draft technical support document draft air emission permit

Technical Support Document, Permit Number: 06100004-008 of 70

Draft Technical Support Document For

Draft Air Emission Permit No. 06100004-008 This technical support document (TSD) is for parties interested in the draft permit and to meet the requirements set forth by the federal and state regulations (40 CFR § 70.7(a)(5) and Minn. R. 7007.0850, subp. 1). This document provides the legal and factual justification for each applicable requirement or policy decision considered in the 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)

Owner/Operator: Minnesota Power, a division of ALLETE, Inc., 30 Superior Street West Duluth, Minnesota 55802-2093 Co-owner: WPPI Energy 1425 Corporate Center Drive Sun Prairie, WI 535901-9109

Minnesota Power - Boswell Energy Center 1210 3rd Street NW Cohasset, Minnesota 55721-8706

Contact: Jeff McCulloch Phone: 218-355-3251

1.2 Facility description

Minnesota Power (Permittee) owns and operates the Boswell Energy Center (facility) located in Cohasset, Minnesota (WPPI Energy of Sun Prairie, Wisconsin (the co-Permittee) owns a 20% stake in Unit 4). The facility is composed of four pulverized coal-fired Electric Utility Steam Generators Units (EUSGU or EGU), as well as coal, ash, and reagent handling equipment, fugitive emission sources, and three emergency generators.

Unit 1 (dry bottom wall-fired) commenced construction in 1954 and operation in 1958, has a Continuous Emissions Monitoring System (CEMS)-based Normal Dependable Heat Input (refer to discussion of this term in Section 3.3) capacity of 1075 mmBtu per hour, and a gross output of 100 megawatts. Unit 2 (dry bottom wall-fired) commenced construction in 1956 and operation in 1960, has CEMS-based Normal Dependable Heat Input capacity of 910 mmBtu per hour, and a gross output of 100 megawatts. Unit 3 (dry bottom tangential-fired) commenced construction in 1970 and operation in 1973, has a CEMS-based Normal Dependable Heat Input capacity of 4425 mmBtu per hour, and a gross output of 450 megawatts. Unit 4 (dry bottom tangential-fired) commenced construction in 1978 and operation in 1980, has a CEMS-based Normal Dependable Heat Input capacity of 6800 mmBtu per hour, and a gross output of 690 megawatts. The boilers are currently fired with subbituminous coal.

All four boilers emit particulate matter (PM), PM less than 10 microns (PM10), PM less than 2.5 microns (PM2.5), sulfur dioxide (SO2), nitrogen oxides (NOX), carbon monoxide (CO), volatile organic compounds (VOC), sulfuric acid mist, mercury (Hg), and hazardous air pollutants (HAPs).


Units 1 and 2 each employ a fabric filter (FF) for PM, PM10, and PM2.5 control, and selective non-catalytic reduction (SNCR) with urea injection and rotating opposed-fired air (ROFA) controls for NOX control. Neither unit is equipped with add-on SO2 or Hg controls (but it is possible that calcium oxide in the ash reacts with SO2 in the flue gas to provide some SO2 reduction).

Unit 3 employs a FF for PM, PM10, and PM2.5 control, selective catalytic reduction (SCR) with ammonia injection, low-NOX burners, and overfire air controls for NOX control, wet flue gas desulfurization (FGD) for SO2 (and fluoride and hydrogen chloride) control, activated carbon injection (ACI) for Hg control, and good combustion practices for CO control. Unit 3 is subject to Best Available Retrofit Technology requirements at part 51, subp. P because it was not in operation prior to August 7, 1962, and was in existence on August 7, 1977.

Unit 4 employs a combined control device comprised of a FF for PM, PM10, and PM2.5 control and a semi-dry FGD for SO2 (and fluoride and hydrogen chloride) control, SNCR with urea injection, low-NOX burners, and overfire air controls for NOX control, ACI for Hg control, and good combustion practices for CO control .

1.3 Description of the activities allowed by this permit action

This permit action is a reissuance of the Part 70 operating permit. This permit action also includes requirements from a 2014 Consent Decree, federal pt. 63, subp. UUUUU Mercury and Air Toxics (MATS) requirements, requirements for the Control Of Mercury From Electric Generating Units at Minn. R. 7011.0561, requirements from the Mercury Emissions Reduction Act at Minn. Stat. Section 216B.68 - 216B.688, revision of Unit 3 and Unit 4 CO Best Available Control Technology (BACT) requirements, Unit 4 emergency generator replacement, pt. 97 Transport Rule requirements, and alternative boiler fuel test burn requirements.

This permit also includes requirements pertaining to a 2015 application (IND20150001) for increased FUGI11/COMG10 Coal Stockpile Material Handling (FUGI11 Existing Coal Drop Onto Pile Segment and FUGI11 Ten New Portable Conveyors/Eleven Drop Points Segment, as well as increased use of the existing sources Rail Receiving EQUI111, Coal Silo EQUI112, Coal Stockpile Maintenance FUGI6, Coal Stockpile Wind Erosion FUGI9, Unpaved Roads FUGI3).

1.4 Description of notifications and applications included in this action

Table 2. Notifications and applications included in this action Date received Application/Notification type and description 05/07/2007 Notification of Replacement of Controls (replace five existing fabric filters with single

fabric filter TREA46/CE045/DC-7 on EQUI111/EU035 rail coal receiving (formerly listed as an insignificant activity))

07/18/2007 Administrative Amendment (correction to former Unit 3 pollution control equipment emergency generator EU007 fuel type)

03/25/2008 Applicability Request (NOX reduction projects made under 40 CFR 52.21(r)(6)) 09/05/2008 Major Amendment (install larger Unit 3 pollution control equipment emergency

generator EU023/EQUI81) 07/03/2008 Notification of Installation of Controls (replace rotoclones on Units 1-3 coal bunkers

EQUI117/EU040 with fabric filter TREA51/CE050/DC-12) 09/15/2008 Major Amendment (natural gas-fired ignitor guns) 12/03/2008 Major Amendment (changes to CEMS) 02/05/2010 Major Amendment (Unit 4 NOX controls; IND20100002) 04/29/2010 Notification of Replacement of Controls (Crusher houses EQUI1/EU011 and


Date received Application/Notification type and description

EQUI102/EU012 coal handling fabric filters replaced by TREA37/CE007/DC-8 and TREA38/CE008/ DC-14, respectively; IND20100001)

10/15/2010 Major Amendment (Unit 3/EQUI100 fabric filter TREA9 CAM; IND20100007) 04/07/2011 Notification of Replacement of Controls (Replace EQUI114/EU037 coal transfer house

two fabric filters with new fabric filter TREA48/DC-16; IND20110002) 05/23/2011 Notification of Installation of Controls (Install TREA2/C044 fabric filter in

EQUI97/EU018 Fly Ash Loadout A - Truck Bay; IND20110001) 09/28/2011 09/29/2016

Part 70 Reissuance update including test burn requirements (IND20110004)

09/07/2012 Major Amendment (Unit 4/EQUI85 control equipment retrofit; IND20120001) 10/09/2012 Notification of Replacement of Equipment (replace Unit 3 failed emergency generator

EU009 with EQUI23/EU033; IND20150002) 03/31/2015 Major Amendment (Consent Decree requirements; IND20150002) 06/01/2015 Minor Amendment (Increase coal storage; add portable conveyors; IND20150001) 10/20/2015 Minor Amendment (replace Unit 4 emergency generator EU010 with EQUI119;

IND20150003) 12/26/2017 Major Amendment (revise EQUI85 and EQUI100 CO BACT requirements;

IND20170001)

1.5 Facility emissions

Table 3. Title I emissions summary – hybrid emissions test: Coal Stockpile Expansion Project (IND20150001)

Pollutant

Projected actual emissions * (tpy)

Baseline actual emissions ** (tpy)

Projected emissions increase prior to excludables (tpy)

Excludable emissions *** (tpy)

Projected emissions increase (including excludables) (tpy)

Unlimited Potential emissions **** (tpy)

Unlimited PTE plus projected emissions increase with excludables

Projected Limited emissions increase including excludables (tpy)

NSR significant thresholds for major sources (tpy)

NSR review required? (Yes/No)

PM 69.29 55.94 13.35 1.71 12.4 14.59 26.99 24.79 25 No PM10 15.22 13.30 1.93 0.81 2.81 6.90 9.71 8.67 15 No PM2.5 1.84 1.47 0.37 0.12 0.30 1.04 1.34 1.19 10 No Lead 4.02E-04 3.24E-04 7.79E-05 9.90E-06 7.20E-05 8.46E-05 1.57E-04 1.44E-04 0.6 No

*Projected actual emissions as defined in 40 CFR § 52.21(b)(41). **Baseline actual emissions as defined in 40 CFR § 52.21(b)(48). ***Emissions that can be excluded as detailed in 40 CFR § 52.21(b)(41)(ii)(c).

Note that for this project, the projected emissions increase prior to excludables, minus the excludable emissions will not equal the projected emissions increase including excludables. This is due to projected actual emissions minus baseline emissions that are less than excludable emissions for two of the existing sources affected by the project, so the projected actual emissions increase for these existing affected emission sources is zero and not a negative value. This applies to FUGI 11 existing coal stockpile material handling segment, and former insignificant activities EQUI 111 Rail Unloading & EQUI 112 Coal Storage Silo.

****Emissions from new portable coal stockpile conveyors (second segment of FUGI 11).

Refer to Section 3.1 Emission calculations for additional information regarding the Table 3 emissions data.

Table 4. Total facility potential to emit summary

PM tpy

PM10 tpy

PM2.5 tpy

SO2 tpy

NOX tpy

CO tpy

CO2e tpy

VOC tpy

Single HAP*

tpy

Total HAPs tpy


PM tpy

PM10 tpy

PM2.5 tpy

SO2 tpy

NOX tpy

CO tpy

CO2e tpy

VOC tpy

Single HAP*

tpy

Total HAPs tpy

Total facility limited potential emissions

1,446 1,934 1,686 7,561 6,484 7,623 1.22 E+07 198.8 157.3 316.9

Total facility actual emissions (2016)

779 1,525 974 3,644 4,314 3,703 8.80 E+06 67.7 **

*Single HAP = hydrogen fluoride ** Not reported in Minnesota emission inventory Table 5. Facility classification

Classification Major Synthetic minor/area Minor/Area

New Source Review X Part 70 X Part 63 X

1.6 Changes to Permit and Facility Data

As described above in Sections 1.3 and 1.4, the permit does authorize or incorporate certain specific modifications. In addition, the MPCA has a combined operating and construction permit program under Minnesota Rules Chapter 7007, and under Minn. R. 7007.0800, the MPCA has authority to include additional requirements in a permit. Under that authority, permit updates are made to reflect current MPCA templates and standard citation formatting, completed requirements and the requirements for removed equipment have been deleted as specified below, as well as the following additional changes are made as described below:

· Total Facility

§ The requirement to operate pollution control equipment whenever the corresponding process and emission units are operating was revised to acknowledge that operation of EQUI85 and EQUI100 (Units 4 and 3, respectively) mercury control equipment (TREA22 and TREA28, respectively) is not required when the respective boiler combusts only natural gas.

The requirement in permit No. 06100004-007 stated:

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

The revised requirement in permit No. 06100004-008 states:

Air Pollution Control Equipment: Operate all pollution control equipment whenever the corresponding process equipment and emission units are operated unless specified otherwise in this permit (refer to requirements 5.20.19 and 5.32.14 in subject items EQUI85 (Unit 4) and EQUI100 (Unit 3), respectively for specific requirements allowing EQUI85 and EQUI100 to operate without operating TREA22 and TREA28 mercury controls, respectively, only when firing only natural gas). [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B)].


Requirement background: Requiring operation of control equipment whenever the corresponding process equipment and emission units are operating ensures compliance with all applicable requirements at the time of permit issuance and is necessary to protect human health and the environment.

Minn. R. 7007.0800, subp. 2(A)&(B) state:

Subp. 2. Emission limitations and standards. The permit must:

A. include emissions limitations, operational requirements, and other provisions needed to ensure compliance with all applicable requirements at the time of permit issuance. For part 70 permits, the requirements and limitations must include approved replicable methodologies identified by the source in its permit application if approved by the commissioner, provided that no approved replicable methodologies shall contravene any terms needed to comply with any applicable requirement or requirement of this part or circumvent any applicable requirement that would apply as a result of implementing the approved replicable method;

B. include any condition the commissioner determines to be necessary to protect human health and the environment;

Minn. R. 7007.0800, subp. 16(J) states:

J. The permittee shall at all times properly operate and maintain the facilities and systems of treatment and control and the appurtenances related to them which are installed or used by the permittee to achieve compliance with the conditions of the permit. Proper operation and maintenance includes effective performance, adequate funding, adequate operator staffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures.

The permit control equipment operating requirement is derived from both Minn. R. 7007.0800, subp. 2(A)&(B) and Minn. R. 7007.0800, subp. 16(J). In certain situations, process equipment/emission units and control equipment can be installed without a permit. Operation of such controls is not required by Minn. R. 7007.0800, subp. 16(J) because the process equipment/emission unit and control equipment are not included in the permit. The inclusion of Minn. R. 7007.0800, subp. 2(A)&(B) in the requirement citation is necessary because requiring operation of control equipment whenever the corresponding process equipment/emission unit is operating regardless if the process equipment/emission unit and/or control equipment are in the permit, ensures compliance with all applicable requirements at the time of permit issuance and is necessary to protect human health and the environment.

Other Control Equipment Operating Requirements Revisions: Existing allowances for not operating EQUI82 and EQUI83 PM controls during startup were revised as discussed below under EQUI82 and EQUI83, to align with Consent Decree requirements for continuous operation of Units 1 and 2 PM control equipment to meet the applicable Consent Decree filterable PM limit. The Consent Decree also requires continuous operation of Units 3 and 4 PM, SO2, and NOX control equipment to meet the applicable Consent Decree filterable PM, SO2, and NOX limits. These requirements to continuously operate the control equipment are part of the applicable PM, SO2, and NOX limits under EQUI82, EQUI83, EQUI85, and EQUI100.


§ The igniter gun carbon monoxide (CO) limit and recordkeeping requirements were moved to COMG9 because the requirement applies to the four electric generating unit boilers and not to the entire facility.

§ Removed completed requirement to submit updated fugitive emissions control plan due to submittal of an updated plan on October 2, 2013. Note the 2013 plan was replaced by a September 18, 2015 plan revision prompted by the increased coal handling and coal pile storage 2015 minor amendment application to comply with 40 CFR Section 60.254(c) for FUGI9 (FS001) Coal Stockpile Wind Erosion and FUGI11 (FS006) Coal Stockpile Material Handling Including Segment For Coal Stockpile Material Handling Using Portable Conveyors. The September 2015 plan was subsequently updated in November 2017 and again in April 2018, and is attached as Appendix D to the permit.

