Program; and - Copies of all documents used to complete an acid rain permit application. [40 CFR 72.9(f)(1)]

EQUI 01 EU026 The Permittee shall apply for Acid Rain Program Permit reissuance: The designated representative shall submit a complete Acid Rain permit application for each source with an affected unit at least 6 months prior to the expiration of an existing Acid Rain Permit in accordance with 40 CFR Section 72.30(c). [40 CFR 72.30(c)]

EQUI 01 EU026 Nitrogen Oxides <= 110 parts per million using a 4-hour rolling average by volume at 15% O2 on a dry basis and assuming a fuel-bound content of zero. Applies at all times except during startup, shutdown, or malfunction. Startup for purposes of this limit shall not exceed 1 hour. Shutdown for purposes of this limit shall not exceed 30 minutes. [40 CFR 60.332(a)(1), 40 CFR 60.334(j)(1)(iii)(A), Minn. R. 7011.2350]

EQUI 01 EU026 Sulfur Dioxide <= 0.15 percent by volume at 15 percent oxygen and on a dry basis. [40 CFR 60.333(a), Minn. R. 7011.2350]

EQUI 01 EU026 Startup and Shutdown Hours <= 1250 hours per year 12-month rolling sum basis. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

EQUI 01 EU026 EQUI1 Startup and Shutdown: In addition to the definition in 40 CFR Section 60.2, startup is defined as all EQUI1 operation at less than 70% capacity (for the specific combustion turbine compressor inlet conditions during operation) prior to initially attaining 70% load. EQUI1 startup ends no later than 15 minutes after EQUI1 first attains 70% load after startup commences. In addition to the definition in 40 CFR Section 60.2, shutdown is defined as all EQUI1 operation at less than 70% load that is part of the process that terminates EQUI1 fuel combustion until the next EQUI1 startup. Shutdown does not include temporary operating loads below 70% for up to 15 consecutive minutes, due to external factors such as changes in compressor inlet conditions. The CEMS data acquisition and handling system monitors EQUI1 load (using a signal provided by the combustion turbine generator control system) and indicates whether EQUI1 is operating in normal mode or startup/shutdown mode. The percent load signal is also used by the CEMS to determine whether emissions data is categorized as normal emissions data or startup/shutdown emissions data. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

EQUI 01 EU026 Sulfur Content of Fuel <= 0.004 grains per dry standard cubic foot 12-month rolling average. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2) and Minn. R. 7007.3000]

EQUI 01 EU026 Sulfur Content of Fuel <= 0.8 percent by weight. [40 CFR 60.333(b), Minn. R. 7011.2350] EQUI 01 EU026 Fuel usage is limited to pipeline quality natural gas. [Title I Condition: Avoid major modification under

40 CFR 52.21(b)(2) and Minn. R. 7007.3000]

EQUI 01 EU026 The Permittee need not monitor the total sulfur content of the gaseous fuel combusted in the turbine, if the gaseous fuel is demonstrated to meet the definition of natural gas in 40 CFR Section 60.331(u). The Permittee shall use one of the following sources of information to make the required demonstration: (i) The gas quality characteristics in a current, valid purchase contract, tariff sheet or transportation contract for the gaseous fuel, specifying that the maximum total sulfur content of the fuel is 20.0 grains/100 scf or less; or (ii) Representative fuel sampling data which show that the sulfur content of the gaseous fuel does not exceed 20 grains/100 scf. At a minimum, the amount of fuel sampling data specified in section 2.3.1.4 or 2.3.2.4 of appendix D to 40 CFR part 75 is required. [40 CFR 60.334(h)(3), Minn. R. 7011.2350]

EQUI 01 EU026 Maintain records of the demonstration that the gaseous fuel used meets the definition of natural gas in 40 CFR Section 60.31(u). [Minn. R. 7007.0800, subp. 5]

EQUI 01 EU026 Daily Startup and Shutdown Operating Hours Monitoring and Recordkeeping: Once each day the Permittee shall calculate and record EQUI1 startup and shutdown operating hours for the previous calendar day. Startup and shutdown operating hours shall be determined using the electronic data produced by instrumentation that instantaneously measures EQUI1 gross electric power output. [Minn. R. 7007.0800, subps. 4-5, Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

EQUI 01 EU026 Monthly Startup and Shutdown Operating Hours Monitoring and Recordkeeping: By the 15th day of each month, the Permittee shall calculate and record the total EQUI1 startup and shutdown operating hours for the previous month and for the previous 12-month period. [Minn. R. 7007.0800, subps. 4-5]

EQUI 01 EU026 Transport Rule (TR) NOx Annual Trading Program Requirements The Permittee shall comply with the TR NOx Annual Trading Program requirements contained in permit Appendix C. [40 CFR 97.430-435]

EQUI 01 EU026 Designated representative requirements: The Permittee shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with 40 CFR Section 97.413 through 97.418. [40 CFR 97.406(a)]

EQUI 01 EU026 1.) The Permittee and the designated representative, of each TR NOx Annual source and each TR NOx Annual unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of 40 CFR Section 97.430 (general requirements, including installation, certification, and data accounting, compliance deadlines, reporting data, prohibitions, and long-term cold storage), 40 CFR Section 97.431 (initial monitoring system certification and recertification procedures), 40 CFR Section 97.432 (monitoring system out-of-control periods), 40 CFR Section 97.433 (notifications concerning monitoring), 40 CFR Section 97.434 (recordkeeping and reporting, including monitoring plans, certification applications, quarterly reports, and compliance certification), and 40 CFR Section 97.435 (petitions for alternatives to monitoring, recordkeeping, or reporting requirements). 2.) The emissions data determined in accordance with 40 CFR Section 97.430 through 97.435 shall be used to calculate allocations of TR NOx Annual allowances under 40 CFR Section 97.411(a)(2) and (b) and 40 CFR Section 97.412 and to determine compliance with the TR NOx Annual emissions limitation and assurance provisions under paragraph 40 CFR Section 97.406(c) below, provided that, for each monitoring location from which mass emissions are reported, the mass emissions amount used in calculating such allocations and determining such compliance shall be the mass emissions amount for the monitoring location determined in accordance with 40 CFR Section 97.430 through 97.435 and rounded to the nearest ton, with any fraction of a ton less than 0.50 being deemed to be zero. [40 CFR 97.406(b)]

EQUI 01 EU026 TR NOx Annual emissions limitation. i.) As of the allowance transfer deadline for a control period in a given year, the Permittee shall hold, in the source's compliance account, TR NOx Annual allowances available for deduction for such control period under 40 CFR Section 97.424(a) in an amount not less than the tons of total NOx emissions for such control period from all TR NOx 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 NOx Annual source are in excess of the TR NOx Annual emissions limitation set forth in 40 CFR Section 97.406(c)(1)(i) above, then: A. The Permittee shall hold the TR NOx Annual allowances required for deduction under 40 CFR Section 97.424(d); and B. The Permittee shall pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act, and each ton of such excess emissions and each day of such control period shall constitute a separate violation of 40 CFR part 97, subpart AAAAA and the Clean Air Act. [40 CFR 97.406(c)(1)]

EQUI 01 EU026 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 Annual 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 having a common designated representative for such control period, where the common designated representative's share of such NOx emissions during such control period exceeds the common designated representative's assurance level for the state and such control period, shall hold (in the assurance account established for the owners and operators of such group) TR NOx Annual allowances available for deduction for such control period under 40 CFR Section 97.425(a) in an amount equal to two times the product (rounded to the nearest whole number), 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 exceeds the common designated representative's assurance level divided by the sum of the amounts, determined for all common designated representatives for such sources and units in the Minnesota and Indian country within the borders of Minnesota for such control period, by which each common designated representative's share of such NOx emissions exceeds the respective common designated representative's assurance level; and (B) The amount by which total NOx emissions from all TR NOx Annual units at TR NOx Annual sources in Minnesota and Indian country within the borders of Minnesota for such control period exceed the state assurance level. ii.) The Permittee shall hold the TR NOx Annual allowances required under 40 CFR Section 97.406(c)(2)(i) above, as of midnight of November 1 (if it is a business day), or midnight of the first business day thereafter (if November 1 is not a business day), immediately after such control period. iii.) Total NOx emissions from all TR NOx Annual units at TR NOx Annual sources in Minnesota and Indian country within in the borders of Minnesota during a control period in a given year exceed the state assurance level if such total NOx emissions exceed the sum, for such control period, of the state NOx Annual trading budget under 40 CFR 97.410(a) and the state's variability limit under 40 CFR 97.410(b). iv.) It shall not be a violation of 40 CFR part 97, subpart AAAAA or of the Clean Air Act if total NOx emissions from all TR NOx Annual units at TR NOx Annual sources in Minnesota and Indian country within the borders of Minnesota during a control period exceed the state assurance level or if a common designated representative's share of total NOx emissions from the TR NOx Annual units at TR NOx Annual sources in the Minnesota and Indian country within the borders of Minnesota during a control period exceeds the common designated representative's assurance level. v.) To the extent the Permittee fails to hold TR NOx Annual allowances for a control period in a given year in accordance with 40 CFR Section 97.406(c)(2)(i) through (iii) above, A. The Permittee shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and B. Each TR NOx Annual allowance that the Permittee fails to hold for such control period in accordance with 40 CFR Section 97.406(c)(2)(i) through (iii) above and each day of such control period shall constitute a separate violation of 40 CFR part 97, subpart AAAAA and the Clean Air Act. [40 CFR 97.406(c)(2)(i)-(v)]

EQUI 01 EU026 Compliance periods. i) A TR NOx Annual unit shall be subject to the requirements under 40 CFR 97.406(c)(1) above for the control period starting on the later of January 1, 2015, or the deadline for meeting the unit's monitor certification requirements 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 97.406(c)(2) above for the control period starting on the later of January 1, 2017 or the deadline for meeting the unit's monitor certification requirements under 40 CFR 97.430(b) and for each control period thereafter. [40 CFR 97.406(c)(3)]

EQUI 01 EU026 Vintage of allowances held for compliance. i). A TR NOx Annual allowance held for compliance with the requirements under 40 CFR 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 such control period or a control period in a prior year. ii). A TR NOx Annual allowance held for compliance with the requirements under 40 CFR 97.406(c)(1)(ii)(A) and (2)(i) through (iii) above for a control period in a given year must be a TR NOx Annual allowance that was allocated for a control period in a prior year or the control period in the given year or in the immediately following year. [40 CFR 97.406(c)(4)]

EQUI 01 EU026 Allowance Management System requirements. Each TR NOx Annual allowance shall be held in, deducted from, or transferred into, out of, or between Allowance Management System accounts in accordance with 40 CFR part 97, subpart AAAAA. [40 CFR 97.406(c)(5)]

EQUI 01 EU026 Limited authorization. A TR NOx Annual allowance is a limited authorization to emit one ton of NOx during the control period in one year. 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; and ii) Notwithstanding any other provision of 40 CFR part 97, the Administrator has the authority to terminate or limit the use and duration of such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act. [40 CFR 97.406(c)(6)]

EQUI 01 EU026 Property right. A TR NOx Annual allowance does not constitute a property right. [40 CFR 97.406(c)(7)] EQUI 01 EU026 Additional recordkeeping and reporting requirements. 1.) Unless otherwise provided, the Permittee

shall keep on site at the source each of the following documents (in hardcopy or electronic format) for a period of 5 years from the date the document is created. This period may be extended for cause, 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 source and each TR NOx Annual unit at the source and all documents that demonstrate the truth of the statements in the certificate of representation; provided that the certificate and documents shall be retained on site at the source beyond such 5-year period until such certificate of representation and documents are superseded because of the submission of a new certificate of representation under 40 CFR 97.416 changing the designated representative. ii.) All emissions monitoring information, in accordance with 40 CFR part 97, subpart AAAAA. iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the TR NOx Annual Trading Program. 2.) The designated representative of a TR NOx Annual source and each TR NOx Annual unit at the source shall make all submissions required under the TR NOx Annual Trading Program, except as provided in 40 CFR Section 97.418. This requirement does not change, create an exemption from, or otherwise affect the responsible official submission requirements under a title V operating permit program in 40 CFR parts 70 and 71. [40 CFR 97.406(e)]

EQUI 01 EU026 Liability. 1.) Any provision of the TR NOx Annual Trading Program that applies to a TR NOx Annual source or the designated representative of a TR NOx Annual source shall also apply to the Permittee. 2.) Any provision of the TR NOx Annual Trading Program that applies to a TR NOx Annual unit or the designated representative of a TR NOx Annual unit shall also apply to the Permittee. [40 CFR 97.406(f)]

EQUI 01 EU026 Effect on other authorities. No provision of the TR NOx Annual Trading Program or exemption under 40 CFR Section 97.405 shall be construed as exempting or excluding the Permittee, and the designated representative, of a TR NOx Annual source or TR NOx Annual unit from compliance with any other provision of the applicable, approved state implementation plan, a federally enforceable permit, or the Clean Air Act. [40 CFR 97.405]

EQUI 01 EU026 TR SO2 Group 2 Trading Program Requirements The Permittee shall comply with the TR SO2 Group 2 Trading Program Requirements contained in permit Appendix C. [40 CFR 97.730-735]

EQUI 01 EU026 Designated representative requirements. The Permittee shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with 40 CFR Section 97.713 through 97.718. [40 CFR 97.706(a)]