§ SO2 re-modeling requirements based on the results of 2014 title V modeling for the 1-hour SO2 NAAQS were added to the permit. Also, requirements to repeat the 2014 modeling for the PM2.5 24-hour NAAQS were added to the permit because numerous 2014 PM2.5 modeling parameters were revised in the updated September 2016 title V reissuance application, and many of those revised parameters would increase ambient PM2.5 impacts. In addition, CO modeling requirements were updated to reflect current agency policy (refer to Section 3.2 modeling discussion below). Finally, parameters for circa 2007 Title V PM10, SO2, and NOX modeling were removed because numerous modeled parameters are no longer accurate and the results of that modeling were well below the relevant ambient air standard as discussed in Section 3.2.

§ Transport Rule requirements from part 97 were added to the permit (primarily as Appendix G)

§ The Fugitive Emissions Control Plan (FECP) was updated and requirements for updating the FECP were added. The requirements are based on 40 CFR §§ 60.254(c)(4)(ii) and 60.254(c)(5).

· COMG1 (GP 004) EGU SO2 Limits

§ Existing COMG1 1-hour SO2 modeling-based limits and citations were revised primarily based on staff review of October 19, 1987 and January 13, 1988 Air Quality Division memoranda. The memoranda from agency modeling staff to agency Air Quality management were a review of the 1987-1988 SO2 modeling results. The results indicated SO2 emissions at 4.0 lb/mmBtu (equal to the Minnesota Indirect Heating Equipment Rule (IHER) SO2 limit) did not cause exceedances of the SO2 National Ambient Air Quality Standard (NAAQS) 3-hour standard (at 40 CFR 50.5) or the Minnesota Ambient Air Quality Standard (MAAQS) 3-hour standard when EQUI82, EQUI83, and EQUI100 vent through STRU13. However, when EQUI82 and EQUI83 vent through STRU12, several 1-hour SO2 limits (1.18 lb/mmBtu limit for EQUI82 and EQUI83, and 2.97 lb/mmBtu for EQUI100) were necessary to protect the 1-hour SO2 MAAQS. SO2 limits applicable to EQUI100 and EQUI85 when EQUI82 and EQUI83 were not operating, were also outcomes of this modeling.

The EQUI82, EQUI83, and EQUI100 SO2 4.0 lb/hr limit on a 1-hour average was split into two distinct limits for each boiler: one 4.0 lb/mmBtu limit (3-hour average) based on the IHER limit, and a second 4.0 lb/mmBtu (1-hour average) derived from the 1980’s SO2 modeling.

The citation for the EQUI100 and EQUI85 SO2 limits (1-hour basis) composed of three sets (referred to as ‘Conditions’) of SO2 limits applicable when EQUI82 and


EQUI83 are not operating, was revised by removing ‘40 CFR pt. 50’ and changing ‘Minn. R. ch. 7009’ to ‘Minn. R. 7009.0020’. The revision was made because this set of three SO2 limits are the outcome of 1987-1988 modeling for demonstrating compliance with the 1-hour SO2 MAAQS (the 1-hour SO2 NAAQS was not promulgated until 2010.) Also, in lieu of citing ‘Minn. R. ch. 7009’, the more relevant citation is ‘Minn. R. 7009.0020’. The 1988 operating permit that contained these limits cited ‘Minn. R. 7005.0080’ which is now codified at Minn. R. 7009.0080 (the MAAQS). Minn. R. 7009.0020 is used in this permit because it is a requirement that prohibits emissions that cause or contribute to a violation of a MAAQS, (Minn. R. 7009.0080 is the 1-hour SO2 MAAQS).

The EQUI85 1.20 lb/mmBtu 1-hour SO2 limit based on 40 CFR 52.21(k) modeling, Best Available Control Technology (BACT), and New Source Performance Standard (NSPS) subp. D was corrected by creating a separate 1.20 lb/mmBtu limit on a 3-hour basis cited as BACT, 40 CFR 52.21(k) modeling, and NSPS subp. D, and revising the existing 1.20 lb/mmBtu 1-hour SO2 limit citation to Minn. R. 7009.0020, and clarifying that the 1-hour modeling-based limit applies when EQUI85 operates alone, or when EQUI82 and EQUI83 vent through STRU12 or when EQUI82, EQUI83, and EQUI100 vent through STRU13.

The memoranda and the SO2 limits revisions are discussed further in Section 3.2.a of this document.

§ The Unit 1, 2, and 3 (EQUI82, EQUI83, and EQUI100) requirement (based on Minn. R. 7011.0505, subp. 3) for determining the applicable SO2 limit when co-firing solid and liquid fuels was revised. The revised equation calculates the applicable limit when co-firing solid and gaseous fuels because the EGUs no longer combust liquid fuel.

§ Consent Decree SO2 limits and pt. 63, subp. UUUUU MATS hydrogen chloride and alternate SO2 limits were added to COMG1The EQUI85/Unit 4 0.33 lb/mmBtu annual average SO2 limit was removed because the basis for this limit (Minn. R. 7021.0050 and chapter 7021) was repealed in 2013 (because other state and federal requirements adequately address SO2 emissions and the standard is no longer needed for environmental protection).

§ The EQUI85 0.030 lb/mmBtu on a 365-day rolling average basis SO2 limit from PER007 was removed because the 0.030 lb/mmBtu on a 30-day rolling average basis Consent Decree SO2 limit is more restrictive.

§ The EQUI85 NSPS subp. D SO2 limit equation for calculating the applicable SO2 limit when solid and liquid fossil fuel were co-fired was removed because distillate fuel oil is no longer an EQUI85 fuel option. (The EQUI85 SO2 BACT limit (equal to the 1.2 lb/mmBtu NSPS limit for solid fossil fuel), was not revised because the BACT limit did not contain the equation that determines the SO2 limit when both solid and liquid fossil fuels are co-fired.)

§ Removed the EQUI100 0.09 lb/mmBtu SO2 limit (30-day rolling average; basis was Minn. R. 7007.0800, subp. 2) that was added to the permit by PER 003.

This limit was set to address anticipated Best Available Retrofit Technology (sometimes referred to as BART) requirements and was included in the Minnesota State Implementation Plan (SIP) December 31, 2009 SIP Revision submittal was sent to EPA. However, the MPCA intended to rely on the cap and trade features of the Clean Air Interstate Rule (CAIR) program instead of BART limits applicable to individual EGUs. Regardless, CAIR was remanded by the D.C. Circuit of the U.S. Court


of Appeals in December 2008 and stayed in Minnesota in December 2009. This lead Minnesota to rely on the source-specific BART determinations at that time for the 2009 Regional Haze SIP. In October 2011, EPA finalized the CAIR replacement known as the Cross State Air Pollution Rule (CSAPR), which is a cap and trade rule similar to CAIR. In December 2011, EPA proposed a rule to allow CSAPR as an alternative to the source-specific BART determinations. In July 2012, EPA approved Minnesota’s proposal to implement CSPAR in place of BART for EGUs. Although CSAPR was subject to additional court challenges, the rule remains in place and the case-by-case BART determinations are not applicable.

Finally, the EQUI100 0.030 lb/mmBtu (30-day rolling average) Consent Decree SO2 limit is more restrictive than the 0.09 lb/mmBtu SO2 limit (30-day rolling average) removed by this permit action.

· COMG3

§ Certain coal handling insignificant activities are now in the permit and associated fabric filters are subject to standard fabric filter monitoring requirements in COMG3.

§ Added particulate matter less than 10 microns (PM10) and particulate matter less than 2.5 microns (PM2.5) percent control efficiency requirements for TREA37/CE007, TREA38/CE008, TREA39/CE009, and TREA40/CE010 because the Permittee relies on the control efficiency for calculating PM10 and PM2.5 emissions from the sources controlled by these fabric filters.

§ Added PM2.5 percent control efficiency requirements for TREA41/CE013, TREA1/CE016, TREA42/CE017, and TREA43/CE018 because the Permittee relies on the control efficiency for calculating PM2.5 emissions from the sources controlled by these fabric filters.

§ Added Lead percent control efficiency requirement for all low temperature fabric filters that control coal dust and fly ash because coal dust and fly ash contain lead, and the Permittee relies on the control efficiency to calculate lead emissions from these sources.

§ Added TREA46/CE045, TREA47/CE046, TREA48/CE047, TREA49/CE048, TREA50/CE049, TREA51/CE050, and TREA52/CE051 to COMG3 and appropriate particulate matter (PM), PM10, PM2.5, and Lead control efficiencies. These fabric filters control coal-handling emission sources previously listed as insignificant activities in prior permits for the facility, and the Permittee uses the control efficiency for these pollutants in emissions calculations, so the control efficiencies must be requirements in the permit.

§ The citation for the requirement to operate and maintain TREA41/CE013 (EQUI99/EU015 Hg Additive Handling and Unit 3 PAC Silo Storage) was changed from a state requirement to a Title I Condition. The revision was necessary because TREA41 was installed as part of the Unit 3 control equipment retrofit (authorized by permit No. 06100004-003 issued March 28, 2007) that avoided a major Prevention of Significant Deterioration (PSD) modification for PM and PM10 (at that time PM10 was used as a surrogate for PM2.5 emissions and permitting). TREA41 is a fabric filter that controls PM and PM10 emissions to keep the modification non-major for PSD.

· COMG4 – added pt. 60, subp. D Continuous Opacity Monitoring System (COMS) requirement for measuring opacity, and revised Section 60.13(e) requirement for EQUI34 (EQUI85 COMS) to indicate the requirement only applies to EQUI34.


· COMG6 – added pt. 60, subp. D CEMS requirement for measuring EQUI85 SO2 and NOX and revised Section 60.13(e) requirement for EQUI53 and EQUI54 (EQUI85 SO2 AND NOX CEMS, respectively) to indicate the requirement only applies to EQUI53 and EQUI54.

· COMG7 – created this group for part 63, subp. UUUUU requirements.

· COMG8 – Created COMG8 for EQUI100 and EQUI85 carbon monoxide CEMS (EQUI71 and EQUI52, respectively) general requirements.

· COMG9

§ Moved Total Facility Igniter Gun CO limit and recordkeeping requirements to COMG9 and made the following changes:

§ References to oil combustion in igniter guns in the 319 tpy CO limit and recordkeeping requirements was removed because oil is no longer a permitted fuel option for the igniter guns.

§ The 319 tpy CO limit reference to an ‘Air Emissions Increase Analysis’ was corrected to an ‘Air Emissions Risk Analysis’ (AERA). This correction is based on the September 15, 2008 application for the igniter guns project that states the limit was designed to avoid the 100 tpy criteria pollutant increase threshold that would trigger an AERA. This limit was not designed to avoid a PSD major modification because actual-to-projected-actual emissions calculations indicated the largest projected increase (as a percent of the applicable PSD significant emission rate) would be for CO but was only 5.6 tpy.

§ Revised the 319 tpy CO limit and recordkeeping requirements by removing background information from the limit, and consolidating the recordkeeping activities into the recordkeeping requirement.

§ Added Test Burn requirements as requested by the Permittee.

§ Acid Rain Program requirements (other than boiler-specific NOX limits at each affected unit) were consolidated from each affected unit (EQUI82, EQUI83, EQUI100, and EQUI85) and the Total Facility subject item to COMG9.

· COMG10 – Created COMG10 to address the 2015 coal stockpile expansion project. COMG10 contains a single requirement that references recordkeeping and reporting requirements from § 52.21(r)(6) and Minn. R. 7007.0800, subps. 4 and 5 located under subject item TFAC1, and a list of affected subject items.

· Moved EQUI52 and EQUI71 (CO CEMS) requirements to COMG8 except for ongoing requirements for cylinder gas audits, relative accuracy test audits, and CEMS recertification.

· EQUI81/EU023 Unit 3 APCE 300 kW Emergency Generator

§ Requirement from Section 60.4211(c) that incorrectly referred to Section 52.05(b) was corrected to reference Section 60.4205(b).

§ Removed requirement based on Section 60.4207(c) because this regulation (regarding the use of non-compliant diesel fuel) was repealed.

§ Removed completed CO BACT stack test requirement

§ Revised requirements to reflect the May 4, 2016 D.C. Circuit Court of Appeals remand of Sections 60.4211(f)(2)(ii) and (iii) back to EPA.

· EQUI82, EQUI83, EQUI100, and EQUI85


§ Permitted Fuels: Removed distillate fuel oil because the oil ignitors were converted to natural gas. Also removed various items such as wastewater treatment sludge, boiler cleaning agents, and oily floor dry because although these materials may be nonhazardous secondary materials, they have not been evaluated according to the requirements of 40 CFR pt. 241 to determine if they are solid waste. Used oil as a fuel has been curtailed to incidental amounts of oil spillage/loss from coal handling equipment onto the coal.

§ Normal Dependable CEMS-based Heat Input: The (original boiler manufacturer’s) boiler heat input capacities were updated using a method employed in permit No. 16300005-012. Refer to Section 3 of this document for further discussion.

§ Revised the 40 CFR Section 75.10 CEMS and COMS monitoring requirement by adding flow monitoring, and removing ‘The SO2 and NOx monitors shall be capable of producing emission rates in units of lb/mmBtu on a one-hour average, a three-hour average and on a 30-day rolling average.’ because Section 75.10 does not require SO2 measurement in pound per million Btu heat input on a 1-hour average, 3-hour average, or a 30-day rolling average. (Section 75.10 only requires SO2 measurement in parts per million and pounds per hour.)

§ Moved all Acid Rain Program requirements to COMG9 except the NOX averaging plan requirement for each unit that was replaced by the applicable NOX limit from Section 76.7(a) as requested in the Permittee’s updated Acid Rain Program application.

§ Added requirements to operate control equipment for all pollutants subject to one or more emission limits.

· EQUI82 and EQUI83 – corrected the requirement to comply with the Acid Rain Program SO2 limit at Section 72.9(c)(1) by changing the requirement from ‘Comply with the applicable Acid Rain emissions limitation for sulfur dioxide.’ to ‘Comply with the applicable Acid Rain emissions limitation for sulfur dioxide for each year commencing January 1, 2000.’ based on the original requirement first added by PER 002.

The 0.10 pounds per million Btu PM limit was revised by indicating the limit is on a 24-hour basis (because it is based on PSD modeling TSP in 1977 during EQUI85 permitting). Also, the 0.60 pounds per million Btu heat input PM limit from Minn. R. 7011.0510 was added to the permit.

Added a requirement to operate the overfire air system and selective noncatalytic reduction system for NOX control for each boiler.

Added a requirement for EQUI82 and EQUI83 retirement (and notification thereof) by 12/31/2018 because the Permittee selected this option from the Consent Decree for these EGUs (Consent Decree options are repower, refuel, reroute, or retire EQUI82 and EQUI83).

The existing allowances for not operating EQUI82 and EQUI83 PM controls were revised because the Consent Decree requires Continuous Operation of such controls (as defined in the Consent Decree). The revisions removed the existing allowance, and replaced it with a reference to the Consent Decree.

The Consent Decree Continuous Operation and Continuously Operate definition, in part, references § 60.11(d) which states, in part, At all times, including periods of startup, shutdown, and malfunction, owners and operators 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. This language at § 60.11(d) only requires control equipment operation during startup to the extent practicable,

· EQUI85

§ Revised NOX limit citations – EQUI85 construction was authorized by a 1977 EPA PSD permit (EPA-77-A-6). That permit limited PM and SO2 but not NOX. A 1988 state-issued operating permit contained the 0.70 lb/mmBtu NOX limit from 40 CFR 60.44(a)(3), but did not contain a Title I NOX limit. However, the March 1997 initial title V operating permit citation for the 0.70 lb/mmBtu limit included 40 CFR 60.44 as well as ‘Title I Condition: 40 CFR Section 52.21 PSD BACT limit and ambient impacts analysis’. Inclusion of the Title I Condition was an error based on the lack of a NOX limit in the 1977 PSD construction permit. To correct this, the Title I Condition was removed from the citation for the EQUI85 0.70 lb/mmBtu NOX limit. The co-fired fuels NOX limit equation was also revised to account for the removal of liquid fuel (distillate fuel oil) as a permitted fuel type.

§ Revised requirements to reflect removal of old EQUI85 controls (electrostatic precipitator, venturi scrubber, and spray tower) and installation of new controls (TREA6 (Low NOX burners (LNB)/Separated Overfire Air (SOFA)), TREA7 (SNCR), TREA21 (Fabric Filter & FGD), and TREA22 ACI).

§ Revised the 0.015 lb/mmBtu front-half particulate matter limit to 0.012 lb/mmBtu as prescribed by permit No. 06100004-007 that stated ‘This limit becomes 0.012 lb/million Btu heat input 90 days after issuance of the MPCA Notice of Compliance letter indicating the test-measured Front-half Particulate Matter emission rate was less than or equal to 0.012 lb/mmBtu during the initial Front-half Particulate Matter performance test after installation of CE 030 and CE 031’ (now known as TREA21 and TREA22, respectively). The (post-control equipment change) August 11, 2016 initial performance test measured an average filterable PM emission rate of 0.0032 lb/mmBtu, as reported in a March 3, 2017 Notice of Compliance. Therefore, the 0.015 lb/mmBtu limit revision to 0.012 lb/mmBtu became effective June 1, 2017.

§ PM, PM10, PM2.5, and fluoride emissions testing requirements after completion of control equipment retrofit were revised to reflect completion of testing, and now require future repeat testing at 60-month intervals. The PM10, PM2.5, and fluorides tests were conducted on October 4, 2016, and filterable and condensable PM tests were conducted August 11, 2016 (as part of the annual PM testing required by the Consent Decree.)

§ Removed the completed requirement to establish the baseline Hg emission rate from the Hg monitoring data required by Minn. § 216B.681.

§ Removed the requirement for MPCA to incorporate a reasonably expected to be achieved Hg reduction due to the installation of TREA21 and TREA22 as required by Minn. Stat. § 216B.687. Additionally, the interim 1.20 E-06 lb/mmBtu limit was revised to 26.0 lb/yr on a 12-month rolling sum based on Minn. Stat. § 216B.687. Refer to Section 2.12 for additional information.

§ Added a requirement for submittal of a Hg Control Optimization Plan (based on Minn. R. 7007.0800, subp. 2(A)&(B)) to ensure optimal mercury emissions reduction by implementing the requirement at Minn. Stat. § 216B.687, subd. 3. This requirement was also added to the total facility requirement for submittal of an application for permit reissuance 180 days before permit expiration. Also added a requirement for conducting a Mercury Reduction Analysis, and submittal of the analysis results within 180 days after permit issuance.


§ Revised the Title I Condition fluorides limit by removing language indicating the limit isn’t applicable until installation of TREA21 and TREA22. Revised all other requirements that included applicability language contingent on startup of EQUI85 after installation of TREA21 and TREA22 because EQUI85 resumed operation on December 16, 2015 after installation of these controls.

§ Removed the requirement to report calendar year SO2 emissions and annual compliance certification based on Minn. R. 7021.0050 due to repeal of Minn. R. ch. 7021.

§ Revised the CO BACT limit as discussed under Section 3.4. Also added to the CO BACT limit a statement that the Permittee shall employ good combustion practices to meet the CO BACT limit.

§ Revised the requirement to vent EQUI85 emissions to TREA22 so that such is not required when EQUI85 combusts only natural gas, instead of when EQUI85 combusts only natural gas during startup.

§ Removed completed requirements for notification of Start of installation of TREA21 and TREA22, and, for EQUI85 startup after completion of TREA21 and TREA22 installation.

§ Removed requirements for submittal of filterable (also referred to as ‘front-half’) PM, PM10, PM2.5, and fluorides test frequency plans due to their completion. The PM test frequency trigger date was reset to 08/11/2021 due to the submittal of the revised (post-control equipment retrofit) PM test frequency plan based on August 11, 2016 PM testing. Also established filterable PM, PM10, PM2.5, and fluorides test frequencies (at 60-month intervals) based on results of October 4, 2016 testing. The filterable PM 60-month test frequency is for determining compliance with the Title I BACT/Title I modeling/NSPS subp. D 0.10 lb/mmBtu limit and not for determining compliance with the filterable PM limit from the 2014 Consent Decree (although the Consent Decree allows use of state required tests to meet the requirement of the annual Consent Decree-required filterable and condensable PM tests).

§ Removed the EQUI85 annual SO2 emissions report requirement imposed by permit No. 06100004-005. The annual report was due 60 calendar days after end of each calendar year after installation of NOX controls TREA6 and TREA7 (CE027 and CE028) authorized by permit No. 06100004-005. Reports submitted for calendar years 2012 through 2016 demonstrated that actual SO2 emissions increase did not exceed the projected increase determined by the actual to projected actual emissions analysis conducted for permit No. 06100004-005.

§ The 135°F minimum stack temperature and associated recordkeeping requirements were removed. These requirements were necessary when the previous EQUI85 control equipment (wet controls in the form of a venturi scrubber and spray tower) resulted in potential STRU14 temperatures below 135°F producing less than optimal emissions dispersion. To address this issue, EQUI85 controls were designed to accommodate a minor amount of EQUI85 flue gas routed through an electrostatic precipitator (ESP) instead of the venturi scrubber and spray tower, on an as-needed basis. The ESP exhaust gas was then routed to STRU14 and combined with the remainder of the EQUI85 exhaust gasses. Because the ESP didn’t overly reduce flue gas temperature (unlike the spray tower and venturi scrubber), the overall STRU14 exhaust temperature could be maintained at or above 135°F. However, the minimum temperature requirement was necessary to ensure the enough exhaust gas was vented to the ESP to ensure adequate emissions dispersion.


The current control equipment (semi-dry flue gas desulfurization and fabric filter) is not configured for this venting scenario; there is no longer an alternate partial flue gas venting option (unlike with the previous controls). Because the potential for reduced stack temperatures is no longer present the requirements are no longer applicable or warranted. Note that 2014 SO2 modeling was conducted with a STRU14 exhaust gas temperature of 158°F.

§ Removed the 0.030 lb/mmBtu heat input 365-day rolling average SO2 limit because it was a placeholder for (and replaced by) the Consent Decree 0.030 lb/mmBtu heat input 30-day rolling average SO2 limit.

· EQUI100

§ Removed completed requirements for submittal of a Hg emissions monitoring plan, a coal Hg content monitoring plan, and a plan for Hg control optimization.

§ The EQUI100 Hg CEMS (EQUI109) was installed to meet the requirements of Minn. R 7011.0561, subp. 5(A) and the STRU13 sorbent trap is used to monitor Hg in the EQUI82, EQUI83, and EQUI100 common stack to meet the requirements of the site-specific monitoring plan requirement at Section 63.10000(d)(1).

§ PER 003 added a Unit 3 hydrogen fluoride (HF) limit to avoid PSD major modification. However, ‘fluorides’ is the regulated PSD pollutant (not including HF; reference the NSR Reform rulemaking preamble discussion at Section 7 ‘Listed Hazardous Air Pollutants’ of FR Vol. 67 No. 251 pg. 80239; December 31, 2002).

§ Removed requirements for PM and CO stack testing while burning waste water treatment sludge and while burning oily materials because both materials are not permitted fuels, have not been determined to not be solid waste when combusted according to 40 CFR 241.3 or 40 CFR 241.4, and new updated requirements were added to COMG9 for test burns of non-permitted fuels.

§ Changed the 0.80E-06 lb/million Btu limit to a 10.0 lb/yr on a 12-month rolling sum basis limit as requested by the Permittee. Also revised the sentence regarding EQUI100 Hg requirements being state-only to more closely reflect the language at Minn. Stat. § 216B.687, subd. 2(a). Refer to Section 2.12 for additional information.

§ Revised the CO BACT limit as discussed under Section 3.4. Also added to the CO BACT limit a statement that the Permittee shall employ good combustion practices to meet the CO BACT limit.

§ Removed the following language from the requirement to vent EQUI100 emissions to the various EQUI100 control equipment:

‘The Permittee is not required to operate CE 029 (TREA22) when EU 003 (EQUI100) combusts only natural gas or when EU 003 combusts natural gas during startup. EU 003 start up operating mode for purposes of this CE 029 operating requirement is defined as when there are less than three EU 003 coal pulverizing mills in service. The Permittee shall maintain records of when EU 003 is operating with less than three mills in service.’

This language pre-dates the effective date of pt. 63, subp. UUUUU and removal of the language is warranted because pt. 63, subp. UUUUU requires use of clean fuels during startup and doesn’t provide an exemption to the subp. UUUUU 1.2 lb/TBtu mercury limit during startup. The language was replaced with:

‘The Permittee is not required to operate TREA28 when EQUI100 is not combusting any coal.’


§ Removed the 0.07 lb/mmBtu NOX limit (30-day rolling average; basis was Minn. R. 7007.0800, subp. 2) that was added to the permit by PER 003.

This limit was set to address anticipated Best Available Retrofit Technology (sometimes referred to as BART) requirements and was included in the Minnesota State Implementation Plan (SIP) December 31, 2009 SIP Revision submittal was sent to EPA. However, the MPCA intended to rely on the cap and trade features of the Clean Air Interstate Rule (CAIR) program instead of BART limits applicable to individual EGUs. Regardless, CAIR was remanded by the D.C. Circuit of the U.S. Court of Appeals in December 2008 and stayed in Minnesota in December 2009. This lead Minnesota to rely on the source-specific BART determinations at that time for the 2009 Regional Haze SIP. In October 2011, EPA finalized the CAIR replacement known as the Cross State Air Pollution Rule (CSAPR), which is a cap and trade rule similar to CAIR. In December 2011, EPA proposed a rule to allow CSAPR as an alternative to the source-specific BART determinations. In July 2012, EPA approved Minnesota’s proposal to implement CSPAR in place of BART for EGUs. Although CSAPR was subject to additional court challenges, the rule remains in place and the case-by-case BART determinations are not applicable.

Finally, the EQUI100 0.060 lb/mmBtu (30-day rolling average) Consent Decree NOX limit is more restrictive than the 0.07 lb/mmBtu NOX limit (30-day rolling average) removed by this permit action.

Revised the requirement to vent EQUI100 emissions to TREA28 so that such is not required when EQUI100 combusts only natural gas, instead of when EQUI100 combusts only natural gas during startup.

· EQUI97, EQUI98, and EQUI122 - Corrections were made to Fly Ash Silo A (EU 017/EQUI98) and Loadout Spout (EU 018/EQUI97) process flow/control equipment and associated subject items, including the addition of the Silo A fly ash ventilated annular loadout spout (EQUI122/EU042 installed without a permit in 2009) as a separate emission source. EQUI122 was not proposed in the PER003 application (permit that authorized the EQUI100 air pollution control retrofit resulting in the collection by the EQUI100 fabric filter (TREA9) of dry fly ash instead of wet ash (that was captured by the old EQUI100 wet particulate matter scrubber)).

· Revisions were made to fly ash and reagent handling equipment PM limits previously cited as both the Industrial Process Equipment Rule at Minn. R. 7011.0715 and Title I Condition to avoid major modification. The affected subject items are: EQUI5/EU019

Unit 3 Limestone Storage Silo; EQUI6/EU020 Unit 3 Limestone Day Bin 1; EQUI7/EU021 Unit 3 Limestone Day Bin 2; EQUI86/EU024 Unit 4 Lime Silo; EQUI87/EU025 Unit 4 Lime Day Bin A; EQUI88/EU026 Unit 4 Lime Day Bin B; EQUI89/EU027 Unit 4 Lime Day Bin C; EQUI90/EU028 Unit 4 Lime Day Bin D; EQUI91/EU029 Unit 4 Lime Day Bin E; EQUI93/EU031 Fly Ash Storage Silo B; EQUI94/EU032 Fly Ash Loadout B - Truck Bay; EQUI97/EU018 Fly Ash Loadout A - Truck Bay; EQUI98/EU017 Fly Ash Storage Silo A; EQUI99/EU015 Hg Additive Handling and Unit 3 PAC Silo Storage; and EQUI120/EU030 Unit 4 Activated Carbon Silo. These PM limits were split into two limits - one Title I PM limit to avoid PSD major modification, and a second PM limit from Minn. R. 7011.0715.

· EQUI106 – This STRU13 Hg sorbent trap monitoring system was installed to monitor EQUI82, EQUI83, and EQUI100 common stack STRU13 Hg emissions, and contains applicable requirements from pt. 63, subp. UUUUU, Appendix A. Common stack monitoring is permitted by subp. UUUUU as specified at Section 63.10010(a)(2)(ii).


As allowed by subp. UUUUU, the Permittee may use either EQUI106 or EQUI109 to monitor STRU13 mercury emissions before EQUI82 and EQUI83 shutdown, and may use either monitor to monitor EQUI100 mercury emissions after EQUI82 and EQUI83 shutdown.

· EQUI107 and EQUI108 (STRU13 and EQUI85 PM CEMS, respectively) requirements were added in response to the Permittee’s use of such CEMS to determine filterable particulate matter emissions compliance under pt. 63, subp. UUUUU, and the 2014 Consent Decree requirement to install PM CEMS. The Permittee established its use of the CEMS option for determining filterable PM compliance under pt. 63, subp. UUUUU in their site-specific monitoring plan required by Section 63.100000(d)(1).

· EQUI109 requirements were added requiring the use of either EQUI109 or EQUI106 to monitor STRU13 mercury emissions before EQUI82 and EQUI83 shutdown, and the missing data procedures during monitor downtime. After EQUI82 and EQUI83 shutdown, the Permittee may use either EQUI109 or EQUI106 to monitor EQUI100 mercury emissions, and during any EQUI109 outage may also use the EQUI106 sorbent trap mercury monitor as a backup or the missing data substitution requirements described immediately below under ‘EQUI109 and EQUI110’.

· EQUI109 and EQUI110 (Unit 3 and Unit 4 Hg CEMS formerly MR025 and MR026, respectively) – Part 75 Hg monitoring requirements were revised to reflect the March 28, 2011 federal register part 75 revisions (in response to the Clean Air Mercury Rule (CAMR) that was vacated by the D.C. Circuit in New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008)). The March 28, 2011 federal register announced the removal of the Hg monitoring provisions that supported CAMR. Specifically, portions of part 75 (subpart I; Section 75.80 – Section 75.84) dealing exclusively with Hg monitoring (CEMS and sorbent trap systems) were removed, and other sections that applied both to Hg monitoring systems and other types of CEMS were revised and re-promulgated, minus the references to Hg.