EQUI 01 EU026 Emissions monitoring, reporting, and recordkeeping requirements. 1.) The Permittee, and the designated representative, of each TR SO2 Group 2 source and each TR SO2 Group 2 unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of 40 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 (initial monitoring system certification and recertification procedures), 40 CFR Section 97.732 (monitoring system out-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, and compliance certification), and 40 CFR Section 97.735 (petitions for alternatives to monitoring, recordkeeping, or reporting requirements). 2.) The emissions data determined in accordance with 40 CFR Section 97.730 through 97.735 shall be used to calculate allocations of TR SO2 Group 2 allowances under 40 CFR 97.711(a)(2) and (b) and 40 CFR Section 97.712 and to determine compliance with the TR SO2 Group 2 emissions limitation and assurance provisions under 40 CFR Section 97.706(c) below, provided that, for each monitoring location from which mass emissions are reported, the mass emissions amount used in calculating such allocations and determining such compliance shall be the mass emissions amount for the monitoring location determined in accordance with 40 CFR Section 97.730 through 97.735 and rounded to the nearest ton, with any fraction of a ton less than 0.50 being deemed to be zero. [40 CFR 97.706(b)]

EQUI 01 EU026 TR SO2 Group 2 emissions limitation. i.) As of the allowance transfer deadline for a control period in a given year, the Permittee shall hold, in the source's compliance account, TR SO2 Group 2 allowances available for deduction for such control period under 40 CFR Section 97.724(a) in an amount not less than the tons of total SO2 emissions for such control period from 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 SO2 Group 2 source are in excess of the TR SO2 Group 2 emissions limitation set forth in paragraph 40 CFR Section 97.706(c)(1)(i) above, then: A.) The Permittee shall hold the TR SO2 Group 2 allowances required for deduction under 40 CFR Section 97.724(d); and B.) The Permittee shall pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act, and each ton of such excess emissions and each day of such control period shall constitute a separate violation of 40 CFR part 97, subpart DDDDD and the Clean Air Act. [40 CFR pt. 97, 706(c)(1)]

EQUI 01 EU026 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 Group 2 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 having a common designated representative for such control period, where the common designated representative's share of such SO2 emissions during such control period exceeds the common designated representative's assurance level for the state and such control period, shall hold (in the assurance account established for the owners and operators of such group) TR SO2 Group 2 allowances available for deduction for such control period under 40 CFR Section 97.725(a) in an amount equal to two times the product (rounded to the nearest whole number), as determined by the Administrator in accordance with 40 CFR Section 97.725(b), of multiplying— A.) The quotient of the amount by which the common designated representative's share of such SO2 emissions exceeds the common designated representative's assurance level divided by the sum of the amounts, determined for all common designated representatives for such sources and units in Minnesota and Indian country within the borders of Minnesota for such control period, by which each common designated representative's share of such SO2 emissions exceeds the respective common designated representative's assurance level; and B.) The amount by which total SO2 emissions from all TR SO2 Group 2 units at TR SO2 Group 2 sources in Minnesota and Indian country within the borders of Minnesota for such control period exceed the state assurance level. ii) The Permittee shall hold the TR SO2 Group 2 allowances required under 40 CFR Section 97.706(c)(2)(i) above, as of midnight of November 1 (if it is a business day), or midnight of the first business day thereafter (if November 1 is not a business day), immediately after such control period. iii.) Total SO2 emissions from all TR SO2 Group 2 units at TR SO2 Group 2 sources in Minnesota and Indian country within the borders of Minnesota during a control period in a given year exceed the state assurance level if such total SO2 emissions exceed the sum, for such control period, of the state SO2 Group 2 trading budget under 40 CFR Section 97.710(a) and the state's variability limit under 40 CFR Section 97.710(b). iv.) It shall not be a violation of 40 CFR part 97, subpart DDDDD or of the Clean Air Act if total SO2 emissions from all TR SO2 Group 2 units at TR SO2 Group 2 sources in Minnesota and Indian country within the borders of Minnesota during a control period exceed the state assurance level or if a common designated representative's share of total SO2 emissions from the TR SO2 Group 2 units at TR SO2 Group 2 sources in Minnesota and Indian country within the borders of Minnesota during a control period exceeds the common designated representative's assurance level. v.) To the extent the Permittee fails to hold TR SO2 Group 2 allowances for a control period in a given year in accordance with 40 CFR Section 97.706(c)(2)(i) through (iii) above, A.) The Permittee shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and B.) Each TR SO2 Group 2 allowance that the Permittee fails to hold for such control period in accordance with 40 CFR Section 97.706(c)(2)(i) through (iii) above and each day of such control period shall constitute a separate violation of 40 CFR part 97, subpart DDDDD and the Clean Air Act. [40 CFR 97.706(c)(2)(i)-(v)]

EQUI 01 EU026 i.) A TR SO2 Group 2 unit shall be subject to the requirements under 40 CFR Section 97.706(c)(1) above for the control period starting on the later of January 1, 2015 or the deadline for meeting the unit's monitor certification requirements under 40 CFR Section 97.730(b) and for each control period thereafter. ii.) A TR SO2 Group 2 unit shall be subject to the requirements under 40 Section CFR 97.706(c)(2) above for the control period starting on the later of January 1, 2017 or the deadline for meeting the unit's monitor certification requirements under 40 CFR Section 97.730(b) and for each control period thereafter. [40 CFR 97.706(c)(3)]

EQUI 01 EU026 Vintage of allowances held for compliance. i.) A TR SO2 Group 2 allowance held for compliance with the requirements under 40 CFR 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 such control 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 97.706(c)(1)(ii)(A) and (2)(i) through (iii) above for a control period in a given year must be a TR SO2 Group 2 allowance that was allocated for a control period in a prior year or the control period in the given year or in the immediately following year. [40 CFR 97.706(c)(4)]

EQUI 01 EU026 Allowance Management System requirements. Each TR SO2 Group 2 allowance shall be held in, deducted from, or transferred into, out of, or between Allowance Management System accounts in accordance with 40 CFR part 97, subpart DDDDD. [40 CFR 97.706(c)(5)]

EQUI 01 EU026 Limited authorization. A TR SO2 Group 2 allowance is a limited authorization to emit one ton of SO2 during the control period in one year. 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; and ii) Notwithstanding any other provision of 40 CFR part 97, subpart DDDDD, the Administrator has the authority to terminate or limit the use and duration of such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act. [40 CFR 97.706(c)(6)]

EQUI 01 EU026 Property right. A TR SO2 Group 2 allowance does not constitute a property right. [40 CFR pt. 97, 706(c)(7)]

EQUI 01 EU026 Additional recordkeeping and reporting requirements. 1.) Unless otherwise provided, the Permittee shall keep on site at the source each of the following documents (in hardcopy or electronic format) for a period of 5 years from the date the document is created. This period may be extended for cause, 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 source and each TR SO2 Group 2 unit at the source and all documents that demonstrate the truth of the statements in the certificate of representation; provided that the certificate and documents shall be retained on site at the source beyond such 5-year period until such certificate of representation and documents are superseded because of the submission of a new certificate of representation under 40 CFR Section 97.716 changing the designated representative. ii.) All emissions monitoring information, in accordance with 40 CFR part 97, subpart DDDDD. iii.) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the TR SO2 Group 2 Trading Program. 2.) The designated representative of a TR SO2 Group 2 source and each TR SO2 Group 2 unit at the source shall make all submissions required under the TR SO2 Group 2 Trading Program, except as provided in 40 CFR Section 97.718. This requirement does not change, create an exemption from, or otherwise affect the responsible official submission requirements under a title V operating permit program in parts 70 and 71. [40 CFR 97.706(e)]

EQUI 01 EU026 Liability. 1.) Any provision of the TR SO2 Group 2 Trading Program that applies to a TR SO2 Group 2 source or the designated representative of a TR SO2 Group 2 source shall also apply to the Permittee. 2.) Any provision of the TR SO2 Group 2 Trading Program that applies to a TR SO2 Group 2 unit or the designated representative of a TR SO2 Group 2 unit shall also apply to the Permittee. [40 CFR 97.706(f)]

EQUI 01 EU026 Effect on other authorities. No provision of the TR SO2 Group 2 Trading Program or exemption under 40 CFR Section 97.705 shall be construed as exempting or excluding the Permittee, and the designated representative, of a TR SO2 Group 2 source or TR SO2 Group 2 unit from compliance with any other provision of the applicable, approved state implementation plan, a federally enforceable permit, or the Clean Air Act. [40 CFR 97.706(g)]

EQUI 46 MR019 CEMS Certification/Recertification Test: due 120 days after the first calendar quarter following CEMS installation/reinstallation. [Minn. R. 7017.1050, subp. 1]

EQUI 46 MR019 CEMS Certification Test Plan: due 30 days before CEMS Certification Test CEMS Certification Test Pretest Meeting: due 7 days before CEMS Certification Test CEMS Certification Test Report: due 45 days after CEMS Certification Test CEMS Certification Test Report - Microfiche Copy: due 105 days after CEMS Certification Test The Notification, Test Plan, and Test Report may be submitted in alternate format as allowed by Minn. R. 7017.1120, subp. 2 [Minn. R. 7017.1080, Minn. R. 7017.1060]

EQUI 46 MR019 Continuous Operation: CEMS must be operated and data recorded during all periods of emission unit operation including periods of emission unit start-up, shutdown, or malfunction except for periods of acceptable monitor downtime. This requirement applies whether or not a numerical emission limit applies during these periods. A CEMS must not be bypassed except in emergencies where failure to bypass would endanger human health, safety, or plant equipment. [Minn. R. 7017.1090]

EQUI 46 MR019 Monitoring Data: All data points collected by a CEMS shall be used to calculate individual hourly emission averages unless another applicable requirement requires more frequent averaging. In order for an hour of data to be considered, it must contain the following minimum number of data points: A. four data points, equally spaced, if the emission unit operated during the entire hour; B. two data points, at least 15 minutes apart, during periods of monitor calibration or routine maintenance; C. one data point if the emission unit operated for 15 minutes or less during the hour. [Minn. R. 7017.1160, subp. 1, Minn. R. 7017.1160, subp. 2]

EQUI 46 MR019 QA Plan: Develop and implement a written quality assurance plan that covers each CEMS. The plan shall be on site and available for inspection within 30 days after monitor certification. The plan shall contain all of the information required by 40 CFR pt. 60, Appendix F, Section 3. The plan shall include the manufacturer's spare parts list for each CEMS and require that those parts be kept at the facility or readily available from another of the Permittee's facilities, unless the Commissioner gives written approval to exclude specific spare parts from the list. [Minn. R. 7017.1170, subp. 2]

EQUI 46 MR019 Requirement: CEMS Daily Calibration Drift (CD) Test: The CD shall be quantified and recorded at zero (low-level) and upscale (high-level) gas concentrations at least once daily according to the procedures listed in Minn. R. 7017.1170, subp. 3(A) and (B) and 40 CFR Section 60.13(d)(1) for each pollutant concentration, each diluent monitor, and for each monitor range. The CEMS shall be adjusted whenever the CD exceeds twice the specification of 40 CFR pt. 60, Appendix B. If no span value is specified in the applicable requirement or in a compliance document, the Permittee shall use a span value equivalent to 1.5 times the emission limit. 40 CFR pt. 60, Appendix F, shall be used to determine out-of-control periods for CEMS. Follow the procedures in 40 CFR pt. 60, Appendix F. [Minn. R. 7017.1170, subp. 3]

EQUI 46 MR019 Cylinder Gas Audit (CGA): due before end of each calendar half-year following Permit Issuance, except that a CGA is not required during any calendar half year in which a RATA was performed. The initial CGA must be performed within 180 days following certification of the CEMS. The CGAs shall be conducted at least three months apart but no more than eight months apart. A CGA shall be conducted according to the procedures in 40 CFR pt. 60, Appendix F, Section 5.1.2. If the monitored emission unit was operated for less than 24 hours during the calendar half year, a CGA is not required for that calendar half year. [Minn. R. 7017.1170, subp. 4]

EQUI 46 MR019 Cylinder Gas Audit (CGA): The Permittee shall conduct a cylinder gas audit : Due by the end of each calendar half-year. A CGA is not required during any calendar half year in which a RATA was performed. The initial CGA must be performed within 180 days following certification of the CEMS. The CGAs shall be conducted at least three months apart but no more than eight months apart. A CGA shall be conducted according to the procedures in 40 CFR pt. 60, Appendix F, Section 5.1.2. If the monitored emission unit was operated for less than 24 hours during the calendar half year, a CGA is not required for that calendar half year. [Minn. R. 7017.1170, subp. 4]

EQUI 46 MR019 Cylinder Gas Audit (CGA) Results Summary: due 30 days after end of each calendar quarter in which a CGA was conducted. [Minn. R. 7017.1180, subp. 1]

EQUI 46 MR019 CEMS Relative Accuracy Test Audit (RATA): The Permittee shall conduct CEMS relative accuracy test audit (RATA) : Due annually before the end of each calendar year. A RATA is not required in any calendar year if a RATA conducted in the previous year demonstrated a relative accuracy value of less than 15 percent or if the associated emissions unit operated less than 48 hours during the calendar year. If the exception is used, the next RATA shall be conducted during the first half of the following calendar year. RATAs shall be conducted at least 3 months apart and according to 40 CFR pt. 60, Appendix F, Section 5.1.1. [40 CFR pt. 75, Appendix B, 2.3]