The current mercury monitoring requirements are those from part 63, subp. UUUUU, Appendix A, along with state requirements based on the vacated mercury CEMS portions of part 75. The state requirements are for determining missing data values during Hg CEMS downtime while Unit 3 and/or Unit 4 are operating and are necessary as part of the compliance determination for the Unit 3 and Unit 4 lb/yr Hg limit based on Minn. Stat. 216B.68 through Minn. Stat. 216B.688 for each unit. Refer to Section 2.12 for additional information.

· EQUI119 (Unit 4 Emergency Generator) was installed to replace the previous generator EU 010. Replacement of EU 010 with EQUI119 reduced emissions of all pollutants.

· STRU14 stack diameter and height were revised due to the following:

§ In the fall of 2015 during the EQUI85 shutdown for the control equipment retrofit, the 20.0-foot diameter stack mouth choke was removed increasing the stack diameter to 35.0 feet (2014 SO2 and PM2.5 modeling was conducted using the 35.0 foot STRU14 diameter (with addition modeling using the 20.0 foot diameter)).

§ In the fall of 2017, the stack height was increased from 600 feet to 616 feet, and the diameter reduced to 32.0 feet.

· TREA5, TREA6, TREA7, TREA8, TREA11, TREA12, TREA13, and TREA15 – Added requirements for operating and maintaining these NOX controls, using the associated NOX CEMS for CAM, and corrective actions if NOX CEMS measure an exceedance of a NOX emission limit.


· TREA9 (CE 021 EQUI100 Fabric Filter) – added control efficiency requirements for PM10 and PM2.5 because the emission calculations rely on these efficiencies for these pollutants. Revised PM and PM10 CAM by removing the opacity component, revising the pressure drop requirement from a maximum of 11.0 inches w.c. to a range of 2.0 – 11.0 inches w.c., and changing the averaging period from one-minute to a more appropriate one-hour period. Added a requirement specifying how the indicator values can be revised.

· TREA10 (CE022/EQUI100 Wet FGD; TREA10 controls SO2, fluorides, and HCl)

Added a 65% fluorides control efficiency requirement because this value was used to calculate fluorides emissions and EQUI100 fluorides emissions are subject to a limit to avoid a PSD major modification. Also added fluorides periodic monitoring requirements as discussed below.

Added a 97.1% HCl control efficiency requirement because TREA10 controls HCl and this value was used to calculate HCl emissions. Also added requirement for corrective action because the Permittee chose the MATS HCl compliance option (in lieu of the alternate SO2 compliance option).

· TREA14 and TREA16 (EQUI82 and EQUI83 Fabric Filters, respectively) – revised CAM from use of the COMS to pressure drop maximum and minimum and added a requirement for how these indicator values can be revised.

· TREA21 (CE030/EQUI85 semidry FGD/fabric filter; TREA21 controls SO2, fluorides, HCl, PM, PM10, and PM2.5)

The 90% fluorides control efficiency citation was revised by adding ‘Title I to avoid major modification under 40 CFR 52.21(b)(2)(i)’ because Unit 4 fluorides emissions are subject to a limit to avoid a PSD major modification.

Added a 97.1% HCl control efficiency requirement because TREA21 controls HCl and this value was used to calculate HCl emissions. Also added requirement for corrective actions if the Permittee chooses the MATS HCl compliance option (in lieu of the Permittee’s chosen SO2 compliance option).

The PM Compliance Assurance Monitoring (CAM) interim plan was revised from use of the continuous opacity monitor and TREA21 fabric filter pressure drop, to the use of only TREA21 fabric filter pressure differential. In addition, the plan also applies to PM10 and PM2.5, and the pressure drop range was revised from 2.0 – 20.0 inches w.c. to 4.0 – 18.0 inches w.c. based on actual observed pressure drop values. Also, fluorides CAM (use of SO2 CEMS data) was added to the permit. Added a requirement for how the indicator values can be revised. Finally, requirements to submit an updated PM CAM plan, and proposed CAM for PM10, PM2.5, and fluorides after installation of TREA21 and TREA22 were removed.

· FUIG1 and FUGI2 – added the PM limit from the industrial process equipment rule at Minn. R. 7011.0715 for these two cooling towers.

· FUGI3 (FS004) requirements to install pavement on the ash haul road and submit a notice of completion of pavement installation were completed so these requirements were removed. The remaining two requirements for controlling ash haul road dust and related recordkeeping were also removed because they no longer apply due to pavement installation on the fly ash haul road. The paved fly ash haul road is now included under and subject to the requirements of FUGI10 (Paved Haul Roads) as well as the Fugitive Dust Control Plan. A new requirement was added to FUGI3 for controlling unpaved road dust using best management practices.


· FUGI9 (FS001) – a requirement was added to limit the uncrusted coal stockpile working area to a maximum of 20 acres (to restrict the fugitive particulate matter emissions increase from wind erosion of the increased stockpile working area due to the 2015 coal stockpile expansion project). This requirement is based on the use of 20 acres in the updated PM emission calculations for this permit reissuance (as opposed to the 50 acre value used in the 2015 application) compared to the pre-modification 14 acre working area.

The acreage limit is not a title I requirement to avoid a major modification because the coal stockpile is a modified existing source whose emission changes were determined on an actual-to-projected-actual basis. Based on a 2011 EPA memorandum to the Semiconductor Industry Association, projected actual emissions can be calculated using design and operational parameters, and the effect of pollution control equipment regardless if they are legally enforceable. Uncrusted working area is an operational parameter and the limit on the working area was not and did not need to be legally enforceable when the projected actual emissions were determined. Therefore the 20 acre limit is a state requirement and not a title I requirement. (See August 26, 2011 EPA memorandum from Stephen D. Page to David Isaacs/Semiconductor Industry Association at https://www.epa.gov/sites/production/files/2015-07/documents/semiconpsd.pdf).

· FUGI11 (FS006) Coal Stockpile Material Handling Including Segment For Coal Stockpile Material Handling Using Portable Conveyors Title I (to avoid major modification) requirements were added for the new portable conveyors to reflect the following assumptions in the 2015 minor amendment application (as updated in the 2016 updated title V reissuance application):

§ A 450 ton-per-hour portable coal conveyor handling limit; § Maximum of 11 conveyor drop points for the coal stockpile (unenclosed/

uncontrolled) portable conveyors;

§ Minimum 20% by weight coal moisture content for coal handled by the portable conveyors;

§ Maximum 20 mph hourly wind speed during coal handling by portable conveyors. · Appendix C Modeling Parameters – except for CO modeled parameters, pre-2014

modeling parameters were removed and 2014 SO2 modeling parameters were added. The pre-2010 parameters (other than for CO) are no longer accurate or relevant due to removal of certain equipment, modeling policy changes (i.e., emergency generators are no longer included in modeling providing the Permittee implements best management practices for the units), reductions in EGU emission rates, and inaccuracies in some of the pre-2014 modeling parameters.

2. Regulatory and/or statutory basis of permit requirements

2.1 New Source Review (NSR)

The facility is an existing major NSR source. In addition, Unit 4 construction occurred in the late 1970’s and is subject to PSD. A 1977 EPA-issued PSD construction permit authorized the construction of this boiler. NOX reduction modifications were made to EQUI85 and EQU100 in 2010 and 2007, respectively, and CO emission increases from those projects were subject to PSD permitting. The CO BACT determinations for both EGUs are revised by this permit action as discussed under Section 3.4 of this TSD.

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2.2 Part 70 Permit Program

The facility is a major source under the Part 70 permit program. This permit action does not change this status.

2.3 New Source Performance Standards (NSPS)

a. Part 60, Subpart D - Unit 4 is subject to pt. 60, subp. D Standards of Performance for Fossil-Fuel-Fired Steam Generators because the Permittee commenced construction of Unit 4 in January 1978 (as authorized by EPA permit No. EPA-5-77-A-6 issued June 16, 1977) which is after the August 17, 1971 commence construction subp. D applicability date, but before the September 18, 1978 commence construction subp. Da applicability date.

b. Part 60, Subpart IIII - The three emergency reciprocating internal combustion engines (RICE; EQUI23, EQUI81, and EQUI119) are subject to pt. 60, subp. IIII Standards of Performance for Stationary Compression Ignition Internal Combustion Engines.

EQUI23 is the Unit 3 Emergency Generator (a diesel fuel-fired compression ignition (CI) engine rated at 398 hp/250 kW manufactured and constructed in 2012). EQUI81 is the Unit 3 Air Pollution Control Equipment Emergency Generator (a diesel fuel-fired CI engine rated at 480 hp/300 kW manufactured and constructed in 2009). EQUI119 is the Unit 4 Emergency Generator (a diesel fuel-fired CI engine rated at 2206 hp/1500 kW manufactured and constructed in 2015).

40 CFR 60.4200(a)(2)(i) states the Permittee is subject to part 60, subp. IIII because it owns and operates EQUI23, EQUI81, and EQUI119 and construction of these RICE commenced after July 11, 2005, the RICE were manufactured after April 1, 2006, and none of the RICE are fire pump engines. In addition, the Permittee does not qualify for the applicability exclusion at 40 CFR 60.4200(b) because none of the RICE are tested at a test cell/stand.

c. Part 60, Subpart Y - The increase in coal storage and handling as proposed by a 2015 minor permit amendment application are subject to pt. 60, subp. Y Standards of Performance for Coal Preparation and Processing Plants. 40 CFR 60.254(c) states the storage pile affected facility includes the equipment used in the loading, unloading, and conveying operations of the affected facility. Therefore the affected sources are:

i. Coal Stockpile - Wind Erosion (FUGI9/FS001); and,

ii. Coal Stockpile Material Handling Including Segment For Coal Stockpile Material Handling Using Portable Conveyors (FUGI11/FS006).

2.4 National Emission Standards for Hazardous Air Pollutants (NESHAP)

The facility is an existing major source of HAPs and is subject to two NESHAPs.

a. Part 63, Subpart UUUUU - The four EGUs at the facility are coal-fired electric utility steam generating units that collectively comprise an affected source subject to pt. 63, subp. UUUUU ‘National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units’ (refer to 40 CFR 63.9982(a)(1)). Subpart UUUUU is frequently referred to as the Mercury and Air Toxics Standards or ‘MATS’.

The four EGUs are existing EGUs because construction of all began on or before May 3, 2011, and none were reconstructed after May 3, 2011. The initial compliance date for existing EGUs is April 16, 2015. The agency issued a January 28, 2013 letter to the Permittee authorizing a one-year extension for EQUI85 to the April 16, 2015 compliance


date to accommodate the EQUI85 control equipment replacement project. Each EGU is equipped with a neural network.

As stated in permit Appendix H, the Permittee has selected the following compliance options:

1. Units 1-3:

a. PM on a lb/mmBtu basis measured by STRU13 PM CEMS; b. HCl on a lb/mmBtu heat input basis with emissions measured by EPA

Reference Method 26A; c. Hg on a lb/TBtu basis measure by the STRU13 Hg sorbent sampler

CEMS.

2. Unit 4:

a. PM on a lb/mmBtu basis measured by STRU14 PM CEMS; b. SO2 on a lb/mmBtu basis measured by STRU14 SO2 CEMS; c. Hg on a lb/TBtu basis measure by the STRU14 Hg CEMS.

Additionally, the Permittee has elected to implement Startup definition paragraph (1) at § 63.10042.

If the Permittee elects to change to another compliance option(s), the Permittee is required by § 63.10030(e) to submit a revised Notice of Compliance Status indicating such changes. The Permittee will not employ emissions averaging. EQUI82, EQUI83, and EQUI100 qualify as low emitting EGUs (LEE) according to § 63.10005(h).

b. Part 63, Subpart ZZZZ - The three emergency engines (EQUI23, EQUI81, and EQUI119) are subject to pt. 63, subp. ZZZZ National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines. Refer to Section 2.3.b for engine horsepower, manufacturing date, and construction date information for these RICE.

According to 40 CFR 63.6590(a)(2)(ii), EQUI23 and EQUI81 are stationary RICE subject to 40 CFR pt. 63, subp. ZZZZ because both have a site rating of equal to or less than 500 brake HP, are located at a major source of HAP emissions, and the Permittee commenced construction of EQUI23 and EQUI81 on or after June 12, 2006. However, although both RICE are subject to 40 CFR part 63, subp. ZZZZ, they are regulated by NSPS subpart IIII according to 40 CFR 63.6590(c)(7).

According to 40 CFR 63.6590(a)(2)(i), EQUI119 is subject to subp. ZZZZ because it has a site rating of greater than 500 brake HP, is located at a major source of HAP emissions, and the Permittee commenced construction of EQUI119 on or after December 19, 2002. However, according to 40 CFR 63.6600(c), the Permittee is not subject to emission limitations in Table 2a or operating limitations in Table 2b in pt. 63, subp. ZZZZ.

2.5 Acid Rain Program

The boilers (EQUI82, EQUI83, EQUI100, and EQUI85) are subject to SO2 and NOX Acid Rain requirements. The Permittee is required to monitor and maintain records of SO2, NOX, CO2, and opacity emissions, maintain SO2 emission allowances, and comply with applicable NOX limits. This permit includes an update NOX compliance plan (Appendix B), and the Permittee has elected to no longer use the NOX averaging provisions at 40 CFR 76.11.

2.6 Transport Rule/CSAPR


The four EGUs are subject to the part 97 Transport Rule (also known as the Cross-State Air Pollution Rule or CSAPR) requirements for the NOX Annual Trading Program (subpart AAAAA) and the SO2 Group 2 Trading Program (subpart DDDDD).

This permit incorporates the requirements of 40 CFR part 97 subps. AAAAA and DDDDD. EPA issued a memorandum on May 13, 2015 to provide guidance to the regions and states on incorporating CSAPR requirements into Title V permits. The guidance included a template for use in permits, and that template is located in permit Appendix G.

All CSAPR requirements incorporated into this permit adhere to EPA’s guidance and template, with one exception. The permit does not include requirements from 40 CFR Section 97.406(d) and 40 CFR Section 97.706(d) regarding revision of part 97 monitoring requirements. Sections 97.406(d) and 97.706(d) were not included because they refer to the permit modifications procedures under part 70 that a Permittee may use to make changes to the monitoring provisions table in the permit. However, in Minnesota, changes to the part 97 monitoring requirements must be made according to the requirements of Minn. R. 7007.1150 through Minn. R. 7007.1500.

2.7 Data Requirements Rule (DRR; 40 CFR part 51, subp. BB; §§ 51.1200 – 51.1205)

The MPCA submitted the 2014 facility 1-hour SO2 modeling results to EPA for demonstrating compliance with the EPA SO2 Data Requirements Rule. MPCA had originally intended to re-issue this permit with incorporated modeled 1-hour SO2 emission rates as hourly emission limits, but this permitting action was not complete (nor the limits effective) by the DRR January 13, 2017 deadline.

In order to meet the January 13, 2017 deadline, the MPCA relied on the federally enforceable Consent Decree SO2 emission limits (instead of using future not-yet-enforceable permit limits equal to the modeled 1-hour SO2 emission rates) to ensure compliance with the 2010 SO2 NAAQS.