EQUI 46 MR019 Relative Accuracy Test Audit (RATA) Notification: due 30 days before CEMS Relative Accuracy Test Audit (RATA). [Minn. R. 7017.1180, subp. 2]

EQUI 46 MR019 Relative Accuracy Test Audit (RATA) Results Summary: due 30 days after end of each calendar quarter in which a RATA was conducted. [Minn. R. 7017.1180, subp. 3]

EQUI 46 MR019 Recordkeeping: The Permittee must retain records of all CEMS monitoring data and support information for a period of five years from the date of the monitoring sample, measurement or report. Records shall be kept at the source. [Minn. R. 7017.1130]

EQUI 60 EU024 Opacity <= 20 percent opacity once operating temperatures have been attained. [Minn. R. 7011.2300, subp. 1]

EQUI 60 EU024 Sulfur Dioxide <= 0.50 pounds per million Btu heat input. The potential to emit from the unit is 0.05 lb/MMBtu due to equipment design and allowable fuel. [Minn. R. 7011.2300, subp. 2]

EQUI 60 EU024 Fuel type is limited to distillate fuel oil with a maximum Sulfur Content of Fuel <= 0.050 percent by weight. [Minn. R. 7007.0800, subp. 2]

EQUI 60 EU024 EQUI60 must be operated according to the following requirements, or the engine will not be considered an emergency engine under 40 CFR Part 63 Subpart ZZZZ, and will be required to meet all Subpart ZZZZ requirements for non-emergency engines. (i) There is no time limit on engine use in emergency situations. (ii) The engine may be operated for the purpose of maintenance checks and readiness testing, provided that the tests are recommended by the manufacturer, the vendor, or the insurance company associated with the engine. Required testing of such units should be minimized, but there is no time limit on engine use in emergency situations and for routine testing and maintenance. (iii) The engine may be operated for an additional 50 hours per year in non-emergency situations. The 50 hours cannot be used for peak shaving or to generate income for a facility to supply power to an electric grid or otherwise supply power as part of a financial arrangement with another entity. [40 CFR 63.6640(f)(2), Minn. R. 7011.8150]

EQUI 60 EU024 Fuel Supplier Certification: The Permittee shall obtain supplier certification that the sulfur content does not exceed 0.050 % by weight. The certification shall be a single certification from the fuel oil supplier guaranteeing a maximum sulfur content in all fuel oil deliveries thereafter. The single certification shall also state that the supplier will notify the Permittee in writing on the date of delivery of fuel oil with a sulfur content exceeding the guaranteed maximum, that the fuel oil sulfur content exceeds the guaranteed maximum value. The Permittee may instead choose to test the oil in the storage tank following each shipment, according to current ASTM or EPA methods and keep records of lab analyses of sulfur content. [Minn. R. 7007.0800, subp. 5]

EQUI 60 EU024 Temporary replacement conditions: The Permittee may temporarily replace EQUI60, provided the following conditions are met: 1) The potential emissions of the replacement unit (assuming all enforceable limits imposed through this permit, and aggregated if more than one engine is simultaneously replaced; see COMG1, EQUI61, and EQUI90) are less than all of the following: 25 tpy PM, 15 tpy PM < 10 microns, 10 tpy PM < 2.5 microns, 40 tpy VOC, 40 tpy SO2, 40 tpy NOx, 100 tpy CO, 75000 tpy CO2e; 2) The Permittee must calculate the allowable potential to emit of each temporary replacement engine assuming operating conditions that are enforceable by this permit. For pollutants not specifically limited by a permit or rule, the Permittee may use emission factors generated based on the temporary replacement engine manufacturer's performance tests; 3) The capacity of the replacement unit is less than or equal to the unit it replaces; 4) The project can only be the temporary replacement of internal combustion engines for the purpose of providing emergency electrical power at the facility; 5) Emissions and operating hours are tracked and calculated as specified in this permit; 6) The replacement engine may only replace a permanent engine that is temporarily out of service for less than one year; 7) The replacement engine must meet the conditions for temporary replacement units under 40 CFR Section 60.4200(e); 8) Prior to making such a change, the Permittee shall apply for and obtain the appropriate permit amendment. The Permittee is not required to complete emission calculations described in Minn. R. 7007.1200 subp. 2. A permit will still be needed regardless of the emissions increase if the change will be subject to a new applicable requirement or requires revisions to the limits or monitoring and recordkeeping in this permit. [40 CFR 60.4200(e), Minn. R. 7005.0100, subp. 35a, Minn. R. 7007.0800, Minn. R. 7007.1200, subp. 3, Minn. R. 7007.1250, Minn. R. 7007.1450, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2) and Minn. R. 7007.3000]

EQUI 60 EU024 The replacement engine may not be operated at the same time as the permanent unit it is replacing, except for up to 8 hours during start-up and shutdown transition periods. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2) and Minn. R. 7007.3000]

EQUI 60 EU024 If the replacement engine does not require a permit amendment, the Permittee shall keep the following records on site for each replacement engine not requiring a permit amendment: - Records required by Minn. R. 7007.1200, subp. 4; - The dates the temporary engine was installed, started operation, and was removed; - Filled form GI05B for each replacement engine with an assigned consecutive emission unit number; - A unique identification for the unit, such as make, model, and serial number; - Rated capacity and type of engine; - Dates and hours of operation of the engine; - A statement of all periods of operation during which the permanent engine being temporarily replaced is not also operating; and - Calculations of the potential to emit of the engine and emission changes pursuant to Minn. R. 7007.1200 subpart 3. [Minn. R. 7007.1200, subp. 4, , Minn. R. 7007.0800, subp. 2]

EQUI 60 EU024 The Permittee shall notify the MPCA if the replacement engine is operated simultaneously with the permanent engine being temporarily replaced, except as allowed by this permit. Make verbal notification within 2 days, and written notification with the semi-annual deviations report. [Minn. R. 7007.1200, subp. 4, Minn. R. 7007.0800, subp. 5]


EQUI 61 EU025 Sulfur Dioxide <= 0.50 pounds per million Btu heat input. The potential to emit from the unit is 0.05 lb/MMBtu due to equipment design and allowable fuels. [Minn. R. 7011.2300, subp. 2]

EQUI 61 EU025 Fuel type is limited to distillate fuel oil with a maximum Sulfur Content of Fuel <= 0.050 percent by weight. [Minn. R. 7007.0800, subp. 2]

EQUI 61 EU025 EQUI61 must be operated according to the following requirements, or the engine will not be considered an emergency engine under 40 CFR Part 63 Subpart ZZZZ, and will be required to meet all Subpart ZZZZ requirements for non-emergency engines. (i) There is no time limit on engine use in emergency situations. (ii) The engine may be operated for the purpose of maintenance checks and readiness testing, provided that the tests are recommended by the manufacturer, the vendor, or the insurance company associated with the engine. Required testing of such units should be minimized, but there is no time limit on engine use in emergency situations and for routine testing and maintenance. (iii) The engine may be operated for an additional 50 hours per year in non-emergency situations. The 50 hours cannot be used for peak shaving or to generate income for a facility to supply power to an electric grid or otherwise supply power as part of a financial arrangement with another entity. [40 CFR 63.6640(f)(2), Minn. R. 7011.8150]

EQUI 61 EU025 Fuel Supplier Certification: The Permittee shall obtain supplier certification that the sulfur content does not exceed 0.050 % by weight. The certification shall be a single certification from the fuel oil supplier guaranteeing a maximum sulfur content in all fuel oil deliveries thereafter. The single certification shall also state that the supplier will notify the Permittee in writing on the date of delivery of fuel oil with a sulfur content exceeding the guaranteed maximum, that the fuel oil sulfur content exceeds the guaranteed maximum value. The Permittee may instead choose to test the oil in the storage tank following each shipment, according to current ASTM or EPA methods and keep records of lab analyses of sulfur content. [Minn. R. 7007.0800, subp. 5]

EQUI 61 EU025 Temporary replacement conditions: The Permittee may temporarily replace EQUI61, provided the following conditions are met: 1) The potential emissions of the replacement unit (assuming all enforceable limits imposed through this permit, and aggregated if more than one engine is simultaneously replaced; see COMG1, EQUI60, and EQUI90) are less than all of the following: 25 tpy PM, 15 tpy PM < 10 microns, 10 tpy PM < 2.5 microns, 40 tpy VOC, 40 tpy SO2, 40 tpy NOx, 100 tpy CO, 75000 tpy CO2e; 2) The Permittee must calculate the allowable potential to emit of each temporary replacement engine assuming operating conditions that are enforceable by this permit. For pollutants not specifically limited by a permit or rule, the Permittee may use emission factors generated based on the temporary replacement engine manufacturer's performance tests; 3) The capacity of the replacement unit is less than or equal to the unit it replaces; 4) The project can only be the temporary replacement of internal combustion engines for the purpose of providing emergency electrical power at the facility; 5) Emissions and operating hours are tracked and calculated as specified in this permit; 6) The replacement engine may only replace a permanent engine that is temporarily out of service for less than one year; 7) The replacement engine must meet the conditions for temporary replacement units under 40 CFR Section 60.4200(e); 8) Prior to making such a change, the Permittee shall apply for and obtain the appropriate permit amendment. The Permittee is not required to complete emission calculations described in Minn. R. 7007.1200 subp. 2. A permit will still be needed regardless of the emissions increase if the change will be subject to a new applicable requirement or requires revisions to the limits or monitoring and recordkeeping in this permit. [40 CFR 60.4200(e), Minn. R. 7005.0100, subp. 35a, Minn. R. 7007.0800, Minn. R. 7007.1200, subp. 3, Minn. R. 7007.1250, Minn. R. 7007.1450, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2) and Minn. R. 7007.3000]

EQUI 61 EU025 The replacement engine may not be operated at the same time as the permanent unit it is replacing, except for up to 8 hours during start-up and shutdown transition periods. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2) and Minn. R. 7007.3000]

EQUI 61 EU025 If the replacement engine does not require a permit amendment, the Permittee shall keep the following records on site for each replacement engine not requiring a permit amendment: - Records required by Minn. R. 7007.1200, subp. 4; - The dates the temporary engine was installed, started operation, and was removed; - Filled form GI05B for each replacement engine with an assigned consecutive emission unit number; - A unique identification for the unit, such as make, model, and serial number; - Rated capacity and type of engine; - Dates and hours of operation of the engine; - A statement of all periods of operation during which the permanent engine being temporarily replaced is not also operating; and - Calculations of the potential to emit of the engine and emission changes pursuant to Minn. R. 7007.1200 subpart 3. [Minn. R. 7007.1200, subp. 4, , Minn. R. 7007.0800, subp. 2]

EQUI 61 EU025 The Permittee shall notify the MPCA if the replacement engine is operated simultaneously with the permanent engine being temporarily replaced, except as allowed by this permit. Make verbal notification within 2 days, and written notification with the semi-annual deviations report. [Minn. R. 7007.1200, subp. 4, Minn. R. 7007.0800, subp. 5]

EQUI 62 EU027 Sulfur Dioxide <= 0.20 pounds per million Btu heat input 30-day rolling average. This limit applies at all times except during periods of startup, shutdown, or malfunction. Potential emissions based on combustion of natural gas at equipment capacity is approximately 0.0006 lb/MMBtu. [40 CFR 60.43Da(b)(2), 40 CFR 60.43Da(g), 40 CFR 60.48Da(a), Minn. R. 7011.0560]

EQUI 62 EU027 Nitrogen Oxides <= 1.6 pounds per megawatt-hour 30-day rolling average (gross energy output). This limit applies at all times except during periods of startup, shutdown, or malfunction. [40 CFR 60.44Da(a)(1), 40 CFR 60.48Da(a), Minn. R. 7011.0560]

EQUI 62 EU027 Operating Hours <= 1500 hours per year 12-month rolling sum. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

EQUI 62 EU027 Sulfur Content of Fuel <= 0.004 grains per dry standard cubic foot 12-month rolling average. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2) and Minn. R. 7007.3000]

EQUI 62 EU027 Fuel usage is limited to pipeline quality natural gas. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2) and Minn. R. 7007.3000]

EQUI 62 EU027 Daily Recordkeeping. On each day of operation, the Permittee shall calculate, record, and maintain the EQUI62 operating hours. [Minn. R. 7007.0800, subp. 5, Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

EQUI 62 EU027 Monthly Recordkeeping: Hours of operation By the 15th of the month, the Permittee shall calculate and record the following: 1) The total hours of operation for the previous calendar month using the daily records; and 2) The 12-month rolling sum of operating hours for the previous 12-month period by summing the monthly operating hours for the previous 12 months. [Minn. R. 7007.0800, subps. 4-5]

EQUI 62 EU027 The Permittee shall determine the mass rate (lb/h) of NOx emissions by installing, operating, and maintaining continuous fuel flowmeters following the appropriate measurements procedures specified in appendix D of 40 CFR Part 75. The emission rate (E) of NOx shall be computed using the following equation: E = (ER x H) / O Where: E = Emission rate of NOx from the duct burner, in lb/MWh gross energy output ER = Average hourly emission rate of NOx exiting the steam generating unit heat input calculated using appropriate F factor as described in Method 19 of appendix A of 40 CFR Part 60, in lb/MMBtu H = Average hourly heat input rate of entire combined cycle unit, in MMBtu/h O = Average hourly gross energy output from entire combined cycle unit, in MW. [40 CFR 60.48Da(k)(2)(iv), Minn. R. 7011.0560]