The Consent Decree SO2 limits are 30-day rolling average limits, in pounds of SO2 per million Btu, but are as stringent, or more, than the one-hour pound per hour SO2 emission rates that demonstrated modeled compliance with the 1-hour SO2 NAAQS. To demonstrate the Consent Decree limits are as stringent, or more, than the emission rates modeled in 2014, the MPCA used the following method:

i. The Consent Decree limits (pounds per million Btu 30-day rolling average) were converted to lb/hr 30-day average limits, using the heat rate input capacity for the EGUs.

ii. The MPCA used the methodology provided in EPA’s April 2014 “Guidance for 1-Hour SO2 Nonattainment Area SIP Submissions,” to convert the NAAQS-compliant modeled lb/hr emission rate to a comparably stringent lb/hr 30-day average limit. The conversion used the conservatively calculated adjustment factors EPA provided in Appendix D of its April 2014 guidance (the average ratio of 99th percentile 30-day average SO2 emission value to the 99th percentile of hourly SO2 emission value).

iii. The MPCA then compared the comparably stringent (modeled) 30-day emission rates to the 30-day Consent Decree limits (converted to lb/hr) and demonstrated the Consent Decree limits are equal to or less than the modeled limits, thereby ensuring that the federally enforceable Consent Decree limits provide for NAAQS attainment. The equivalent STRU13 30-day rolling average lb/hr Consent Decree limit is 1522 lb/hr compared to an equivalent 30-day rolling average NAAQS-compliant modeled SO2 emission rate of 3484 lb/hr. The equivalent STRU14 30-day


rolling average lb/hr Consent Decree limit is 204 lb/hr compared to an equivalent NAAQS-compliant modeled SO2 emission rate of 1638 lb/hr.

2.8 Compliance Assurance Monitoring (CAM)

CAM applicability is determined on a pollutant-by-pollutant basis for each “pollutant specific emissions unit,” (PSEU) as defined at 40 CFR § 64.1. CAM applies to a unit that meets the following conditions:

· The unit is subject to an emission limitation or standard for the applicable regulated air pollutant (or a surrogate thereof), other than an emission limitation or standard that is exempt under § 64.2(b)(1);

· The unit uses a control device to achieve compliance with any such emission limitation or standard; and,

· The unit has potential pre-control device emissions of the applicable regulated air pollutant that are equal to or greater than 100 percent of the amount (in tons per year) required for the unit to be classified as a major source.

Table 6 below lists the emission sources and pollutants subject to CAM, whether the source is a Large or Other PSEU, and the monitoring for the applicable pollutants. CAM plans are in Attachment 6.


Table 6. CAM summary

Unit Control Pollutant Emission Limitation Basis

CAM Applicability Monitoring

EQUI82 Unit 1

TREA16 Fabric Filter PM

Minn. R. 7011.0510 40 CFR § 52.21(k) Consent Decree*

Other Pressure differential >2.0 <14.0 inches w.c.

TREA15 SNCR NOX Consent Decree Large NOX CEMS

EQUI83 Unit 2

TREA14 Fabric Filter PM

Minn. R. 7011.0510 40 CFR § 52.21(k) Consent Decree

Other Pressure differential >2.0 <14.0 inches w.c.

TREA11 SNCR NOX Consent Decree Large NOX CEMS

EQUI100 Unit 3

TREA9 Fabric Filter

PM Minn. R. 7011.0510 Consent Decree Large Pressure differential

>2.0 <11.0 inches w.c. PM10 Minn. R. 7007.0800, subp. 2(A)&(B) Large

TREA10 Wet FGD SO2

Minn. R. 7011.0510 40 CFR § 50.5 Minn. R. 7009.0020 Consent Decree

Large SO2 CEMS

TREA5 SCR NOX Consent Decree Large NOX CEMS

EQUI 85 Unit 4 (STRU14)

TREA21 Dry FGD/Fabric Filter

PM

40 CFR § 60.42(a)(1) 40 CFR § 52.21(j)&(k) Minn. R. 7007.0800, subp. 2(A)&(B) Consent Decree

Large Pressure differential >4.0 <18.0 inches w.c.

PM10 Minn. R. 7007.0800, subp. 2(A)&(B)

Large PM2.5 Large

SO2

40 CFR § 52.21(j)&(k) Minn. R. 7009.0020 40 CFR § 60.43(a)(2) Consent Decree 40 CFR § 50.17

Large SO2 CEMS

Fluorides 40 CFR § 52.21 Large

TREA7 SNCR NOX 40 CFR § 60.44(b) Consent Decree Large NOX CEMS

*CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21

For Large PSEUs (in the context of § 64.5(a)), the Permittee must collect four or more data values equally spaced over each hour. For Other PSEUs (in the context of § 64.5(b)), one monitored parameter record is required each 24 hours. Although EQUI82 and EQUI83 are Other filterable PM PSEUs, the Permittee has elected to monitor the EQUI82 and EQUI83 fabric filter (TREA16 and TREA14) pressure drop four times per hour to generate 1-hour average pressure drop values for each fabric filter. CAM Plans are located in Attachment 5.

EQUI85 fluorides CAM is based on TREA21 (Fabric Filter and Semi-Dry Flue Gas Desulfurization) controlling both SO2 and fluorides, and the results of fluorides emissions testing and concurrent SO2 CEMS data demonstrating that SO2 is worst case compared to fluorides.

CAM does not apply to the modeling-based common stack STRU13 SO2 4450 lb/hr (1-hour average) limit because CAM doesn’t apply to a stack. Also, only EQUI100 SO2 emissions are controlled by an SO2 control device (EQUI82 and EQUI83 that also vent through STRU13 are


not equipped with SO2 control equipment), and CAM is already specified for EQUI100 SO2 emissions as shown in the table above.

Note that EQUI100 fluorides emissions are not subject to CAM (but are subject to periodic monitoring as discussed in Table 15) but were included by Permittee in their CAM plan submittals because initial emission calculations indicated uncontrolled fluorides would exceed the 100 tpy major source threshold.

In addition, the EQUI85 and EQUI100 flue gas desulfurization equipment (TREA21 and TREA10, respectively) also controls HCl, these emissions are subject to the MATS HCl limit, and controlled emissions exceed the 10 tpy major source threshold. However, EQUI85 and EQUI100 HCl emissions are not subject to CAM because the MATS is an emission limitation exempt from CAM under § 64.2(b)(1)(i).

Resetting the TREA9, TREA14, TREA16, or TREA21 fabric filter pressure drop range can not be made through the values recorded during a single particulate matter performance test. This is due to the fact that the CAM pressure drop range was established through review of the differential pressure experienced over one or more months of bag filter operation, and not from the short term variation experienced during a single performance test.

2.9 Environmental Review and Air Emissions Risk Analysis

None of the changes authorized by this permit trigger requirements for environmental review or an Air Emissions Risk Analysis.

2.10 2014 Consent Decree

The Permittee entered into a Consent Decree (CASE 0:14-cv-02911-ADM-LIB Document 3-1 filed on July 16, 2014 and signed by the Judge of the U.S. District Court for Minnesota on September 29, 2014) with the US EPA and MPCA. The Consent Decree (Attachment 6 to this document) imposes PM, SO2, and NOX limits that reduce allowable emissions of these pollutants. As stated at paragraph 210, the Consent Decree requirements and limitations are applicable requirements as defined at 40 CFR § 70.2.

The Consent Decree also requires refueling, retirement, or repowering of Units 1 and 2 no later than December 31, 2018 (the Permittee submitted a December 19, 2016 notification indicating these units will be shut down by December 31, 2018) as well as various other requirements related to SO2 and NOX allowances, monitoring (including submittal of updated Compliance Assurance Monitoring Plans for PM emissions from each EGU), stack testing, control equipment operation, and netting credits. Also, EPA has indicated (through electronic mail communication on February 23, 2016 included as Attachment 8 to this technical support document) that if the Permittee meets requirements for filterable PM testing every other calendar year (instead of every calendar year), then the Permittee may test condensable PM emissions every other calendar year (refer to Attachment 8). Most applicable Consent Decree definitions are located in permit Appendix F.

The Consent Decree allows PM testing every other year if certain conditions are met. Appendix K contains an email from EPA to the Permittee clarifying that boilers that qualify for every other year filterable PM testing are also eligible to test condensable PM every other year instead of every year.

2.11 Minnesota Rule 7011.0561 Control of Mercury from Electric Generating Units

The four electric utility boilers are subject to Minn. R. 7011.0561 because the boilers do not qualify for the exemption at Minn. R. 7011.0561, subp. 3. Also, Minn. R. 7011.0561, subp. 4,


states that unless the commissioner establishes an alternative mercury emissions reduction under Minn. Stat. § 216B.687, subd. 3, the EGUs are subject to Minn. R. 7011.0561.

Minn. Stat. § 216B.687, subd. 3 applies to units already subject to a limit established through the MERA when the unit’s operating permit is undergoing reissuance and mercury reduction optimization is reviewed to determine if additional reductions are feasible; EQUI85 is not yet subject to an already-established MERA limit. The specific reference only to subd. 3 at Minn. R. 7011.0561, subp. 4 was an oversight in the rule drafting process because the commissioner can establish a mercury limit at both Minn. Stat. § 216B.687, subd. 2(b) as well as at subd. 3. The agency is in the process of revising Minn. R. 7011.0561, subp. 4 so that it references all of Minn. Stat. § 216B.687, instead of only subd. 3. In the interim, the COMG9 requirement for 90% mercury control or limit mercury to 0.8 lb/TBtu citation includes ‘Minn. R. 7007.0800, subp. 2(A)&(B)’ to provide the agency authority to extend the exemption at Minn. R. 7011.0561, subp. 4 to EQUI85.

EQUI100 and EQUI85 are subject to limits established by the commissioner (10.0 lb/yr and 26.0 lb/yr both on a 12-month rolling sum basis, for EQUI100 and EQUI85, respectively) pursuant to Minn. Stat. § 216B.687, subd. 3 and 2(b), respectively. Additionally, both EQUI100 and EQUI85 have nameplate capacities greater than of 100 MW. Therefore, the limit options at Minn. R. 7011.0561, subp. 4(A) do not apply to EQUI100 and EQUI85.

EQUI82 and EQUI83 are not supplemental units (as defined at Minn. Stat. § 216B.6851, subd. 2) and each has a nameplate capacity of less than or equal to 100 MW, so these units would be subject to the limit options at Minn. R. 7011.0561, subp. 4(B). However, both EGUs will be shutdown by the end of 2018, which predates the January 1, 2025 Hg limit applicability date (at Minn. R. 7011.0561, subp. 4(B)) for these two EGUs.

2.12 Minnesota Statute Sections 216B.68 – 216B.688 Mercury Emissions Reduction Act (MERA)

The Minnesota Mercury Emissions Reductions Act (MERA) requires public utilities that own and operate targeted units (Minn. Stat. § 216B.68, subd. 8) at a qualifying facility (Minn. Stat. § 216B.68, subd. 6) to monitor mercury emissions, submit mercury reduction plans to the Public Utilities Commission (PUC) for employing technology most likely to achieve 90% mercury reduction, and to optimize operation of mercury controls for such units. The MERA also provides the Permittee the option to include one or more supplemental units (Minn. Stat. § 216B.6851, subd. 2) in any submitted MERA plan, whereby such units would be subject to the MERA, and to seek approval from the PUC for cost recovery.

Boswell Energy Center is a qualifying facility because it had a total net dependable capacity in excess of 500 megawatts as of January 1, 2006. EQUI85 and EQUI100 are targeted units subject to Minn. Stat. §§ 216B.68 – 216B.688 because each unit is greater than 100 megawatts, and the units are located at a qualifying facility.

EQUI82 and EQUI83 are neither targeted units (both EQUI82 and EQUI83 individual electrical output does not exceed 100 MW; Minn. Stat. § 216B.68, subd. 8) or supplemental units (because neither EQUI82 or EQUI83 were part of a mercury emissions-reduction plan under the MERA; Minn. Stat. § 216B.6851, subd. 2). Therefore, EQUI82 and EQUI83 are not subject to Minn. Stat. §§ 216B.68 – 216B.688.

For EQUI85 and EQUI100, the Permittee has the option of complying with the mercury reduction plan requirements at either Minn. Stat. § 216B.682 or Minn. Stat. § 216B.6851. The Permittee elected to comply with Minn. Stat. § 216B.6851, and submitted a reduction plan for each EGU to the Department of Commerce Public Utilities Commission (PUC). The EQUI100 plan was submitted October 27, 2006 and the PUC issued the Order approving the plan and cost recovery on October 26, 2007. The EQUI85 plan was submitted August 31,


2012 and the PUC issued the Order approving the plan and cost recovery on November 5, 2013. Both plans indicated mercury reductions would approach or attain 90%.

The EQUI100 plan indicated baseline mercury emissions were 100 pounds per year, and the proposed control equipment would reduce emissions by 90% to 10 pounds per year. The EQUI85 plan indicated baseline mercury emissions were 228 pounds per year, and the proposed control equipment would reduce emissions by 89% to 26 pounds per year.

PER003 (issued March 2007) authorized installation of EQUI100 control equipment to reduce multiple pollutants, including mercury. PER003 also required installation of Hg CEMS on EQUI100 and EQUI85 and monitoring of Hg emissions from these EGUs, and establishment of the baseline Hg emission rate for each EGU.

PER007 (issued June 2013) added an EQUI100 0.80E-06 lb/mmBtu (0.80 lb/TBtu) ‘first stage’ Hg limit based on the agency’s 2011 statistical analysis of EQUI100 Hg CEMS data. A requirement (the ‘Existing Monitoring Plan For Mercury Emissions’) for determining the Hg emissions rate using the EQUI100 Hg CEMS (EQUI109) was also added, along with requirements for submittal of a EQUI100 coal mercury content plan and an updated mercury emissions monitoring plan. PER007 authorized installation of EQUI85 mercury controls, required operation of those mercury controls, added an interim EQUI85 1.2E-06 lb/mmBtu mercury emission limit, and retained the PER003 requirement to establish the EQUI85 baseline mercury emissions rate.

EQUI85 PER008 Changes:

· The PER007 EQUI85 interim 1.2E-06 lb/mmBtu mercury limit has been replaced with a 26.0 lb/yr on a 12-month rolling sum basis limit as requested by the Permittee.

· The requirement to establish Hg baseline emission rate required by Minn. Stat. § 216B.681 is removed. This requirement was imposed by the 2007 PER003 and required at least six months of monitoring data to determine the pre-control Hg emission rate.

· Added a requirement for submittal of a coal Hg monitoring plan for daily sampling, and weekly analysis of composite samples from the daily samples. Coal Hg content data is necessary (along with Hg CEMS data) to determine the relationship between coal mercury content and stack mercury emissions, and to demonstrate that mercury reduction optimization required by Minn. Stat. § 216B.687, subd. 3 is occurring. An option to request cessation of such monitoring upon demonstration that sufficient data has been collected to demonstrate the level of Hg control efficiency and that optimization has occurred, has also been added.

· A requirement to submit a Hg controls optimization plan with the application for permit reissuance has been added.

EQUI100 PER008 Changes:

· The requirements for submittal of EQUI100 plans for Hg emissions monitoring and coal Hg content monitoring were completed and removed from PER008.