EQUI 90 EU028 Sulfur Dioxide <= 0.50 pounds per million Btu heat input The potential to emit from the unit is 0.05 lb/MMBtu due to equipment design and allowable fuel. [Minn. R. 7011.2300, subp. 2]

EQUI 90 EU028 Sulfur Content of Fuel <= 0.050 percent by weight. [Minn. R. 7007.0800, subps. 4-5] EQUI 90 EU028 Fuel type: Distillate fuel oil only, by design [Minn. R. 7005.0100, subp. 35a]

EQUI 90 EU028 Fuel Supplier Certification: The Permittee shall obtain supplier certification that the sulfur content does not exceed 0.050 % by weight. The certification shall be a single certification from the fuel oil supplier guaranteeing a maximum sulfur content in all fuel oil deliveries thereafter. The single certification shall also state that the supplier will notify the Permittee in writing on the date of delivery of fuel oil with a sulfur content exceeding the guaranteed maximum, that the fuel oil sulfur content exceeds the guaranteed maximum value. The Permittee may instead choose to test the oil in the storage tank following each shipment, according to current ASTM or EPA methods and keep records of lab analyses of sulfur content. [Minn. R. 7007.0800, subps. 4-5]

EQUI 90 EU028 Hours of Operation: The Permittee shall maintain documentation on site that the unit is an emergency generator by design that qualifies under the U.S. EPA memorandum entitled "Calculating Potential to Emit (PTE) for Emergency Generators" dated September 6, 1995, limiting operation to 500 hours per year. [Minn. R. 7007.0800, subps. 4-5]

EQUI 90 EU028 The Permittee shall at all times operate and maintain the engine, including any associated air pollution control equipment or monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions. The general duty to minimize emissions does not require any further efforts to reduce emissions if levels required by Subpart ZZZZ have been achieved. Determination of whether such operation and maintenance procedures are being used will be based on information available to the Administrator which may include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the source. [40 CFR 63.6605(b), Minn. R. 7011.8150]

EQUI 90 EU028 The Permittee shall meet the following 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; c. Inspect all hoses and belts every 500 hours of operation or annually, whichever comes first, and replace as necessary. [40 CFR 63.6602, 40 CFR pt. 63, Subp. ZZZZ(Table 2c), Minn. R. 7011.8150]

EQUI 90 EU028 During periods of startup, the Permittee shall minimize the engine's time spent at idle and minimize the engine's startup time at startup to a period needed for appropriate and safe loading of the engine, not to exceed 30 minutes, after which time the non-startup emission limits apply. [40 CFR 63.6602, 40 CFR 63.6625(h), 40 CFR pt. 63, Subp. ZZZZ(Table 2c), Minn. R. 7011.8150]

EQUI 90 EU028 The Permittee has the option of utilizing an oil analysis program in order to extend the specified oil change requirement in Table 2C to Subpart ZZZZ. The oil analysis must be performed at the same frequency specified in Table 2C. The analysis program must at a minimum analyze the Total Base Number, viscosity, and percent water content. The condemning numbers for these parameters are as follows: Total Base Number is less than 30 percent of the Total Base Number of the oil when new; viscosity of the oil has changed by more than 20 percent from the viscosity of the oil when new; or percent water content (by volume) is greater than 0.5. If none of the condemning values are exceeded, the Permittee is not required to change the oil. If any of the condemning limits are exceeded, the Permittee shall change the oil within 2 days of receiving the results of the analysis; if the engine is not in operation when the results are received, the Permittee shall change the oil within 2 days or before commencing operation, whichever is later. The Permittee shall keep records of the parameters that are analyzed as part of the program, the results of the analysis, and the oil changes for the engine. The analysis program must be part of the maintenance plan for the engine. [40 CFR 63.6625(i), 40 CFR pt. 63, subp. ZZZZ(Table 2C), Minn. R. 7011.8150]

EQUI 90 EU028 The Permittee shall operate and maintain the engine and after-treatment control device (if any) according to the manufacturer's emission-related written instructions or develop a maintenance plan which must provide to the extent practicable for the maintenance and operation of the engine in a manner consist with good air pollution control practice for minimizing emissions. [40 CFR 63.6625(e), Minn. R. 7011.8150]

EQUI 90 EU028 The Permittee shall install a non-resettable hour meter if one is not already installed. [40 CFR 63.6625(f), Minn. R. 7011.8150]

EQUI 90 EU028 The Permittee shall be in continuous compliance with the applicable requirements of Table 2C to 40 CFR pt. 63, Subpart ZZZZ. [40 CFR 63.6640(a), Minn. R. 7011.8150]

EQUI 90 EU028 The Permittee shall report each instance in which the applicable operating limitation was not met. These instances are deviations from the operating limitations in 40 CFR pt. 63, Subpart ZZZZ. These deviations shall be reported according to the requirements of 40 CFR Section 63.6650. [40 CFR 63.6640(b), Minn. R. 7011.8150]

EQUI 90 EU028 The Permittee must operate the emergency stationary RICE according to the requirements in 40 CFR Section 63.6640(f)(1), (f)(2)(i), and (f)(4). In order for the engine to be considered an emergency stationary RICE under 40 CFR pt. 63, subpart ZZZZ, any operation other than emergency operation, maintenance and testing, and operation in non-emergency situations for 50 hours per year, as described in 40 CFR Section 63.6640(f)(1)(i) and (f)(4), is prohibited. If the Permittee does not operate the engine according to the requirements in 40 CFR Section 63.6640(f), the engine will not be considered an emergency engine under this subpart and must meet all requirements for non-emergency engines. [40 CFR 63.6640(f), Minn. R. 7011.8150]

EQUI 90 EU028 There is no time limit on the use of emergency stationary RICE in emergency situations. [40 CFR 60.6640(f)(1), Minn. R. 7011.8150]

EQUI 90 EU028 The Permittee may operate the emergency stationary RICE for the purposes specified in 40 CFR Section 63.6640(f)(2)(i) for a maximum of 100 hours per calendar year. Any operation for non-emergency situations as allowed by 40 CFR Section 63.6640(f)(3) counts as part of the 100 hours per calendar year. On May 1st, 2015, the District Court of Columbia Circuit Court vacated the provisions of 40 CFR Section 63.6640(f)(2) that allow operation of an emergency generator without emissions controls for up to 100 hours per year as part of an emergency demand-response program. On May1, 2016 the D.C Circuit Court's mandate to vacate the provision became effective, therefore the Permittee may not operate according to the provisions at 40 CFR Section 63.6640(f)(2)(ii) or (f)(2)(iii) as part of the 100 hours per calendar year. [40 CFR 63.6640(f)(2), Minn. R. 7011.8150]

EQUI 90 EU028 The Permittee may operate the emergency stationary RICE for maintenance checks and readiness testing, provided that the tests are recommended by federal, state or local government, the manufacturer, the vendor, the regional transmission organization or equivalent balancing authority and transmission operator, or the insurance company associated with the engine. The Permittee may petition the Administrator for approval of additional hours to be used for maintenance checks and readiness testing, but a petition is not required if the Permittee maintains records indicating that federal, state, or local standards require maintenance and testing of emergency RICE beyond 100 hours per calendar year. [40 CFR 63.6640(f)(2)(i), Minn. R. 7011.8150]

EQUI 90 EU028 The Permittee may operate the emergency stationary RICE for up to 50 hours per calendar year in non-emergency situations. The 50 hours of operation in non-emergency situations are counted as part of the 100 hours per calendar year for maintenance and testing provided in 40 CFR Section 63.6640(f)(2). The 50 hours per year for non-emergency situations cannot be used for peak shaving or to generate income for a facility to supply power to an electric grid or otherwise supply power as part of a financial arrangement with another entity. [40 CFR 63.6640(f)(3), Minn. R. 7011.8150]

EQUI 90 EU028 The Permittee shall keep records of the maintenance conducted on the stationary RICE in order to demonstrate that the engine and after-treatment control device (if any) was operated and maintained according to the maintenance plan. [40 CFR 63.6655(e), Minn. R. 7011.8150]

EQUI 90 EU028 The Permittee shall keep records of all engine operating hours, and record whether the use was emergency operation, maintenance and testing, or non-emergency operation. [Minn. R. 7007.0800, subp. 5]

EQUI 90 EU028 Records shall be in a form suitable and readily available for expeditious review according to 40 CFR Section 63.10(b)(1). Each record shall be kept for 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. Each record shall be accessible in hard copy or electronic form. [40 CFR 63.6660(a)-(c), Minn. R. 7011.8150]

EQUI 90 EU028 The following parts of the General Provisions apply: 40 CFR Sections 63.1, 63.2, 63.3, 63.4, 63.5, 63.6(a), 63.6(c)(1)-(2), 63.6(f)(2)-(3), 63.6(g)(1)-(3), 63.6(i), 63.6(j), 63.7(a)(3), 63.8(a)(1), 63.8(b)(1), 63.9(a), 63.10(a), 63.10(b)(1), 63.10(b)(2)(vi)-(xii), 63.10(b)(2)(xiv), 63.10(b)(3), 63.12, 63.13, 63.14, and 63.15. [40 CFR 63.6665, Minn. R. 7011.8150]

EQUI 90 EU028 The Permittee shall report each instance in which the applicable General Provisions, listed above, were not met. [40 CFR 63.6640(e), Minn. R. 7011.8150]

EQUI 90 EU028 Temporary replacement conditions: The Permittee may temporarily replace EQUI90, provided the following conditions are met: 1) The potential emissions of the replacement unit (assuming all enforceable limits imposed through this permit, and aggregated if more than one engine and/or boiler is simultaneously replaced; see COMG1) are less than all of the following: 25 tpy PM, 15 tpy PM < 10 microns, 10 tpy PM < 2.5 microns, 40 tpy VOC, 40 tpy SO2, 40 tpy NOx, 100 tpy CO, 75000 tpy CO2e; 2) The Permittee must calculate the allowable potential to emit of each temporary replacement engine assuming operating conditions that are enforceable by this permit. For pollutants not specifically limited by a permit or rule, the Permittee may use emission factors generated based on the temporary replacement engine manufacturer's performance tests. 3) The capacity of the replacement unit is less than or equal to the capacity of EQUI90; 4) The project can only be the temporary replacement of the internal combustion engine for the purpose of providing emergency electrical power at the facility; 5) Emissions and operating hours are tracked and calculated as specified in this permit; 6) The replacement engine may only replace EQUI90 when EQUI90 is temporarily out of service for less than one year; 7) The equipment must meet all other requirements for EQUI90 OR the replacement engine may not be on site for more than 1 year and must meet the conditions for temporary replacement units under 40 CFR Section 60.4200(e); and 8) Prior to making such a change, the Permittee shall apply for and obtain the appropriate permit amendment as applicable. The Permittee is not required to complete emission calculations described in Minn. R. 7007.1200 subp. 2. A permit will still be needed regardless of the emissions increase if the change will be subject to a new applicable requirement or requires revisions to the limits or monitoring and recordkeeping in this permit. [40 CFR 60.4200(e), Minn. R. 7005.0100, subp. 35a, Minn. R. 7007.0800, Minn. R. 7007.1200, subp. 3, Minn. R. 7007.1250, Minn. R. 7007.1450, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2) and Minn. R. 7007.3000]

EQUI 90 EU028 The replacement engine may not be operated at the same time as EQUI90, except for up to 8 hours during start-up and shutdown transition periods. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2) and Minn. R. 7007.3000]

EQUI 90 EU028 If the replacement engine does not require a permit amendment, the Permittee shall keep the following records on site for each replacement engine: - Records required by Minn. R. 7007.1200, subp. 4; - The dates the temporary engine was installed, started operation, and was removed; - Filled form GI05B for each replacement engine with an assigned consecutive emission unit number; - A unique identification for the unit, such as make, model, and serial number; - Rated capacity and type of engine; - Dates and hours of operation of the engine; - A statement of all periods of operation during which EQUI90 is not also operating; and - Calculations of the potential to emit of the engine and emission changes pursuant to Minn. R. 7007.1200 subpart 3. [Minn. R. 7007.0800, subp. 2, Minn. R. 7007.1200, subp. 4, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2) and Minn. R. 7007.3000]

EQUI 90 EU028 The Permittee shall notify the MPCA if the replacement engine is operated simultaneously with EQUI90, except as allowed by this permit. Make verbal notification within 2 days, and written notification with the semi-annual deviations report. [Minn. R. 7007.0800, subp. 5, Minn. R. 7007.1200, subp. 4]

EQUI 91 EU029 Recordkeeping: By the last day of each calendar month, the Permittee shall record the amount of natural gas combusted in the boilers during the previous calendar month. These records shall consist of purchase records, receipts, or fuel meter readings. [40 CFR 60.48c(g), Minn. R. 7011.0570]

EQUI 91 EU029 The Permittee shall maintain records required by 40 CFR pt. 60, subp. Dc for a period of two years following the date the record was made. [40 CFR 60.48c(i), Minn. R. 7011.0570]

EQUI 91 EU029 Recordkeeping: The Permittee shall maintain a file of all measurements, maintenance, reports and records for at least five years. This requirement is more stringent than 40 CFR Section 60.7(f), which specifies two years. [40 CFR 60.7(f), Minn. R. 7007.0800, subp. 5(C), Minn. R. 7019.0100, subp. 1]

EQUI 91 EU029 At all times, including periods of startup, shutdown, and malfunction, the Permittee shall, to the extent practicable, maintain and operate EQUI91 in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the MPCA which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. [40 CFR 60.11(d), Minn. R. 7017.2015]

EQUI 91 EU029 Recordkeeping: The Permittee shall maintain records of the occurrence and duration of any startup, shutdown, or malfunction in the operation of the facility including; any malfunction of the air pollution control equipment; or any periods during which a continuous monitoring system or monitoring device is inoperative. [40 CFR 60.7(b), Minn. R. 7019.0100, subp. 1]

EQUI 91 EU029 The Permittee shall submit a notification of any physical or operational change which increases emission rate: due 60 days (or as soon as practical) before the change is commenced. [40 CFR 60.7(a)(4), Minn. R. 7019.0100, subp. 1]

EQUI 91 EU029 The affected source of 40 CFR pt. 63, subp. DDDDD is the collection at a major source of all existing industrial, commercial, and institutional boilers and process heaters within a subcategory as defined in 40 CFR Section 63.7575. These units are part of the subcategory "units designed to burn gas 1 fuels". [40 CFR 63.7490]

EQUI 91 EU029 The Permittee must conduct a tune-up of the boiler or process heater annually as specified in 40 CFR Section 63.7540. [40 CFR 63.7500(a)(1), 40 CFR pt. 63, subp. DDDDD(Table 3)]

EQUI 91 EU029 Boilers in the "units designed to burn gas 1 fuels" subcategory are not subject to the emission limits in Table 1 and 2 or 11 through 13 of 40 CFR pt. 63, subpart DDDDD or the operating limits in Table 4 of the subpart. [40 CFR 63.7500(e)]

EQUI 91 EU029 At all times, the Permittee must operate and maintain any affected source, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions. Determination of whether such operation and maintenance procedures are being used will be based on information available to the Administrator that may include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the source. [40 CFR 63.7500(a)(3)]

EQUI 91 EU029 Circumvention. The Permittee shall not build, erect, install, or use any article, machine, equipment, or process to conceal an emission that would otherwise constitute noncompliance with a relevant standard. Such concealment includes, but is not limited to: (1) The use of diluents to achieve compliance with a relevant standard based on the concentration of a pollutant in the effluent discharged to the atmosphere; or (2) The use of gaseous diluents to achieve compliance with a relevant standard for visible emissions. [40 CFR 60.12, 40 CFR 63.4(b), Minn. R. 7011.0050, Minn. R. 7011.7000]

EQUI 91 EU029 The standards under 40 CFR Section 63.7500 apply at all times the affected unit is operating, except during periods of startup and shutdown during which time the Permittee must comply only with Table 3 to Subpart DDDDD of Part 63. [40 CFR 63.7500(f)]

EQUI 91 EU029 The Permittee must be in compliance with the work practice standards in 40 CFR pt. 63, subp. DDDDD. [40 CFR 63.7505(a)]

EQUI 91 EU029 The Permittee must conduct the first annual tune-up no later than 13 months after the initial startup of the boiler. Thereafter each annual tune-up specified in 40 CFR Section 63.7540(a)(10) must be no more than 13 months after the previous tune-up. [40 CFR 63.7510(g), 40 CFR 63.7515(d)]

EQUI 91 EU029 The Permittee must conduct an annual tune-up of the boiler or process heater to demonstrate continuous compliance as specified below: 1. As applicable, inspect the burner, and clean or replace any components of the burner as necessary (the Permittee may delay the burner inspection until the next scheduled unit shutdown). Units that produce electricity for sale may delay the burner inspection until the first outage, not to exceed 36 months from the previous inspection. At units where entry into a piece of process equipment or into a storage vessel is required to complete the tune-up inspections, inspections are required only during planned entries into the storage vessel or process equipment; 2. Inspect the flame pattern, as applicable, and adjust the burner as necessary to optimize the flame pattern. The adjustment should be consistent with the manufacturer's specifications, if available; 3. Inspect the system controlling the air-to-fuel ratio, as applicable, and ensure that it is correctly calibrated and functioning properly (the Permittee may delay the inspection until the next scheduled unit shutdown). Units that produce electricity for sale may delay the inspection until the first outage, not to exceed 36 months from the previous inspection; 4. Optimize total emissions of CO. This optimization should be consistent with the manufacturer's specifications, if available, and with any NOx requirement to which the unit is subject; 5. Measure the concentrations in the effluent stream of CO in parts per million, by volume, and oxygen in volume percent, before and after the adjustments are made (measurements may be either on a dry or wet basis, as long as it is the same basis before and after the adjustments are made). Measurements may be taken using a portable CO analyzer; and 6. Maintain on-site and submit, if requested by the Administrator, an annual report containing the information below: i. The concentrations of CO in the effluent stream in parts per million by volume, and oxygen in volume percent, measured at high fire or typical operating load, before and after the tune-up of the boiler or process heater; ii. A description of any corrective actions taken as a part of the tune-up; and iii. The type and amount of fuel used over the 12 months prior to the tune-up, but only if the unit was physically and legally capable of using more than one type of fuel during that period. Units sharing a fuel meter may estimate the fuel used by each unit. [40 CFR 63.7540(a)(10)]

EQUI 91 EU029 If the unit is not operating on the required date for a tune-up, the tune-up must be conducted within 30 calendar days of startup. [40 CFR 63.7540(a)(13)]

EQUI 91 EU029 The Permittee must submit a Notification of Compliance Status for each boiler or process heater before the close of business on the 60th day following the completion of all initial compliance demonstrations for all boiler or process heaters at the facility. The Notification of Compliance Status report must contain all the information specified below: 1. A description of the affected unit(s) including identification of which subcategories the unit is in, the design heat input capacity of the unit, a description of the add-on controls used on the unit to comply with this subpart, description of the fuel(s) burned, including whether the fuel(s) were a secondary material determined by the Permittee or the EPA through a petition process to be a non-waste under 40 CFR Section 241.3, whether the fuel(s) were a secondary material processed from discarded non-hazardous secondary materials within the meaning of 40 CFR Section 241.3, and justification for the selection of fuel(s) burned during the compliance demonstration. 2. A signed certification that the Permittee has met all applicable emission limits and work practice standards. 3. If there was a deviation from any emission limit, work practice standard, or operating limit, submit a description of the deviation, the duration of the deviation, and the corrective action taken in the Notification of Compliance Status report. 4. In addition to the information required in 40 CFR Section 63.9(h)(2), the notification of compliance status must include the following certification(s) of compliance, as applicable, and signed by a responsible official: i. This facility complies with the required initial tune-up according to the procedures in 40 CFR Section 63.7540(a)(10)(i) through (vi). ii. This facility has had an energy assessment performed according to 40 CFR Section 63.7530(e). [40 CFR 63.7530(f), 40 CFR 63.7545(a), 40 CFR 63.7545(e)(1)-(8), 40 CFR 63.9(h)(2)(ii), Minn. R. 7019.0100]

EQUI 91 EU029 Notification of Compliance Status Contents: The notification shall be signed by the responsible official who shall certify its accuracy, and shall list: 1. The methods that were used to determine compliance; 2. The results of any performance tests, opacity or visible emission observations, continuous monitoring system (CMS) performance evaluations, and/or other monitoring procedures or methods that were conducted; 3. The methods that will be used for determining continuing compliance, including a description of monitoring and reporting requirements and test methods; 4. The type and quantity of hazardous air pollutants emitted by the source (or surrogate pollutants if specified in the relevant standard), reported in units and averaging times and in accordance with the test methods specified in the relevant standard; 5. If the relevant standard applies to both major and area sources, an analysis demonstrating whether the affected source is a major source (using the emissions data generated for this notification); 6. A description of the air pollution control equipment (or method) for each emission point, including each control device (or method) for each hazardous air pollutant and the control efficiency (percent) for each control device (or method); and 7. A statement by the owner or operator of the affected existing source as to whether the source has complied with the relevant standard or other requirements. [40 CFR 63.7545(a), 40 CFR 63.9(h)(2)(i)(A)-(G), Minn. R. 7019.0100]

EQUI 91 EU029 The Permittee must submit a signed statement in the Notification of Compliance Status report that indicates that a tune-up of the boiler or process heater was conducted. [40 CFR 63.7530(d)]

EQUI 91 EU029 Compliance Report: The Permittee shall submit a compliance status report : Due annually, by the 31st of January. The first compliance report must cover the period beginning on the startup date of the boiler (12/5/2015) and ending on December 31, 2016. The first annual compliance report must be postmarked or submitted no later than January 31, 2017. Each subsequent compliance report must cover the applicable 1-year period from January 1 to December 31 and postmarked or submitted no later than January 31. [40 CFR 63.7495(a), 40 CFR 63.7550(a)-(b), 40 CFR pt. 63, subp. DDDDD(Table 9)]

EQUI 91 EU029 A Compliance Report must contain the following: 1. Company and Facility name and address; 2. Date of report and beginning and ending dates of the reporting period; 3. The total operating time during the reporting period; 4. The date of the most recent tune-up. Include the date of the most recent burner inspection if it was not done annually and was delayed until the next scheduled or unscheduled unit shutdown. 5. If there were no deviations from the requirements for work practice standards for periods of startup and shutdown in Table 3 of 40 CFR pt. 63, subp. DDDDD that apply, include a statement that there were no deviations from the emission limitations and work practice standards during the reporting period. [40 CFR 63.7550(b), 40 CFR 63.7550(a), 40 CFR pt. 63, subp. DDDDD(Table 9)]

EQUI 91 EU029 The Permittee must submit all reports required by 40 CFR pt. 63, subp. DDDDD, Table 9 electronically using CEDRI that is accessed through the EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). However, if the reporting form specific to 40 CFR pt. 63, subp. DDDDD is not available in CEDRI at the time that the report is due, the Permittee must submit the report to the Administrator at the appropriate address listed in 40 CFR Section 63.13. At the discretion of the Administrator, you must also submit these reports, to the Administrator in the format specified by the Administrator. [40 CFR 63.7550(h)(3)]

EQUI 91 EU029 The Permittee must keep records of each notification and report that is submitted to comply with 40 CFR pt. 63, subp. DDDDD, including all documentation supporting any Initial Notification or Notification of Compliance Status or biennial compliance report that is submitted, according to the requirements in 40 CFR Section 63.10(b)(2)(xiv). [40 CFR 63.7555(a)(1)]

EQUI 91 EU029 The Permittee must maintain records of the calendar date, time, occurrence and duration of each startup and shutdown and the types and amounts of fuels used during each startup and shutdown. [40 CFR 63.7555(i), 40 CFR 63.7555(j)]

EQUI 91 EU029 Recordkeeping: The Permittee shall maintain files of all information required by 40 CFR pt. 63 in a form suitable and readily available for expeditious inspection and review. The files should be retained for at least 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. Only the most recent two years of information must be kept on site. [40 CFR 63.10(b)(1), 40 CFR 63.7560, Minn. R. 7019.0100, subp. 2(B)]

EQUI 91 EU029 The Permittee shall maintain, at a minimum, the following information in the files: The occurrence and duration of each startup, shutdown, or malfunction of operation when the startup or shutdown causes the source to exceed any applicable emission limitation in the relevant emission standards. [40 CFR 63.10(b)(2)(i), Minn. R. 7019.0100, subp. 2(B)]

EQUI 92 EU030 This source is subject to the U.S. EPA Acid Rain Program codified at 40 CFR pts. 72, 73, and 75. Combustion turbine EQUI92 is a utility unit that also is a gas-fired unit and a new unit, as defined in 40 CFR Section 72.2. The Permittee's application for an acid rain permit for the combustion turbines is attached in Appendix D to this permit. [40 CFR pt. 72, 40 CFR pt. 73, 40 CFR pt. 75]

EQUI 92 EU030 The Permittee shall comply with the applicable Acid Rain emissions limitation for sulfur dioxide. [40 CFR 72.9(c)(1)(ii), 40 CFR 72.9(g)(4)]

EQUI 92 EU030 The Permittee shall hold allowances as of the allowance transfer deadline, in the unit's compliance subaccount, not less than the total annual emissions of sulfur dioxide for the previous calendar year. Allowances shall be held in, deducted from, or transferred among Allowance Tracking System accounts in accordance with the Acid Rain Program. [40 CFR 72.9(c)(1)(i), 40 CFR 72.9(g)(4)]

EQUI 92 EU030 If EQUI92 has excess emissions, the designated representative shall submit a proposed offset plan in accordance with 40 CFR Section 72.9(e). [40 CFR 72.9(e)]

EQUI 92 EU030 The Permittee shall certify Acid Rain Program submittals. Each submission under the Acid Rain Program shall be submitted, signed, and certified by the designated representative or the alternative designated representative for all sources on behalf of which the submission is made in accordance with 40 CFR Section 72.21. [40 CFR 72.21, 40 CFR 72.22]

EQUI 92 EU030 The Permittee shall keep on site or readily accessible at another site each of the following documents for a period of 5 years from the date the document is created: - The certificate of representation; - All emission monitoring information; - Copies of all reports, compliance certifications, and other submissions or records made under the Acid Rain Program; and - Copies of all documents used to complete an acid rain permit application. [40 CFR 72.9(f)(1)]

EQUI 92 EU030 The Permittee shall apply for Acid Rain Program Permit reissuance: The designated representative shall submit a complete Acid Rain permit application for each source with an affected unit at least 6 months prior to the expiration of an existing Acid Rain Permit in accordance with 40 CFR Section 72.30(c). [40 CFR 72.30(c)]