· The first stage 0.80E-06 lb/mmBtu limit has been replaced with a 10.0 lb/yr on a 12-month rolling sum basis limit as requested by the Permittee. Also, as shown in Figure 1, coal mercury content data coupled with EQUI100 Hg CEMS data demonstrate optimization of EQUI100 mercury controls due to ongoing mercury reductions of at least 90%. In addition, as part of optimization of mercury reduction and avoid to excessive use of activated carbon, the Permittee incorporated a logic feedback loop between TREA28 (the EQUI100 carbon injection system) and EQUI109


(the EQUI100 Hg CEMS). Comparison of coal mercury content and outlet emissions are shown in Figure 2. Mercury emissions monitoring suggests that outlet mercury emissions are related more strongly to the operation of air pollution controls rather than coal mercury content. Coal mercury content measurement is thus no longer required.


Figure 1: EQUI100 Mercury Removal Efficiencies January 1, 2016 through December 31, 2016

Figure 2: EQUI100 Mercury Emissions vs. Coal Mercury Content January 1, 2016 through

December 31, 2016

Additional requirements were also added to the EQUI85 and EQUI100 Hg CEMS (subject

items EQUI110 and EQUI109, respectively) for deriving missing Hg CEMS data when the units are operating but the CEMS are not operating or are out-of-control (as defined at § 72.2). These requirements are based on the former requirements of 40 CFR § 75.38 [as amended at 73 FR 4349, Jan. 24, 2008], Section 2.1.7 of Appendix A to 40 CFR pt. 75 [as amended at 73 FR 4363, Jan. 24, 2008], Table 1 of 40 CFR § 75.33 [as amended at 73 FR 4346, Jan. 24, 2008] and the current requirements of 40 CFR § 75.33(b)(1)-(4) [as amended at 76 FR 17311, Mar. 28, 2011].


The requirements formerly in part 75 were repealed on March 28, 2011 due to the DC Circuit Court vacating the Clean Air Mercury Rule (CAMR) in 2008 (as referenced in the discussion in this document at Section 1.6 under EQUI109 and EQUI110). Although these CAMR requirements were vacated, they were not vacated due to errors in the requirements, but were vacated because the program they supported was vacated. Therefore these requirements are reasonable to use as the basis for the missing data substitution requirement in this permit action that are needed for determining compliance with the pound per year EQUI85 and EQUI100 Hg emission limits.

2.13 Environmental Justice

Environmental Justice (EJ) is the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies. EPA has this goal for all communities and persons across the U.S.A. It will be achieved when everyone enjoys the same degree of protection from environmental and health hazards and equal access to the decision-making process to have a healthy environment in which to live, learn, and work.

As part of this permitting process, the MPCA contacts US E.P.A. Region 5 staff to verify if there are any possible EJ issues for the facility location that need to be addressed in the permit action. For this project, MPCA staff contacted EPA Region 5 staff who used the draft Environmental Justice Strategic Enforcement Assessment Tool (EJSEAT) to determine that EJ concerns were unlikely for the Minnesota Power – Boswell Energy Center location.

2.14 Minnesota State Rules

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

· Minn. R. 7011.0510 Standards of Performance for Existing Indirect Heating Equipment

· Minn. R. 7011.0561 Control of Mercury From Electric Generating Units · Minn. R. 7011.0710 Standards of Performance for Pre-1969 Industrial Process

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

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

Engines

Also, an air pollution control equipment operating requirement based on Minn. R. 7007.0800, subp. 16(J) is used throughout the permit. This requirement (shown below) is not a revision of subp. 16(J) (shown further below) but is a requirement based on subp. 16(J) and subp. 2(B) that requires operation of all control equipment whether or not the permit requires such, to protect human health and the environment. The requirement citation includes Minn. R. 7007.0800, subp. 2(B) in reflection of this.

The permit requirement based on subp. 16(J) and subp. 2(B) says:

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) says:

(J) The permittee shall at all times properly operate and maintain the facilities and systems of treatment and control and the appurtenances


related to them which are installed or used by the permittee to achieve compliance with the conditions of the permit. Proper operation and maintenance includes effective performance, adequate funding, adequate operator staffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures.

The rule at subp. 16(J) is not used verbatim in the permit because the rule language could preclude agency enforcement action for failure to operate control equipment installed without a permit but where such control equipment operation is necessary to meet applicable requirement and protect human health and the environment. This control equipment operating requirement has been used in title V permits for more than the past twenty years ago to address this issue. Table 7. Regulatory overview of facility

Subject item* Applicable regulations Requirements

COMG1 - Sulfur Dioxide Limits

Minn. R. 7011 EQUI82, EQUI83, and EQUI100 IHER SO2 limit. 40 CFR pt. 50 Minn. R. 7009

EGU (EQUI82, EQUI83, EQUI85, and EQUI100), STRU13, and STRU14 SO2 modeling-based limits.

40 CFR 60, subp. D EQUI85 NSPS subp. D SO2 limit – refer to subp. D applicability discussion in Section 2.3.

40 CFR pt. 63 EGU subp. UUUUU MATS SO2/HCl Limits – refer to subp. UUUUU applicability discussion in Section 2.4.

Title I Condition: 40 CFR 52 EQUI85 BACT and PSD modeling-based SO2 limit.

CAAA 1990; Minn. Stat. § 116; Title I Condition: 40 CFR 52; Minn. R. 7007

Consent Decree EGU SO2 limits.

COMG3 - Low Temperature Fabric Filters Requirements

Minn. R. 7007; Minn. R. 7011; Title I Condition: Avoid major modification under 40 CFR 52

Fabric filter PM, PM10, PM2.5, and Lead control efficiency, monitoring, recordkeeping, and corrective action requirements. Refer to individual EQUI (controlled by a COMG3 fabric filter) requirements discussions in this table, for additional information.

COMG4 – COMS Requirements

Minn. R. 7007 Permittee requirement to comply with all applicable EGU COMS requirements regardless if they are in the permit.

Minn. R. 7017 EQUI82, EQUI83, and EQUI100 COMS requirements. 40 CFR 60 EQUI85 NSPS COMS requirements.

40 CFR 75 EQUI82, EQU83, EQUI85, and EQUI100 Acid Rain Program Opacity Monitoring.

COMG6 – SO2, NOX, & CO2 CEMS, & Flow Monitors Requirements

Minn. R. 7007 Permittee requirement to comply with all applicable EGU CEMS requirements regardless if they are in the permit.

Minn. R. 7017 EGU CEMS operating, monitoring, and submittal requirements.

40 CFR 60 EQUI85 CEMS operating requirements.

40 CFR 75 EGU Acid Rain Program CEMS operating, monitoring, recordkeeping, reporting, and QA/QC requirements.

COMG7 – Part 63 subp. UUUUU

40 CFR pt. 63 MATS limits, testing, monitoring, recordkeeping, and reporting requirements. Refer to subp. UUUUU applicability discussion in Section 2.4.

Minn. R. 7007 Permittee must comply with any subp. UUUUU revisions regardless if such revisions are incorporated into the permit.



COMG8 - CO CEMS Requirements

Minn. R. 7007

Permittee requirement to comply with all applicable EQUI52 and EQUI71 CEMS requirements regardless if they are in the permit; CO CEMS data reduction requirements for determining CO emission rates.

Minn. R. 7017 EQUI85 and EQUI100 CO CEMS operating, monitoring, submittal, and QA/QC requirements.

COMG9 - EGU Acid Rain, Ignitor Gun, Consent Decree, Hg Control, & Test Burn Additional Requirements

40 CFR 72 EGU Acid Rain Program requirements.

40 CFR 241; Minn. R. 7007 EGU Test Burn requirements.

CAAA of 1990; Minn. Stat. § 116; Title I Condition: 40 CFR 52

EGU Consent Decree requirements.

Minn. R. 7007 EGU Ignitor Gun monitoring and recordkeeping requirements.

Minn. R. 7011.0561 EGU Minnesota requirements for control of Hg emissions.

COMG10 Title I Condition: 40 CFR 52; Minn. R. 7007

Reasonable Possibility requirements for 2015 coal stockpile expansion.

EQUI1 – Crusher EQUI3 – Unit 1&2 Fly Ash Silo EQUI4 - Unit 1&2 Fly Ash Separator

Minn. R. 7007 Requirement to vent emissions to specified COMG3 fabric filter (EQUI1/TREA37, EQUI3/TREA39, EQUI4/TREA40).

Minn. R. 7011

Industrial Process Equipment Rule (IPER) PM and opacity limits – this equipment is post-1969 and the IPER applies because there isn’t another applicable standard of performance.

EQUI5 – Unit 3 Limestone Silo EQUI6 – Unit 3 Limestone Day Bin 1 EQUI7 - Unit 3 Limestone Day Bin 2

Title I Condition: Avoid major modification under 40 CFR 52; Minn. R. 7007

Requirement to vent emissions to specified COMG3 fabric filter (EQUI5/TREA1, EQUI6/TREA42, EQUI7/TREA43).

Minn. R. 7011 IPER PM and opacity limits – this equipment is post-1969 and the IPER applies because there isn’t another applicable standard of performance.

Title I Condition: Avoid major modification under 40 CFR 52

These emission units were new emission units installed as part of the PER003 EQUI100 control equipment retrofit project, and Title I Limits to Avoid major modification were necessary to restrict PM and PM10 emission increases to less than the PSD significant level for each pollutant.

EQUI23 - Unit 3 Emergency Gen.

40 CFR 60 NSPS subp. IIII requirements - EQUI23 is subject to NSPS subp. IIII as stated at 40 CFR 63.6590(c)(7).

40 CFR 63

NESHAP subp. ZZZZ requirements – EQUI23 is a 2012 398 hp 250 kW compression ignition new emergency generator regulated under NSPS subp. IIII because the Permittee does not test EQUI23 at a stationary RICE test cell/stand 40 CFR 63.6585, EQUI23 is located at a major source of HAP emissions, and the Permittee commenced EQUI23 construction on or after June 12, 2006. EQUI23 meets the requirements of pt. 63, subp. ZZZZ by meeting the requirements of 40 CFR pt. 60, subp. IIII as stated at 40 CFR 63.6590(c)(7).

40 CFR 89 RICE emission limits as referenced from 60.4202(a)(2) and 40 CFR 60.4205(b).

Minn. R. 7005 Fuel type limited by design.

Minn. R. 7007 Operating hours and fuel type recordkeeping; Best Management Practices.


Subject item* Applicable regulations Requirements Minn. R. 7011 Minnesota SO2 and opacity limits.

COMS: EQUI28 U3 EQUI29 U1 EQUI30 U2 EQUI34 U4

Minn. R. 7017 Minnesota requirements for periodic COMS calibration error audits.

CEMS: EQUI35 U4 flow EQUI36 U1 SO2 EQUI37 U1 NOX EQUI38 U1 CO2 EQUI39 U1 flow EQUI40 U2 SO2 EQUI41 U2 NOX EQUI42 U2 CO2 EQUI43 U2 flow EQUI44 U3 SO2 EQUI45 U3 NOX EQUI50 U3 CO2 EQUI51 U3 flow EQUI53 U4 SO2 EQUI54 U4 NOX EQUI55 U4 CO2

40 CFR pt. 75 EGU SO2, NOX, CO2, and Flow Rate CEM QA/QC requirements.

EQUI52 – CO CEMS Minn. R. 7017 EQUI85 and EQUI100 CO CEMS QA/QC requirements. EQUI71 – CO CEMS

EQUI81 - Reciprocating IC Engine

40 CFR 60 NSPS subp. IIII requirements – EQUI81 is subject to NSPS subp. IIII as stated at 40 CFR 63.6590(c)(7).

40 CFR 63

NESHAP subp. ZZZZ requirements – EQUI81 is a 2009 480 hp 300 kW compression ignition new emergency generator regulated under NSPS subp. IIII because the Permittee does not test EQUI81 at a stationary RICE test cell/stand 40 CFR 63.6585, EQUI81 is located at a major source of HAP emissions, and the Permittee commenced EQUI81 construction on or after June 12, 2006. EQUI81 meets the requirements of pt. 63, subp. ZZZZ by meeting the requirements of 40 CFR pt. 60, subp. IIII as stated at 40 CFR 63.6590(c)(7).




Minn. R. 7011 Minnesota SO2 and opacity limits.

EQUI82 – Unit 1 EQUI83 – Unit 2

40 CFR 63 Mercury and Air Toxics Standards HCl testing – refer to subp. UUUUU applicability discussion in Section 2.4.

40 CFR 64 Compliance Assurance Monitoring. 40 CFR 75 Acid Rain Monitoring. 40 CFR 76 Acid Rain NOX Reduction Program.


Subject item* Applicable regulations Requirements CAAA of 1990; Minn. Stat. § 116; Minn. R. 7007; Title I Condition: 40 CFR 52

Consent Decree limits and testing for NOX, SO2, and PM emissions, and additional requirements.

Minn. R. 7007 Permitted fuels, control equipment operating requirements, and boiler shutdown requirement.

Minn. R. 7011

Indirect Heating Equipment Rule (IHER) PM, SO2, and opacity limits – these existing units (constructed before January 31, 1977) are not subject to any other standard of performance therefore the IHER applies.

Minn. R. 7017 Emissions monitoring and stack testing requirements.

Title I Condition: 40 CFR 52

Filterable PM limit based on 1976 PM modeling for 1977 EQUI85/Boiler 4 PSD construction permit. (EQUI85 construction was a major modification to an existing major PSD source).

EQUI85 – Unit 4

40 CFR 60

NSPS subp. D PM, SO2, NOX, and opacity limits, testing, and monitoring apply because EQUI85 construction commenced January 1978 (after subp. D August 17, 1971 but before subp. Da September 18, 1978 applicability date).

40 CFR 64 Compliance Assurance Monitoring. 40 CFR 75 Acid Rain Monitoring. 40 CFR 76 Acid Rain NOX Reduction Program. CAAA of 1990; Minn. Stat. § 116; Minn. R. 7007; Title I Condition: 40 CFR 52


Minn. R. 7007 Permitted fuels, control equipment operating requirements, and state PM, PM10, and PM2.5 emission limits.


Minn. Stat. § 216B Minnesota Mercury Emissions Reduction Act requirements.


PM and SO2 BACT limits and PM modeling-based limit from 1977 EQUI85 PSD construction permit (EQUI85 construction was a major modification to an existing major PSD source); CO BACT limit and monitoring for 2010 low NOX burner installation (major modification for CO); PM testing for PM BACT limit.


Fluorides limit, testing, and control equipment operation requirements to avoid PSD major modification; limit imposed by PER007 because of reasonable possibility that EQUI85 control equipment retrofit fluorides emissions increase could be greater than 50% of the 3 tpy fluorides significance threshold at 40 CFR 52.21(b)(23)(i).



EQUI86 - Unit 4 Lime Silo EQUI87 - Unit 4 Lime Day Bin A EQUI88 - Unit 4 Lime Day Bin B EQUI89 - Unit 4 Lime Day Bin C EQUI90 - Unit 4 Lime Day Bin D EQUI91 - Unit 4 Lime Day Bin E EQUI93 - Fly Ash Silo B EQUI94 - Fly Ash Silo B Loadout - Truck Bay

Minn. R. 7011 Title I Condition: Avoid major modification under 40 CFR 52; Minn. R. 7007

IPER PM and opacity limits – this equipment is post-1969 and the IPER applies because there isn’t another applicable standard of performance. PM, PM10, and PM2.5 limits; Requirements to vent emissions to specified COMG3 fabric filter (EQUI86/TREA23, EQUI87/TREA24, EQUI88/TREA25, EQUI89/TREA26, EQUI90/TREA27, EQUI91/TREA29, EQUI93/TREA31, EQUI94/TREA32). These emission units were new emission units installed as part of the PER007 EQUI85 control equipment retrofit project, and Title I Limits to Avoid major modification were necessary to restrict PM, PM10, and PM2.5 emission increases to less than the PSD significant level for each pollutant.

EQUI97 - Fly Ash Silo A Loadout - Truck Bay


IPER PM and opacity limits – this equipment is post-1969 and the IPER applies because there isn’t another applicable standard of performance. PM, PM10, and PM2.5 limits and requirement to vent emissions to COMG3 fabric filter (EQUI97/TREA2). This EQUI97/EU018 fly ash truck loadout emission unit was a new emission unit installed as part of the PER003 EQUI100 control equipment retrofit project, and Title I Limits to Avoid major modification were necessary to restrict PM and PM10 emission increases to less than the PSD significant level for each pollutant. However a change in the method of operation occurred in 2011 when (wetted) ash was no longer disposed of as waste so that (dry) ash could be sold as a product for cement manufacture. Because the change occurred after the 07/15/2008 grandfather rule repeal, the grandfather provision of using PM10 as a surrogate for PM2.5 emissions (that ended 07/15/2008) can not be employed for this change and stand-alone EQUI97 PM2.5 permit requirements are necessary.

EQUI98 - Fly Ash Silo A


IPER PM and opacity limits – this equipment is post-1969 and the IPER applies because there isn’t another applicable standard of performance. PM and PM10 limits and requirement to vent emissions to COMG3 fabric filter (EQUI98/TREA36). This EQUI98/EU017 fly ash storage silo was a new emission unit installed as part of the PER003 EQUI100 control equipment retrofit project, and Title I Limits to Avoid major modification were necessary to restrict PM and PM10 emission increases to less than the PSD significant level for each pollutant for the project.



EQUI99 - Hg Additive Handling and Unit 3 PAC Silo


IPER PM and opacity limits – this equipment is post-1969 and the IPER applies because there isn’t another applicable standard of performance. PM and PM10 limits; Requirements to vent emissions to specified COMG3 fabric filter (EQUI99/TREA41). This emission unit was installed as part of the PER003 EQUI100 control equipment retrofit project, and Title I Limits to Avoid major modification were necessary to restrict PM and PM10 emission increases to less than the PSD significant level for each pollutant.

EQUI100 - Unit 3

40 CFR 63 Mercury and Air Toxics Standards HCl testing - refer to subp. UUUUU applicability discussion in Section 2.4.

40 CFR 75 Acid Rain Monitoring. 40 CFR 76 Acid Rain NOX Reduction Program. 40 CFR 64 Compliance Assurance Monitoring. 40 CFR 75 Acid Rain Monitoring. 40 CFR 76 Acid Rain NOX Reduction Program. CAAA of 1990; Minn. Stat. § 116; Minn. R. 7007; Title I Condition: 40 CFR 52


Minn. R. 7007 Permitted fuels, control equipment operating requirements, and state PM and PM10 emission limits.

Minn. R. 7011

Indirect Heating Equipment Rule (IHER) PM, SO2, and opacity limits – this existing unit (constructed before January 31, 1977) is not subject to any other standard of performance therefore the IHER applies.


Minn. Stat. § 216B Minnesota Mercury Emissions Reduction Act requirements.


Fluorides and lead limits, testing, and control equipment operating requirements to avoid PSD major modification.


CO BACT limit and monitoring for 2007 PER003 low NOX burner installation (major modification for CO).

EQUI102 - Crusher House C-14

Minn. R. 7007 Requirements to vent emissions to specified COMG3 fabric filter (EQUI102/TREA38).


EQUI106 - STRU13 Sorbent Trap Hg Sampler

40 CFR pt. 63 MATS Hg monitoring requirements; Refer to subp. UUUUU applicability discussion in Section 2.4.

Minn. R. 7017 Minnesota Hg monitoring requirements.

EQUI107 - STRU13 PM CEMS

40 CFR 63 MATS PM monitoring requirements. Minn. R. 7017 Minnesota PM CEMS requirements. CAAA of 1990; Title I Condition: 40 CFR 52; Minn. Stat. § 116; Minn. R. 7007

Consent Decree PM CEMS requirements.

EQUI108 - Boiler 40 CFR 63 MATS PM monitoring requirements.


Subject item* Applicable regulations Requirements 4 PM CEMS Minn. R. 7017 Minnesota PM CEMS requirements.

CAAA of 1990; Title I Condition: 40 CFR 52; Minn. Stat. § 116; Minn. R. 7007

Consent Decree PM CEMS requirements.

EQUI109 - Boiler 3 Hg CEMS


Minn. R. 7017 Minnesota Hg monitoring requirements. Minn. R. 7007; Minn. Stat. 216B

Minnesota Mercury Emissions Reduction Act requirements.

EQUI110 - Boiler 4 Hg CEMS


Minn. R. 7017 Minnesota Hg monitoring requirements. Minn. R. 7007; Minn. Stat. 216B

Minnesota Mercury Emissions Reduction Act requirements.

EQUI111 - Rail Unloading EQUI112 - Lowering Well EQUI113 - Coal Silos EQUI114 - Transfer House A C16/C18 EQUI115 - Transfer House B C9/C10 EQUI116 - Dust Tank EQUI117 - Units 1, 2, 3 Bunkers & Trippers

Minn. R. 7007

Requirements to vent emissions to specified COMG3 fabric filter (EQUI111/TREA46, EQUI112 & EQUI113/TREA47, EQUI114/TREA48, EQUI115/TREA49, EQUI116/TREA50, EQUI117/TREA51).

Minn. R. 7011 IPER PM and opacity limits – this equipment is pre-1969 and the IPER applies because there isn’t another applicable standard of performance.

EQUI118 - Unit 4 Bunkers & Trippers

Minn. R. 7007 Requirements to vent emissions to specified COMG3 fabric filter (EQUI118/TREA52).


EQUI119 - Emergency Gen. Unit 4; 2206 hp; 1500 kW; CI; 2015

40 CFR 60

NSPS subp. IIII requirements – EQUI119 is a 2015 2206 hp compression ignition new emergency generator regulated under NSPS subp. IIII because EQUI119 was manufactured after April 1, 2006, the Permittee commenced EQUI119 construction on or after July 11, 2005, and EQUI119 is not a fire pump engine.

40 CFR 63

NESHAP subp. ZZZZ requirements – EQUI119 is a 2015 2206 hp compression ignition new emergency generator regulated under NESHAP subp. ZZZZ because EQUI119 has a hp rating greater than 500 hp, is located at a major source of HAP emissions, and the Permittee commenced construction of EQUI119 on or after December 19, 2002.






Minn. R. 7011 Minnesota SO2 and opacity limits.

EQUI120 - Unit 4 Activated Carbon Silo



PM, PM10, and PM2.5 limits; Requirements to vent emissions to specified COMG3 fabric filter (EQUI120/TREA30). This emission unit was installed as part of the PER007 EQUI85 control equipment retrofit project, and Title I Limits to Avoid major modification were necessary to restrict PM, PM10, and PM2.5 emission increases to less than the PSD significant level for each pollutant.

EQUI122 - Fly Ash Silo A Loadout Spout with Ventilated Annular Hood



PM, PM10, and PM2.5 limits; Requirements to vent emissions to specified COMG3 fabric filter (EQUI122/TREA36). This emission unit was installed in 2009 as part of the EQUI100 control equipment retrofit project authorized by PER003 issued March 2007. EQUI122 Title I Limits to Avoid major modification are necessary to restrict PM, PM10, and PM2.5 emission increases to less than the PSD significant level for each pollutant because uncontrolled PM, PM10, and PM2.5 emissions from the PER003 retrofit project exceeded the PSD significant emissions rates (25, 15, and 10 tpy, respectively). PER003 (March 2007) did not include EQUI122 and no permit was issued for this installation. Therefore, the grandfather provision of using PM10 as a surrogate for PM2.5 emissions (that ended 07/15/2008) can not be employed and stand-alone EQUI122 PM2.5 permit requirements are necessary.

FUGI1 – Unit 4 Cooling Tower FUGI2 – Unit 3 Cooling Tower

Minn. R. 7011 IPER PM limit – this equipment is post-1969 and the IPER applies because there isn’t another applicable standard of performance.

FUGI3 - Unpaved Roads Minn. R. 7011 Best Management Practices for control of fugitive dust

from unpaved roads.

FUGI9 - Coal Stockpile - Wind Erosion

Minn. R. 7007 Coal stockpile working area acreage limit to restrict wind erosion emissions increase from coal stockpile expansion.

40 CFR 60 Prepare and operate in accordance with a submitted fugitive coal dust emissions control plan.

FUGI10 - Paved Road Dust

Minn. R. 7007 Recordkeeping of control measures. Minn. R. 7011 Requirements for control of fugitive PM emissions.




Control of paved road fugitive dust emissions to restrict PM, PM10, and PM2.5 emission increases from the EQUI100 and EQUI85 control equipment retrofit projects and avoid major modification for each project under 40 CFR 52.21. FUGI10 was modified as part of the EQUI100 and EQUI85 retrofit projects due to the addition of paved road truck traffic for transport of EQUI100 and EQUI85 control equipment reagents and dry fly ash. Requirements are title I conditions for this modified source because the Permittee proposed these requirements in the Aug 2006 PER003 application as title I conditions.

FUGI11 - Coal Stockpile Material Handling (Existing Coal Drop Onto Pile Segment and Ten New Portable Conveyors/Eleven Drop Points Segment)


Minn. R. 7007

Coal moisture content, number of portable conveyor drop points, conveyor capacity, and maximum wind speed requirements to restrict portable conveyors PM, PM10, and PM2.5 emission increases to less than the significant emission rate to avoid major modification under 40 CFR 52.21. Recordkeeping of coal moisture content, number of conveyor drop points, and conveyor capacity.

40 CFR 60 Prepare and operate in accordance with a submitted fugitive coal dust emissions control plan.

STRU 13: Units 1, 2, & 3 Common Stack

40 CFR 50 Monitoring 1-hour pound per hour SO2 emission rate

TFAC1 - Total Facility

Minn. R. 7002 Emission Fee requirements.

Minn. R. 7007

Permit appendices, permit shield, operate control equipment, follow O&M plan, inspections, general conditions, monitoring equipment, recordkeeping, permit amendments, and extensions.

Minn. Rs. 7007 & 7009, Minn. Stat. § 116

Comply with ambient air standards and modeling requirements.

Minn. Rs. 7009 & 7011, Title I Condition: Avoid major modification under 40 CFR 52; 40 CFR 60

Comply with fugitive emission control plan.

Minn. R. 7017 Testing and monitoring requirements.

Minn. R. 7019 Emission Inventory, operation changes, shutdown/breakdown, and deviations reporting requirements.

Minn. R. 7030 Noise requirements.

Minn. R. 7011 Circumvention prohibited, control of fugitive emissions.

Title I Condition: 40 CFR 52; Minn. R. 7007 Reasonable Possibility requirements.


Subject item* Applicable regulations Requirements TREA5 – Unit 3 SCR TREA6 - Unit 4 LNB/SOFA TREA7 - Unit 4 ROTA-Mix SNCR TREA8 Unit 3 Low NOx Burners/Over-Fire Air TREA11 - Unit 2 ROTA-Mix SNCR TREA12 - Unit 1 ROFA TREA13 - Unit 2 ROFA TREA15 - Unit 1 ROTA-Mix SNCR

40 CFR 64 NOX CAM and corrective action requirements.

Minn. R. 7007 Operate and maintain control device.

TREA9 - Unit 3 Fabric Filter

40 CFR 64 PM and PM10 CAM requirements.

Minn. R. 7007 PM, PM10, and PM2.5 control efficiency requirements; TREA9 operation, maintenance, and corrective action requirements.


Lead control efficiency and TREA9 operation and maintenance requirements to restrict potential lead emissions increase to avoid PSD major modification for PER003 EQUI100 control equipment retrofit.

TREA10 - Unit 3 Wet FGD

40 CFR 63; Minn. R. 7007 HCl emissions corrective actions. 40 CFR 64 SO2 CAM requirements.

Minn. R. 7007 HCl control efficiency requirement; operate TREA10 according to O&M plan; fluoride emissions corrective actions.

Title I Condition: Avoid major modification under 40 CFR 52; 40 CFR 50; Minn. R. 7007; Minn. R. 7009

Requirement to operate and maintain TREA10.


Fluorides control efficiency and monitoring requirements to avoid PSD major modification for PER003 EQUI100 control equipment retrofit.

TREA14 – Unit 2 Fabric Filter TREA16 – Unit 1 Fabric Filter

40 CFR 64 PM CAM Requirements. Minn. R. 7007 Follow O&M plan, corrective action requirements.

Title I Condition: 40 CFR 52; Minn. R. 7007

PM control efficiency requirements & TREA14 and TREA16 operating requirements to ensure compliance with EQUI82 and EQUI83 filterable PM limit based on modeling for Boiler 4 PSD permit.

TREA21 Unit 4 Semi-Dry FGD & Fabric Filter

40 CFR 50; Title I Condition: 40 CFR 52; Title I Condition: Avoid major modification under 40 CFR 52; Minn. R. 7007

TREA21 operating and maintenance requirement to ensure EQUI85 compliance with PM and SO2 BACT and PSD modeling-based limits, and fluorides limit to avoid PSD major modification from PER 007 control equipment retrofit.


Subject item* Applicable regulations Requirements 40 CFR 63; Minn. R. 7007 HCl corrective actions.

40 CFR 64 PM, PM10, PM2.5, SO2, and fluorides CAM requirements.

Minn. R. 7007 PM10, PM2.5, and HCl control efficiency requirements.

Title I Condition: 40 CFR 52; Minn. R. 7007

PM control efficiency requirement to ensure compliance with PM BACT and modeling limit.


Fluorides control efficiency requirement to limit PER007 control equipment retrofit emissions increase to less than significant and avoid PSD major modification.

TREA22 – Unit 4 ACI TREA28 – Unit 3 ACI

Minn. R. 7007 Operation, maintenance, and corrective action requirements.

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

3. Technical information

3.1 Emission Calculations

Attachment 1 is the GI-07 form and Facility PTE calculations. Attachment 2 is the coal stockpile expansion project emissions calculation spreadsheet.

The Table 3 unlimited emissions increase for new portable conveyors was calculated using the same inputs listed in the Attachment 2 "Input Summary" worksheet except the 20% moisture content was replaced by the 17.8% geometric mean moisture content from AP-42 table 11.9-3 for coal loading, to calculate unlimited PTE. This moisture content is a reasonable worst-case moisture subbituminous coal content and demonstrates that the coal stockpile expansion project needed limits to avoid a PSD major modification for PM emissions.