EQUI 92 EU030 [Stage 1] The Permittee must commence construction of EQUI92 prior to August 16, 2020. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

EQUI 92 EU030 [Stage 1] The shakedown period for EQUI92 is defined as the period of time commencing on the date of initial startup and terminating: 1. 180 days after initial startup of the unit; 2. 60 days after achieving maximum production of EQUI92; or 3. Upon submittal of successful compliance test and CEMS certification reports for EQUI92; whichever date is earliest. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2) (i) and Minn. R. 7007.3000]

EQUI 92 EU030 [Stage 1] The Permittee shall limit Heat Input <= 6458 trillion Btu per year 12-month rolling sum basis. This limit does not apply until after the shakedown period ends. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

EQUI 92 EU030 Heat Input: [Stage 1] Monthly Recordkeeping: By the 15th of the month, the Permittee shall calculate and record the following: 1) The total heat input (MMBtu) for EQUI92 for the previous calendar month, by multiplying the total fuel usage for the previous calendar month by the energy content of the fuel. The energy content used can be the content listed on fuel supplier specifications, or assumed to be 1020 Btu/scf. 2) The 12 month rolling sum heat input for the previous 12 month period by summing the monthly heat input data for the previous 12 months. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

EQUI 92 EU030 [Stage 1] The Permittee shall limit Start-up Shut-down (SUSD) Operating Hours <= 260 hours per year 12-month rolling sum basis to be calculated by the 15th day of each month for the previous 12-month period as described later in this permit. This limit does not apply until after the shakedown period ends. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

EQUI 92 EU030 Operating Hours: [Stage 1] Daily Recordkeeping: For each SUSD event the Permittee shall record and maintain a record of the start time and stop time of the event. A startup event begins when fuel flow to the combustion chamber starts, and ends when the control parameter "L8MECL" reads "TRUE". A shutdown event begins when the control parameter "L8MECL" reads "FALSE", and ends when fuel flow to the combustion chamber ceases. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

EQUI 92 EU030 Operating Hours: [Stage 1] Monthly Recordkeeping: By the 15th of the month, the Permittee shall calculate and record the following: 1) The total amount of time spent in SUSD mode for the previous calendar month using the SUSD event record. 2) The 12-month rolling sum of SUSD hours for the previous 12-month period by summing the SUSD monthly hours for the previous 12 months. [Minn. R. 7007.0800, subps. 4-5]

EQUI 92 EU030 [Stage 1] Fuel type: Natural gas only. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

EQUI 92 EU030 [Stage 1] The Permittee shall maintain purchase records for all fuel used at EQUI92 demonstrating that the turbine combusts natural gas only. The Permittee shall maintain these records as specified in 40 CFR Section 60.7(b) and (f) and under 40 CFR pt. 75, subp. F. [40 CFR 60.5520(d), 40 CFR 60.5520(d)(1), 40 CFR 60.5525, 40 CFR 60.5535(a), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

EQUI 92 EU030 The Permittee shall limit Sulfur Dioxide <= 0.060 pounds per million Btu heat input (26.0 nanograms SO2 per Joule of heat input). [40 CFR 60.4330(a)(2)]

EQUI 92 EU030 The Permittee shall limit Nitrogen Oxides <= 4.7 pounds per megawatt-hour 4-hour rolling average (96 ppm by volume at 15 percent O2 or 590 nanograms per Joule of useful output) when turbine is operating at less than 75 percent of peak load or operating at ambient temperature less than 0 degrees Fahrenheit. [40 CFR 60.4320(a), 40 CFR pt. 60, subp. KKKK(Table1)]

EQUI 92 EU030 The Permittee shall limit Nitrogen Oxides <= 0.43 pounds per megawatt-hour 4-hour rolling average (15 ppm at 15% Oxygen or 54 nanograms per Joule of useful output) when EQUI92 is operating at greater than or equal to 75 percent of peak load and operating at temperatures greater than or equal to 0 degrees Fahrenheit. [40 CFR 60.4320(a), 40 CFR pt. 60, subp. KKKK(Table 1)]

EQUI 92 EU030 The Permittee shall limit Carbon Dioxide <= 120 pounds per million Btu heat input (50 kilograms carbon dioxide per gigajoule of heat input). [40 CFR 60.5520(a), 40 CFR 60.5520(b)]


EQUI 92 EU030 Sulfur Dioxide <= 0.50 pounds per million Btu heat input The potential to emit from the unit is 0.0034 lb/MMBtu due to equipment design and allowable fuel. [Minn. R. 7011.2300, subp. 2]

EQUI 92 EU030 The Permittee shall operate and maintain EQUI92, TREA39, EQUI93, and EQUI94 in a manner consistent with good air pollution control practices for minimizing emission at all times including during startup, shutdown, and malfunction. [40 CFR 60.4333(a)]

EQUI 92 EU030 [Stage 1] The Permittee shall install, calibrate, maintain, and operate a continuous monitoring system (CEMS) consisting of a NOx monitor and diluent gas (oxygen) monitor, to determine the hourly NOx emission rate in parts per million (ppm) or pound per million British thermal units (lb/MMBtu). Additional requirements for the NOx CEMS are at COMG11. The Permittee shall install, calibrate, maintain, and operate a fuel flow meter to continuously measure the heat input to EQUI92. The Permittee shall install, calibrate, maintain, and operate a watt meter to continuously measure the gross electrical output of EQUI92. [40 CFR 60.4335(b)(1)-(3), 40 CFR 60.4340(b), Minn. R. 7017.1006, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

EQUI 92 EU030 Each fuel flowmeter shall be installed, calibrated, maintained, and operated according to the manufacturer's instructions. Alternatively, with state approval, fuel flowmeters that meet the installation, certification, and quality assurance requirements of 40 CFR pt. 75, Appendix D are acceptable for use under 40 CFR pt. 60, subp. KKKK. [40 CFR 60.4345(c)]

EQUI 92 EU030 The Permittee shall install, calibrate, maintain, and operate each watt meter according to manufacturer's instructions. [40 CFR 60.4345(d)]

EQUI 92 EU030 The Permittee may elect not to monitor the total sulfur content of the fuel combusted in the turbine, if the fuel is demonstrated not to exceed potential sulfur emissions of 26 ng SO2/J (0.060 lb SO2/MMBtu) heat input. The Permittee must use one of the following sources of information to make this demonstration: (a) The fuel quality characteristics in a current, valid purchase contract, tariff sheet or transportation contract for the fuel, specifying that the total sulfur content for natural gas use is 20 grains of sulfur or less per 100 standard cubic feet; or (b) Representative fuel sampling data which show that the sulfur content of the fuel does not exceed 26 ng SO2/J (0.060 lb SO2/MMBtu) heat input. At a minimum, the amount of fuel sampling data specified in 40 CFR pt. 75, Appendix D, Section 2.3.1.4 or 2.3.2.4 is required. [40 CFR 60.4365]

EQUI 92 EU030 Nitrogen Oxides The Permittee shall conduct initial performance test : Due 180 calendar days after Initial Startup Date. The performance test shall be conducted as specified in 40 CFR Section 60.4400(a)(1)(i) or (ii), or as an alternative, the initial performance test may be performed using NOx-diluent CEMS as described in 40 CFR Section 60.4405. [40 CFR 60.4400(a)(1), 40 CFR 60.4400(b)(5), 40 CFR 60.4405, 40 CFR 60.8, Minn. R. 7017.2015, subp. 2(A)]

EQUI 92 EU030 The Permittee must conduct an initial performance test for NOx, as required in 40 CFR Section 60.8 (except as specified in 40 CFR Section 60.8(a)(1), (a)(2), (a)(3), and (a)(4)), using one of the following methodologies for each test run: (i) Measure the NOx concentration (in ppm), using EPA Method 7E or EPA Method 20 of 40 CFR pt. 60, Appendix A. For units complying with the output based standard, concurrently measure the stack gas flow rate, using EPA Methods 1 and 2 of 40 CFR pt. 60, Appendix A and measure and record the electrical and thermal output from the unit. Then, use the Equation 5 in 40 CFR Section 60.4395(a)(1)(i) to calculate the NOx emission rate; or (ii) Measure the NOx and diluent gas concentrations, using either EPA Methods 7E and 3A, or EPA Method 20 of 40 CFR pt. 60, Appendix A. Concurrently measure the heat input to the unit, using a fuel flowmeter (or flowmeters), and measure the electrical and thermal output of the unit. Use EPA Method 19 in 40 CFR pt. 60, Appendix A to calculate the NOx emission rate in lb/MMBtu. Then, use Equations 1 and, if necessary, 2 and 3 in 40 CFR Section 60.4350(f) to calculate the NOx emission rate in lb/MWh. Sampling traverse points shall be selected as described at 40 CFR Section 60.440(a)(2) or (3). The performance test must be done at any load condition within plus or minus 25 percent of 100 percent of peak load. The Permittee may perform testing at the highest achievable load point, if at least 75 percent of peak load cannot be achieved in practice. The Permittee must conduct three separate test runs for each performance test with a minimum time per run of 20 minutes. Compliance with the applicable emission limit in 40 CFR Section 60.4320 must be demonstrated at each tested load level. Compliance is achieved if the three-run arithmetic average NOx emission rate at each tested level meets the applicable emission limit in 40 CFR Section 60.4320. The ambient temperature must be greater than zero degrees F during the performance test. [40 CFR 60.4400(a)(1)-(3), 40 CFR 60.4400(b), 40 CFR 60.4400(b)(4), 40 CFR 60.4400(b)(6)]

EQUI 92 EU030 The performance evaluation of the CEMS may be conducted either separately from the initial performance test or (as described in 40 CFR 60.4405) as part of the initial performance test. [40 CFR 60.4400(b)(5)]

EQUI 92 EU030 As an alternative to the performance testing requirements at 40 CFR Section 60.4400 the initial performance test may be performed using NOx-diluent CEMS as follows: a) Perform a minimum of nine RATA reference method runs with a minimum time per run of 21 minutes, at a single load level, within plus or minus 25 percent of 100 percent of peak load. The ambient temperature must be greater than 0 degrees F during the RATA runs. b) For each RATA run, concurrently measure the heat input to the unit using a fuel flow meter (or flow meters) and measure the electrical and thermal output from the unit. c) Use the test data both to demonstrate compliance with the applicable NOx emission limit under 40 CFR 60.4320 and to provide the required reference method data for the RATA of the CEMS described in 40 CFR Section 60.4335. d) Compliance with the applicable emission limit in 40 CFR section 4320 is achieved if the arithmetic average of all of the NOx emission rates for the RATA runs, expressed in units of ppm or lb/MWh, does not exceed the emission limit. [40 CFR 60.4405]

EQUI 92 EU030 Sulfur Dioxide The Permittee shall conduct initial performance test : Due 180 calendar days after Initial Startup Date. The Permittee must conduct an initial performance test, as required in 40 CFR Section 60.8 (except as specified in 40 CFR Section 60.8(a)(1), (a)(2), (a)(3), and (a)(4)) for sulfur dioxide. Subsequent SO2 performance tests shall be conducted on an annual basis (no more than 14 calendar months following the previous performance test). The Permittee must use one of following three methodologies to conduct the performance tests: (1) If the Permittee chooses to periodically determine the sulfur content of the fuel combusted in the turbine, a representative fuel sample must be collected following ASTM D5287 (incorporated by reference, see 40 CFR Section 60.17) for natural gas. The fuel analyses may be performed either by the Permittee, a service contractor retained by the Permittee, the fuel vendor, or any other qualified agency. Analyze the samples for the total sulfur content of the fuel using ASTM D1072, or alternatively D3246, D4084, D4468, D4810, D6228, D6667, or Gas Processors Association Standard 2377 (all of which are incorporated by reference, see 40 CFR Section 60.17). (2) The Permittee may measure the SO2 concentration (in parts per million (ppm)), using EPA Methods 6, 6C, 8, or 20 in 40 CFR pt. 60, Appendix A. In addition, the American Society of Mechanical Engineers (ASME) standard, ASME PTC 19-10-1981-Part 10, "Flue and Exhaust Gas Analyses," manual methods for sulfur dioxide (incorporated by reference) can be used instead of EPA Methods 6 or 20. For units complying with the output based standard, concurrently measure the stack gas flow rate, using EPA Methods 1 and 2 in 40 CFR pt. 60, Appendix A, and measure and record the electrical and thermal output from the unit. Then use Equation 6 at 40 CFR Section 60.4415(a)(2) to calculate the SO2 emission rate. (3) The Permittee may measure the SO2 and diluent gas concentrations, using either EPA Methods 6, 6C, or 8 and 3A, or 20 in 40 CFR pt. 60, Appendix A. In addition, you may use the manual methods for sulfur dioxide ASME PTC 19-10-1981-Part 10 (incorporated by reference, see 40 CFR Section 60.17). Concurrently measure the heat input to the unit, using a fuel flowmeter (or flowmeters), and measure the electrical and thermal output of the unit. Use EPA Method 19 in 40 CFR pt. 60, Appendix A to calculate the SO2 emission rate in lb/MMBtu. Then, use Equations 1 and, if necessary, 2 and 3 in 40 CFR Section 60.4350(f) to calculate the SO2 emission rate in lb/MWh. [40 CFR 60.4415(a), 40 CFR 60.8, Minn. R. 7017.2015, subp. 2(A)]

EQUI 92 EU030 The Permittee shall conduct performance tests required by 40 CFR pt. 60, subp. KKKK according to the general performance testing requirements at 40 CFR Section 60.8(c)-(i). [40 CFR 60.8(c)-(i), Minn. R. 7017.2015, subp. 2(A)]

EQUI 92 EU030 If a force majeure is about to occur, occurs, or has occurred for which the Permittee intends to assert a claim of force majeure, the Permittee shall submit written notification as soon as practicable following the date the Permittee first knew, or through due diligence should have known that the event may cause or caused a delay in testing beyond the regulatory deadline, but the notification must occur before the performance test deadline unless the initial force majeure or a subsequent force majeure event delays the notice, and in such cases, the notification shall occur as soon as practicable. [40 CFR 60.8(a)(1), Minn. R. 7017.2015, subp. 2(A)]

EQUI 92 EU030 The Permittee shall provide a written description of the force majeure event and a rationale for attributing the delay in testing beyond the regulatory deadline to the force majeure; describe the measures taken or to be taken to minimize the delay; and identify a date by which the Permittee proposes to conduct the performance test. The performance test shall be conducted as soon as practicable after the force majeure occurs. [40 CFR 60.8(a)(2), Minn. R. 7017.2015, subp. 2(A)]

EQUI 92 EU030 The decision as to whether or not to grant an extension to the performance test deadline is solely within the discretion of the Administrator. The Administrator will notify the Permittee in writing of approval or disapproval of the request for an extension as soon as practicable. [40 CFR 60.8(a)(3), Minn. R. 7017.2015, subp. 2(A)]

EQUI 92 EU030 Until an extension of the performance test deadline has been approved by the Administrator under 40 CFR Section 60.8(a)(1), (a)(2), and (a)(3), the Permittee remains strictly subject to the requirements of 40 CFR pt. 60. [40 CFR 60.8(a)(4), Minn. R. 7017.2015, subp. 2(A)]

EQUI 92 EU030 The Permittee shall submit a notification of date construction began : Due 30 calendar days after Date of Construction Start. Submit the name and number of the Subject Item and the date construction began. [40 CFR 60.7(a)(1), Minn. R. 7019.0100, subp. 1]

EQUI 92 EU030 The Permittee shall submit a notification of the actual date of initial startup : Due 15 calendar days after Initial Startup Date. [40 CFR 60.7(a)(3), Minn. R. 7019.0100, subp. 1]

EQUI 92 EU030 The Permittee shall submit a notification of any physical or operational change which increases emission rate: due 60 days (or as soon as practical) before the change is commenced. [40 CFR 60.7(a)(4), Minn. R. 7019.0100, subp. 1]

EQUI 92 EU030 Recordkeeping: The Permittee shall maintain records of the occurrence and duration of any startup, shutdown, or malfunction in the operation of the facility including; any malfunction of the air pollution control equipment; or any periods during which a continuous monitoring system or monitoring device is inoperative. [40 CFR 60.7(b), Minn. R. 7019.0100, subp. 1]

EQUI 92 EU030 Recordkeeping: The Permittee shall maintain a file of all measurements, maintenance, reports and records for at least five years. This requirement is more stringent than 40 CFR Section 60.7(f), which specifies two years. [40 CFR 60.7(f), Minn. R. 7007.0800, subp. 5(C), Minn. R. 7019.0100, subp. 1]

EQUI 92 EU030 At all times, including periods of startup, shutdown, and malfunction, the Permittee shall, to the extent practicable, maintain and operate any affected facility including associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Administrator which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. [40 CFR 60.11(d), Minn. R. 7017.2015, subp. 2(B)]

EQUI 92 EU030 For the purpose of submitting compliance certifications or establishing whether or not the Permittee has violated or is in violation of any standard in this part, nothing in this part shall preclude the use, including the exclusive use, of any credible evidence or information, relevant to whether a source would have been in compliance with applicable requirements if the appropriate performance or compliance test or procedure had been performed. [40 CFR 60.11(g), Minn. R. 7017.2015, subp. 2(B)]

EQUI 92 EU030 The Permittee shall not build, erect, install, or use any article, machine, equipment or process, the use of which conceals an emission which would otherwise constitute a violation of an applicable standard. Such concealment includes, but is not limited to, the use of gaseous diluents to achieve compliance with an opacity standard or with a standard which is based on the concentration of a pollutant in the gases discharged to the atmosphere. [40 CFR 60.12, Minn. R. 7011.0050]

EQUI 92 EU030 The Permittee shall furnish the Administrator within 60 days of completion two or, upon request, more copies of a written report of the results of the performance evaluation. [40 CFR 60.13(c)(2), Minn. R. 7017.1010, subp. 1(A)]

EQUI 92 EU030 Transport Rule (TR) NOx Annual Trading Program Requirements The Permittee shall comply with the TR NOx Annual Trading Program requirements contained in permit Appendix C. [40 CFR 97.430-435]

EQUI 92 EU030 Designated representative requirements: The Permittee shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with 40 CFR Section 97.413 through 97.418. [40 CFR 97.406(a)]

EQUI 92 EU030 1.) The Permittee and the designated representative, of each TR NOx Annual source and each TR NOx Annual unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of 40 CFR Section 97.430 (general requirements, including installation, certification, and data accounting, compliance deadlines, reporting data, prohibitions, and long-term cold storage), 40 CFR Section 97.431 (initial monitoring system certification and recertification procedures), 40 CFR Section 97.432 (monitoring system out-of-control periods), 40 CFR Section 97.433 (notifications concerning monitoring), 40 CFR Section 97.434 (recordkeeping and reporting, including monitoring plans, certification applications, quarterly reports, and compliance certification), and 40 CFR Section 97.435 (petitions for alternatives to monitoring, recordkeeping, or reporting requirements). 2.) The emissions data determined in accordance with 40 CFR Section 97.430 through 97.435 shall be used to calculate allocations of TR NOx Annual allowances under 40 CFR Section 97.411(a)(2) and (b) and 40 CFR Section 97.412 and to determine compliance with the TR NOx Annual emissions limitation and assurance provisions under paragraph 40 CFR Section 97.406(c) below, provided that, for each monitoring location from which mass emissions are reported, the mass emissions amount used in calculating such allocations and determining such compliance shall be the mass emissions amount for the monitoring location determined in accordance with 40 CFR Section 97.430 through 97.435 and rounded to the nearest ton, with any fraction of a ton less than 0.50 being deemed to be zero. [40 CFR 97.406(b)]

EQUI 92 EU030 TR NOx Annual emissions limitation. i.) As of the allowance transfer deadline for a control period in a given year, the Permittee shall hold, in the source's compliance account, TR NOx Annual allowances available for deduction for such control period under 40 CFR Section 97.424(a) in an amount not less than the tons of total NOx emissions for such control period from all TR NOx 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 NOx Annual source are in excess of the TR NOx Annual emissions limitation set forth in 40 CFR Section 97.406(c)(1)(i) above, then: A. The Permittee shall hold the TR NOx Annual allowances required for deduction under 40 CFR Section 97.424(d); and B. The Permittee shall pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act, and each ton of such excess emissions and each day of such control period shall constitute a separate violation of 40 CFR part 97, subpart AAAAA and the Clean Air Act. [40 CFR 97.406(c)(1)]

EQUI 92 EU030 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 Annual 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 having a common designated representative for such control period, where the common designated representative's share of such NOx emissions during such control period exceeds the common designated representative's assurance level for the state and such control period, shall hold (in the assurance account established for the owners and operators of such group) TR NOx Annual allowances available for deduction for such control period under 40 CFR Section 97.425(a) in an amount equal to two times the product (rounded to the nearest whole number), 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 exceeds the common designated representative's assurance level divided by the sum of the amounts, determined for all common designated representatives for such sources and units in the Minnesota and Indian country within the borders of Minnesota for such control period, by which each common designated representative's share of such NOx emissions exceeds the respective common designated representative's assurance level; and (B) The amount by which total NOx emissions from all TR NOx Annual units at TR NOx Annual sources in Minnesota and Indian country within the borders of Minnesota for such control period exceed the state assurance level. ii.) The Permittee shall hold the TR NOx Annual allowances required under 40 CFR Section 97.406(c)(2)(i) above, as of midnight of November 1 (if it is a business day), or midnight of the first business day thereafter (if November 1 is not a business day), immediately after such control period. iii.) Total NOx emissions from all TR NOx Annual units at TR NOx Annual sources in Minnesota and Indian country within in the borders of Minnesota during a control period in a given year exceed the state assurance level if such total NOx emissions exceed the sum, for such control period, of the state NOx Annual trading budget under 40 CFR 97.410(a) and the state's variability limit under 40 CFR 97.410(b). iv.) It shall not be a violation of 40 CFR part 97, subpart AAAAA or of the Clean Air Act if total NOx emissions from all TR NOx Annual units at TR NOx Annual sources in Minnesota and Indian country within the borders of Minnesota during a control period exceed the state assurance level or if a common designated representative's share of total NOx emissions from the TR NOx Annual units at TR NOx Annual sources in the Minnesota and Indian country within the borders of Minnesota during a control period exceeds the common designated representative's assurance level. v.) To the extent the Permittee fails to hold TR NOx Annual allowances for a control period in a given year in accordance with 40 CFR Section 97.406(c)(2)(i) through (iii) above, A. The Permittee shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and B. Each TR NOx Annual allowance that the Permittee fails to hold for such control period in accordance with 40 CFR Section 97.406(c)(2)(i) through (iii) above and each day of such control period shall constitute a separate violation of 40 CFR part 97, subpart AAAAA and the Clean Air Act. [40 CFR 97.406(c)(2)(i)-(v)]

EQUI 92 EU030 Compliance periods. i) A TR NOx Annual unit shall be subject to the requirements under 40 CFR 97.406(c)(1) above for the control period starting on the later of January 1, 2015, or the deadline for meeting the unit's monitor certification requirements 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 97.406(c)(2) above for the control period starting on the later of January 1, 2017 or the deadline for meeting the unit's monitor certification requirements under 40 CFR 97.430(b) and for each control period thereafter. [40 CFR 97.406(c)(3)]

EQUI 92 EU030 Vintage of allowances held for compliance. i). A TR NOx Annual allowance held for compliance with the requirements under 40 CFR 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 such control period or a control period in a prior year. ii). A TR NOx Annual allowance held for compliance with the requirements under 40 CFR 97.406(c)(1)(ii)(A) and (2)(i) through (iii) above for a control period in a given year must be a TR NOx Annual allowance that was allocated for a control period in a prior year or the control period in the given year or in the immediately following year. [40 CFR 97.406(c)(4)]

EQUI 92 EU030 Allowance Management System requirements. Each TR NOx Annual allowance shall be held in, deducted from, or transferred into, out of, or between Allowance Management System accounts in accordance with 40 CFR part 97, subpart AAAAA. [40 CFR 97.406(c)(5)]

EQUI 92 EU030 Limited authorization. A TR NOx Annual allowance is a limited authorization to emit one ton of NOx during the control period in one year. 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; and ii) Notwithstanding any other provision of 40 CFR part 97, the Administrator has the authority to terminate or limit the use and duration of such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act. [40 CFR 97.406(c)(6)]

EQUI 92 EU030 Property right. A TR NOx Annual allowance does not constitute a property right. [40 CFR 97.406(c)(7)] EQUI 92 EU030 Additional recordkeeping and reporting requirements. 1.) Unless otherwise provided, the Permittee

shall keep on site at the source each of the following documents (in hardcopy or electronic format) for a period of 5 years from the date the document is created. This period may be extended for cause, 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 source and each TR NOx Annual unit at the source and all documents that demonstrate the truth of the statements in the certificate of representation; provided that the certificate and documents shall be retained on site at the source beyond such 5-year period until such certificate of representation and documents are superseded because of the submission of a new certificate of representation under 40 CFR 97.416 changing the designated representative. ii.) All emissions monitoring information, in accordance with 40 CFR part 97, subpart AAAAA. iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the TR NOx Annual Trading Program. 2.) The designated representative of a TR NOx Annual source and each TR NOx Annual unit at the source shall make all submissions required under the TR NOx Annual Trading Program, except as provided in 40 CFR Section 97.418. This requirement does not change, create an exemption from, or otherwise affect the responsible official submission requirements under a title V operating permit program in 40 CFR parts 70 and 71. [40 CFR 97.406(e)]

EQUI 92 EU030 Liability. 1.) Any provision of the TR NOx Annual Trading Program that applies to a TR NOx Annual source or the designated representative of a TR NOx Annual source shall also apply to the Permittee. 2.) Any provision of the TR NOx Annual Trading Program that applies to a TR NOx Annual unit or the designated representative of a TR NOx Annual unit shall also apply to the Permittee. [40 CFR 97.406(f)]

EQUI 92 EU030 Effect on other authorities. No provision of the TR NOx Annual Trading Program or exemption under 40 CFR Section 97.405 shall be construed as exempting or excluding the Permittee, and the designated representative, of a TR NOx Annual source or TR NOx Annual unit from compliance with any other provision of the applicable, approved state implementation plan, a federally enforceable permit, or the Clean Air Act. [40 CFR 97.405]

EQUI 92 EU030 TR SO2 Group 2 Trading Program Requirements The Permittee shall comply with the TR SO2 Group 2 Trading Program Requirements contained in permit Appendix C. [40 CFR 97.730-735]

EQUI 92 EU030 Designated representative requirements. The Permittee shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with 40 CFR Section 97.713 through 97.718. [40 CFR 97.706(a)]

EQUI 92 EU030 Emissions monitoring, reporting, and recordkeeping requirements. 1.) The Permittee, and the designated representative, of each TR SO2 Group 2 source and each TR SO2 Group 2 unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of 40 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 (initial monitoring system certification and recertification procedures), 40 CFR Section 97.732 (monitoring system out-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, and compliance certification), and 40 CFR Section 97.735 (petitions for alternatives to monitoring, recordkeeping, or reporting requirements). 2.) The emissions data determined in accordance with 40 CFR Section 97.730 through 97.735 shall be used to calculate allocations of TR SO2 Group 2 allowances under 40 CFR 97.711(a)(2) and (b) and 40 CFR Section 97.712 and to determine compliance with the TR SO2 Group 2 emissions limitation and assurance provisions under 40 CFR Section 97.706(c) below, provided that, for each monitoring location from which mass emissions are reported, the mass emissions amount used in calculating such allocations and determining such compliance shall be the mass emissions amount for the monitoring location determined in accordance with 40 CFR Section 97.730 through 97.735 and rounded to the nearest ton, with any fraction of a ton less than 0.50 being deemed to be zero. [40 CFR 97.706(b)]

EQUI 92 EU030 TR SO2 Group 2 emissions limitation. i.) As of the allowance transfer deadline for a control period in a given year, the Permittee shall hold, in the source's compliance account, TR SO2 Group 2 allowances available for deduction for such control period under 40 CFR Section 97.724(a) in an amount not less than the tons of total SO2 emissions for such control period from 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 SO2 Group 2 source are in excess of the TR SO2 Group 2 emissions limitation set forth in paragraph 40 CFR Section 97.706(c)(1)(i) above, then: A.) The Permittee shall hold the TR SO2 Group 2 allowances required for deduction under 40 CFR Section 97.724(d); and B.) The Permittee shall pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act, and each ton of such excess emissions and each day of such control period shall constitute a separate violation of 40 CFR part 97, subpart DDDDD and the Clean Air Act. [40 CFR 97.706(c)(1)]

EQUI 92 EU030 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 Group 2 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 having a common designated representative for such control period, where the common designated representative's share of such SO2 emissions during such control period exceeds the common designated representative's assurance level for the state and such control period, shall hold (in the assurance account established for the owners and operators of such group) TR SO2 Group 2 allowances available for deduction for such control period under 40 CFR Section 97.725(a) in an amount equal to two times the product (rounded to the nearest whole number), as determined by the Administrator in accordance with 40 CFR Section 97.725(b), of multiplying— A.) The quotient of the amount by which the common designated representative's share of such SO2 emissions exceeds the common designated representative's assurance level divided by the sum of the amounts, determined for all common designated representatives for such sources and units in Minnesota and Indian country within the borders of Minnesota for such control period, by which each common designated representative's share of such SO2 emissions exceeds the respective common designated representative's assurance level; and B.) The amount by which total SO2 emissions from all TR SO2 Group 2 units at TR SO2 Group 2 sources in Minnesota and Indian country within the borders of Minnesota for such control period exceed the state assurance level. ii) The Permittee shall hold the TR SO2 Group 2 allowances required under 40 CFR Section 97.706(c)(2)(i) above, as of midnight of November 1 (if it is a business day), or midnight of the first business day thereafter (if November 1 is not a business day), immediately after such control period. iii.) Total SO2 emissions from all TR SO2 Group 2 units at TR SO2 Group 2 sources in Minnesota and Indian country within the borders of Minnesota during a control period in a given year exceed the state assurance level if such total SO2 emissions exceed the sum, for such control period, of the state SO2 Group 2 trading budget under 40 CFR Section 97.710(a) and the state's variability limit under 40 CFR Section 97.710(b). iv.) It shall not be a violation of 40 CFR part 97, subpart DDDDD or of the Clean Air Act if total SO2 emissions from all TR SO2 Group 2 units at TR SO2 Group 2 sources in Minnesota and Indian country within the borders of Minnesota during a control period exceed the state assurance level or if a common designated representative's share of total SO2 emissions from the TR SO2 Group 2 units at TR SO2 Group 2 sources in Minnesota and Indian country within the borders of Minnesota during a control period exceeds the common designated representative's assurance level. v.) To the extent the Permittee fails to hold TR SO2 Group 2 allowances for a control period in a given year in accordance with 40 CFR Section 97.706(c)(2)(i) through (iii) above, A.) The Permittee shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and B.) Each TR SO2 Group 2 allowance that the Permittee fails to hold for such control period in accordance with 40 CFR Section 97.706(c)(2)(i) through (iii) above and each day of such control period shall constitute a separate violation of 40 CFR part 97, subpart DDDDD and the Clean Air Act. [40 CFR 97.706(c)(2)(i)-(v)]

EQUI 92 EU030 i.) A TR SO2 Group 2 unit shall be subject to the requirements under 40 CFR Section 97.706(c)(1) above for the control period starting on the later of January 1, 2015 or the deadline for meeting the unit's monitor certification requirements under 40 CFR Section 97.730(b) and for each control period thereafter. ii.) A TR SO2 Group 2 unit shall be subject to the requirements under 40 Section CFR 97.706(c)(2) above for the control period starting on the later of January 1, 2017 or the deadline for meeting the unit's monitor certification requirements under 40 CFR Section 97.730(b) and for each control period thereafter. [40 CFR 97.706(c)(3)]

EQUI 92 EU030 Vintage of allowances held for compliance. i.) A TR SO2 Group 2 allowance held for compliance with the requirements under 40 CFR 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 such control 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 97.706(c)(1)(ii)(A) and (2)(i) through (iii) above for a control period in a given year must be a TR SO2 Group 2 allowance that was allocated for a control period in a prior year or the control period in the given year or in the immediately following year. [40 CFR 97.706(c)(4)]

EQUI 92 EU030 Allowance Management System requirements. Each TR SO2 Group 2 allowance shall be held in, deducted from, or transferred into, out of, or between Allowance Management System accounts in accordance with 40 CFR part 97, subpart DDDDD. [40 CFR 97.706(c)(5)]

EQUI 92 EU030 Limited authorization. A TR SO2 Group 2 allowance is a limited authorization to emit one ton of SO2 during the control period in one year. 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; and ii) Notwithstanding any other provision of 40 CFR part 97, subpart DDDDD, the Administrator has the authority to terminate or limit the use and duration of such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act. [40 CFR 97.706(c)(6)]

EQUI 92 EU030 Property right. A TR SO2 Group 2 allowance does not constitute a property right. [40 CFR pt. 97, 706(c)(7)]

EQUI 92 EU030 Additional recordkeeping and reporting requirements. 1.) Unless otherwise provided, the Permittee shall keep on site at the source each of the following documents (in hardcopy or electronic format) for a period of 5 years from the date the document is created. This period may be extended for cause, 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 source and each TR SO2 Group 2 unit at the source and all documents that demonstrate the truth of the statements in the certificate of representation; provided that the certificate and documents shall be retained on site at the source beyond such 5-year period until such certificate of representation and documents are superseded because of the submission of a new certificate of representation under 40 CFR Section 97.716 changing the designated representative. ii.) All emissions monitoring information, in accordance with 40 CFR part 97, subpart DDDDD. iii.) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the TR SO2 Group 2 Trading Program. 2.) The designated representative of a TR SO2 Group 2 source and each TR SO2 Group 2 unit at the source shall make all submissions required under the TR SO2 Group 2 Trading Program, except as provided in 40 CFR Section 97.718. This requirement does not change, create an exemption from, or otherwise affect the responsible official submission requirements under a title V operating permit program in parts 70 and 71. [40 CFR 97.706(e)]

EQUI 92 EU030 Liability. 1.) Any provision of the TR SO2 Group 2 Trading Program that applies to a TR SO2 Group 2 source or the designated representative of a TR SO2 Group 2 source shall also apply to the Permittee. 2.) Any provision of the TR SO2 Group 2 Trading Program that applies to a TR SO2 Group 2 unit or the designated representative of a TR SO2 Group 2 unit shall also apply to the Permittee. [40 CFR 97.706(f)]

EQUI 92 EU030 Effect on other authorities. No provision of the TR SO2 Group 2 Trading Program or exemption under 40 CFR Section 97.705 shall be construed as exempting or excluding the Permittee, and the designated representative, of a TR SO2 Group 2 source or TR SO2 Group 2 unit from compliance with any other provision of the applicable, approved state implementation plan, a federally enforceable permit, or the Clean Air Act. [40 CFR 97.706(g)]

TREA 37 CE032 Operate and maintain TREA37 at all times that EQUI1 and EQUI62 are in operation except during times of start-up, shutdown, or malfunction (as defined in EQUI1 and EQUI62). At all times, the Permittee shall maintain documentation of the operation of TREA37, and have it available for review at the stationary source. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2, Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

TREA 37 CE032 The Permittee shall operate and maintain the SCR in accordance with the Operation and Maintenance (O & M) Plan. The Permittee shall keep copies of the O & M Plan available onsite for use by staff and MPCA staff. [Minn. R. 7017.0200, Minn. R. 7007.0800, subp. 14, ]

TREA 37 CE032 SCR Monitoring: The total NOx as NO2 CEMS (EQUI44) shall be used to assess proper operation of the SCR. [40 CFR 64.7(a), Minn. R. 7007.0800, subp. 2, Minn. R. 7017.0200]

TREA 37 CE032 Nitrogen Oxides <= 4.5 parts per million on an instantaneous basis. NOx emissions in excess of this threshold shall be considered an excursion under 40 CFR Section 64.6(c)(2), for purposes of the NOx limits under EQUI1, EQUI62, and STRU32. This applies for all types and qualities of fuel burned. [40 CFR 64.3, Minn. R. 7017.0200]

TREA 37 CE032 Monitoring Equipment: The Permittee shall install and maintain the necessary monitoring equipment for measuring and recording ammonia injection rate as required by this permit. The monitoring equipment must be installed, in use, and properly maintained when the SCR is in operation. [Minn. R. 7007.0800, subp. 4, Minn. R. 7017.0200, ]

TREA 37 CE032 Continuous Monitoring: The Permittee shall monitor continuously, or at a minimum once every 15 minutes, monitor the total NOx as NO2 emissions in the exhaust. See Subject Item COMG3 for additional CEMs operating requirements. [40 CFR 64.3(b)(4)(ii), Minn. R. 7017.0200]

TREA 37 CE032 Periodic Inspections: At least semiannually, or more frequently as required by the manufacturer's specifications, the Permittee shall inspect the control equipment components. The Permittee shall maintain a written record of these inspections. [40 CFR 64.3, Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subps. 4-5, Minn. R. 7017.0200]

TREA 37 CE032 Corrective Actions: The Permittee shall take corrective action as soon as possible if any of the following occur: - The alarm is triggered for instantaneous NOx emissions of 4.5 ppm, outside of startup or shutdown; or - The SCR or any of its components are found during the inspections to need repair. Corrective actions shall return NOx emissions to within the permitted range, and/or include completion of necessary repairs identified during the inspection, as applicable. Corrective actions include, but are not limited to, those outlined in the O&M Plan for the SCR. The Permittee shall keep a record of the type and date of any corrective action taken for the SCR. [40 CFR 64.7(d)(1), Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subps. 4-5, Minn. R. 7017.0200]

TREA 37 CE032 Documentation of Need for Improved Monitoring: If the Permittee fails to achieve compliance with an emission limitation or standard for which the monitoring did not provide an indication of an excursion or exceedance while providing valid data, or the results of compliance or performance testing document a need to modify the existing ammonia injection rate, the Permittee shall promptly notify the MPCA and, if necessary, submit a permit amendment application to address the necessary monitoring changes. [Minn. R. 7017.0200, ]

TREA 37 CE032 As required by 40 CFR Section 64.9(a)(2), for the Semi-Annual Deviations Report requirements listed in Section 6 of this permit and/or the Notification of Deviations Endangering Human Health and the Environment listed earlier in Section 5 of this permit, as applicable, the Permittee shall include the following related to the monitoring identified as required by 40 CFR pt. 64: 1) Summary information on the number, duration, and cause of excursions or exceedances, as applicable, and the corrective action taken; and 2) Summary information on the number, duration, and cause for monitor downtime incidents. [40 CFR 64.9(a)(2), Minn. R. 7017.0200]

TREA 37 CE032 The Permittee shall maintain records of monitoring data, monitor performance data, corrective actions taken, and other supporting information required to be maintained. The Permittee may maintain records on alternative media, such as microfilm, computer files, magnetic tape disks, or microfiche, provided that the use of such alternative media allows for expeditious inspection and review, and does not conflict with other applicable recordkeeping requirements. [40 CFR 64.9(b), Minn. R. 7017.0200]

TSD AttachmentsAttachment 5: SI Detail Report

Xcel Energy Black Dog Generating PlantPermit Number: 03700003 101

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Oxy

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Prim

ary

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2000

Cont

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Mon

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TBD

TBD

TBD

Nitr

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Prim

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TBD

TBD

TBD

TBD

Cont

inuo

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Data

Acqu

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Diam

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Flow

Rate

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1M

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Up,

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STRU

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STRU

34SV

029

Auxi

liary

Boile

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52.

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000

300

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mbu

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ack

200

2328

6564

010

76M

anuf

actu

rer

Up,

No

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Fugi

tive

Emis

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sDe

scrip

tion

Subj

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lfac

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nas

soci

ate

with

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Cont

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Emiss

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Cont

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send

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Burn

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29/2

016

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