Note that the MATS provides multiple emission limit options. For EQUI82 and EQUI83 SO2 limited emissions, the (most restrictive) MATS 0.20 pounds per million Btu heat input SO2 limit option was not used to calculated limited SO2 because the Permittee elected to comply with the HCl emission limit option for these units. As a result, Units 1 and 2 limited SO2 emissions are based on the most stringent applicable SO2 limit of 0.700 pounds per million Btu heat input (from the Consent Decree).

3.2 Dispersion modeling

a. Revisions of COMG1 SO2 Modeling-Based Limits Based On Review of 1987-1988 Facility SO2 Modeling

The COMG1 1-hour SO2 limits and citations were revised based on October 19, 1987 and January 13, 1988 Air Quality Division memoranda from Dennis Becker to J. David Thornton. The memoranda are a review of SO2 modeling and state the following in part:

“Current MP – Clay Boswell emission limitations are: Emission limitation of 4.00 #SO2/MMBTU for units 1-2 Emission limitation of 4.00 #SO2/MMBTU for unit 3 Emission limitation of 1.20 #SO2/MMBTU for unit 4…


Dispersion modeling for MP – Clay Boswell’s primary configuration was performed to determine compliance with Minnesota and National Ambient Air Quality Standards (i.e., MAAQS and NAAQS) for sulfur dioxide as required per USEPA Stack Height Regulations (40 CFR Part 51). It reflects U.S. EPA Good Engineering Practice (GEP) stack parameters (i.e., units 1-3 at 667.50 feet versus 700 feet) for federal purposes and actual stack parameters for state purposes.

Model results indicate no SO2 emission reductions are necessary when units 1-3 are vented through the common stack using GEP stack parameters. However, model results do indicate SO2 emission reductions are necessary to meet the state 1-hour standard when units 3 and 4 are online and units 1&2 are not operating…

Below are three possible solutions which will bring MP – Clay Boswell into modeled compliance with Minnesota’s 1-hour ambient sulfur dioxide standard when units 1&2 are not operational…

1) unit 3 at 3.52 #SO2/mmBtu and unit 4 at 1.20 #SO2/mmBtu, or 2) unit 3 at 4.00 #SO2/mmBtu and unit 4 at 0.88 #SO2/mmBtu, or 3) unit 3 at 3.67 #SO2/mmBtu and unit 4 at 1.10 #SO2/mmBtu...

…MP – Clay Boswell units 1 and 2 (when) vented through the 250 foot stack requires a 70.32 percent emission reduction to meet the SO2 NAAQS with GEP stack parameters at unit 3. Additionally, MP – Boswell unit 3 requires a 25.68 percent to meet SO2 MAAQS with actual stack parameters at unit 3. Therefore, required MP – Clay Boswell (ALTERNATE CONFIGURATION) emission limitations are:

Emission limitation of 1.18 #SO2/MMBTU for units 1-2 Emission limitation of 2.97 #SO2/MMBTU for unit 3 Emission limitation of 1.20 #SO2/MMBTU for unit 4.”

The SO2 ambient air quality standards effective during this 1987-1988 modeling exercise are shown in Table 8 below.

Table 8. SO2 Ambient Air Quality Standards Effective October 1987 MAAQS NAAQS

Comments Avg period ug/m3 ppm Avg period ug/m3 ppm

1-hour 1300 0.5 none MAAQS are those specified in October 1987 BEC modeling conducted by MPCA. NAAQS ug/m3 values based on ppm equivalency values published in Minn. R. 7009.0080 and its predecessors.

3-hour 1300 0.5 3-hour 1310 0.5

24-hour 365 0.14 24-hour 367 0.14

annual 60 0.02 annual 60 0.02

Based on this memorandum, it is evident that:

i. The 1.18 lb/mmBtu SO2 Unit 1 and Unit 2 limits are necessary to protect the ‘SO2 NAAQS’ when venting in the Alternate Configuration (EQUI82 and EQUI83 operating and venting through STRU12, EQUI100 operating and venting through STRU13 at the Good Engineering Practice (GEP) 667.50 foot height and EQUI85 operating).

ii. The ‘SO2 NAAQS’ is the 3-hour NAAQS because a 1-hour SO2 NAAQS was not promulgated until 2010.

iii. The 1.18 lb/mmBtu EQUI82 and EQUI83 limits are necessary to meet the 1-hour SO2 MAAQS because Unit 3 SO2 must be restricted to 2.97 lb/mmBtu in order to meet the 1-hour MAAQS when Units 1 and 2 vent through STRU12.


The SO2 emission limit revisions are tabulated in Table 9 below.

Table 9. COMG1 SO2 Limits Revisions

Unit

Units 1-4 SO2 Limits1

(lb/mmBtu) When Units 1&2 vent

through STRU12

PER 007 Averaging

Time PER 007 Citation

PER 008 Averaging


1&2 1.18 1-hour M.R. 7009.0020 1-hour M.R. 7009.0020 3-hour 40 CFR 50.5

3 2.97 1-hour M.R. 7009.0020 1-hour M.R. 7009.0020

4 1.20 1-hour Title I Condition BACT and modeling

1-hour M.R. 7009.0020

3-hour Title I Condition BACT and modeling; 40 CFR 60.43(a)(2)

Unit

Units 1-4 SO2 Limits1 (lb/mmBtu) When

Units 1&2 vent through STRU13

PER 007 Averaging


PER 008 Averaging


1,2,3 4.00 1-hour M.R. 7011.0510 M.R. ch. 7009

3-hour M.R. 7011.0510 3-hour 40 CFR 50.5 1-hour M.R. 7009.0020

4 1.20 1-hour

Title I Condition: 40 CFR Section 52.21(j) PSD BACT limit & ambient impacts analysis; 40 CFR Section 60.43

3-hour Title I Condition BACT & modeling; 40 CFR 60.43(a)

1-hour M.R. 7009.0020

1Limits include formula to determine limit when co-firing non-solid fossil fuel and coal according to Minn. R. 7011.0510 and 40 CFR Section 60.42(a) as applicable (PER 008 Section 60.43(a) limit no longer includes the proration formula for co-firing solid and liquid fossil fuel because all units no longer combust liquid fossil fuel).

b. 2014 SO2 and PM2.5 Modeling

Due to comments received during the public comment period for permit No. 06100004-007, the MPCA added a requirement to the permit for conducting modeling for the 1-hour SO2 NAAQS and 24-hr PM2.5 NAAQS. The results of that exercise are summarized in Table 10 below.

Table 10. 2014 Modeling Results

Pollutant Averaging period

NAAQS standard (µg/m3)

Total modeled concentration (µg/m3; including background)

Percent of standard (%) Tier

SO2 1-hr 196.0 (75 ppb) 186.601 95.2% 42

PM2.5 24-hr 35.0 28.17 80.5% 2 1without choke (diameter = 35.0 feet; choke removed in 2015); with choke (diameter = 20.0 feet) total concentration is 186.58 µg/m3; 2017 stack extension increased (height to 616 feet and) diameter to 32.0 feet 2 Tier 4 was incorrectly assigned by agency modeling staff during the modeling results review – Tier 4 can only apply when modeling is part of a project subject to PSD, and the 2014 modeling was not part of a PSD project

The SO2 modeling results were close to the NAAQS resulting in inclusion of the modeled SO2 emission rates (4450 lb/hr for STRU13 and 2600 lb/hr for STRU14) as 1-hour permit


limits in the permit (in COMG1). (Refer to Table 11 for comparison of the 30-day rolling average emissions as limited by the Consent Decree to the modeled lb/hr emission rates.) However, MPCA review of the modeling report the SO2 modeling results erroneously assigned Tier 4 for future changes to modeled SO2 parameters (located in the TFAC total facility subject item); Tier 4 only applies to modeling results for PSD-required modeling. The correct tier should have been Tier 3. Regardless, the Permittee preferred and the agency agreed to a single remodeling requirement in light of the decision at United States Steel Corporation v. Minnesota Pollution Control Agency, 2015 WL 4508104 (Minn Ct. App. 2015).

Review of modeled PM2.5 parameter values shows a number of discrepancies between the 2014 values and the 2016 updated reissuance application values for the same PM2.5 modeling parameters. As a result, this permit requires PM2.5 remodeling with updated parameters from the 2016 application.

c. Comparison of 2014 1-Hour SO2 Modeled Emission Rates and Consent Decree (CD) 30-day Rolling SO2 Limits

As part of the requirements for the Data Requirements Rule at pt. 51, subp. BB for demonstrating compliance with the 1-hour SO2 NAAQS, MPCA staff conducted an analysis to determine if the 30-day rolling average SO2 Consent Decree limits are as or more stringent than the 1-hour modeled SO2 emission rates. The MPCA used the following method:

i. Convert the CD limits (30-day rolling average in lb/mmBtu) to 30-day average limits expressed in lb/hr, using the heat rate input for the Facility EGUs.

ii. Using the methodology provided in EPA’s April 2014 “Guidance for 1-Hour SO2 Nonattainment Area SIP Submissions,” convert the NAAQS-compliant modeled lb/hr emission rate (also referred to as the critical emissions value) to a comparably stringent 30-day average limit, expressed in lb/hr. This conversion will use the conservatively calculated adjustment factors EPA provided in Appendix D of its guidance (the average ratio of 99th percentile 30-day average SO2 emission value to the 99th percentile of hourly SO2 emission value).

iii. Compare the comparably stringent (modeled) 30-day emission rates to the 30-day CD limits (in lb/hr) and show that the CD limits are equal to or less than the modeled limits, thereby ensuring that the federally enforceable CD limits provide for NAAQS attainment.

Using this method, the following results in Table 11 below were obtained demonstrating the Consent Decree 30-day rolling average SO2 emission limits are more restrictive than the modeled pound per hour SO2 emission rates.

Table 11. Comparison of modeled and Consent Decree SO2 emission rates

Stack NAAQS-compliant emissions rate (converted to 30-day average)

CD 30-day average emissions limits

(converted to lb/hr) STRU13 (Units 1, 2, & 3) 3454 lb/hr 1,430 lb/hr STRU14 (Unit 4) 1,846 lb/hr 204 lb/hr

d. Review of 2010 EQUI85 and 2008 EQUI100 PSD CO modeling

EQUI100 and EQUI81 CO emissions were modeled in 2008 as part of the EQUI100 Low-NOX burner and installation of EQUI81 project (PER003 and PER004). EQUI85 CO emissions were modeled in 2010 as part of the EQUI85 NOX reduction project (PER005).


Both projects were subject to PSD for CO emissions. Both modeled emissions rates were approximately ten-fold higher than the respective permitted emission rate. Table 12 shows the results of the modeling and support the existing CO modeling requirements that are currently in permit No. 06100004-007 and carried forward into permit No. 06100004-008.

Table 12. PSD CO SIL Modeling

Modeled CO emission rate

(lb/hr) 1-Hour

SIL

Percent of 1-hour SIL 8-Hour

SIL

Percent of 8-

hour SIL

Tier

CO Significant Impact Level (SIL) Value (μg/m3)

2,000 500

EQUI100 Low-NOX Project 5032.5

Predicted Impacts (μg/m3) 241.3 12.1% 1 118.4 23.7% 1

EQUI85 Low-NOX Project 9608.7

Predicted Impacts (μg/m3) 352.31 17.6% 1 144.22 28.8% 1

e. Review of 2007 Title V Modeling

Permit No. 06100004-003 required the Permittee to conduct title V modeling for NOX, PM10, and SO2. Requirements based on the modeling results were added by Permit No. 06100004-004. All requirements were Tier 1 requirements (the least restrictive for requirements when modeled parameters are changed) other than those for NOX which were Tier 2. However, NOX modeling included the three emergency generators but current agency modeling policy doesn’t include emergency generators providing the Permittee operates these sources according to best management practices (BMPs; permit No. 06100004-008 includes an appendix of BMPs). In addition, two of the three modeled emergency generators were older pre-1975 equipment that were replaced with new lower-emitting (EQUI23 and EQUI119) emergency generators (in 2012 and 2015, respectively).

Many of the 2007 modeled parameters are no longer applicable due to equipment changes as well as inaccuracy of some of the modeled parameter data. Table 13 demonstrates the results of the modeling and the percent of each impact relative to the appropriate ambient air standard. Due to the low impacts, equipment changes, parameter inaccuracies, and 2014 SO2 modeling, these 2007 parameters and re-modeling requirements based on this modeling, are not carried forward into permit No. 06100004-008. In addition, the Permittee is not required to update the Title V modeling at this time because SO2 was modeled for the 1-hour NAAQS in 2014, PM2.5 re-modeling is required by permit No. 06100004-008, and emergency engines are operated according to BMPs.


Table 13. 2007 NOX, PM10, and SO2 Title V Modeling Minnesota Ambient Air Quality Standards (μg/m3)

Pollutant 1-Hour 3-Hour 24-Hour Annual NOX - - - 100 PM10 - - 150 50 SO2 1,300 1,300 365 60

SO2 (Northern MN) - 915 - - Predicted Impacts including Monitored Background Concentrations (μg/m3 / percent of standard)

Pollutant 1-Hour 3-Hour 24-Hour Annual Tier NOX - - - 72.7/72.7% 2 PM10 - - 60.8/40.5% 25.9/51.8% 1 SO2 692.9/53.3% NA 205.9/56.4% 13.2/22.0% 1

SO2 (Northern MN) - 526.9/57.6% - - 1

3.3 CEMS-based Normal Dependable Heat Input

The Acid Rain Program monitoring requirements in part 75 include requirements to monitor and report heat input for the four EGUs at the Facility. These values exceed those derived from the manufacturer’s rated heat input and the heat input determined by fuel use and heat content. This phenomena has been studied by the Electric Power Research Institute, who determined the issue is related to US E.P.A. Method 2 for determining stack gas velocity and volumetric flow rate. Regardless, using the heat input data obtained by this monitoring, the Permittee conducted an analysis to determine the CEMS-based Normal Heat Input Capacity1.

Because the heat input measurements are rigorously quality assured under the Part 75, heat input values that rarely occurred were not automatically dismissed, but rather, only those values that by simple inspection could be identified as clearly unrepresentative due to their separation from the rest of the data were dismissed. Using this method, the Permittee concludes (and the agency accepts the conclusion that) the heat inputs (for emission calculation purposes) are appropriately revised to those in Table 14 below:

Table 14. CEMS-based Normal Dependable Heat Input Unit Heat Input (mmBtu/hr) 1 1075 2 910 3 4425 4 6800

3.4 EQUI85 and EQUI100 CO BACT Requirements Revision

The EQUI100 CO BACT determination made in 2007 (as part of PER003) resulted in a 0.15 lb/mmBtu CO limit on a 24-hour rolling average, excluding startup, shutdown, and malfunction. The EQUI85 CO BACT determination made in 2010 (as part of PER005) resulted in a 0.15 lb/mmBtu CO limit on a 30-day rolling average, excluding startup and shutdown,

1 This is similar to the analysis conducted by Xcel Energy for the Allen S. King plant permit No. 16300005-012 issued by

the Minnesota Pollution Control Agency on June 20, 2013.


and a limit of 28,826 lb/hr on a 1-hour average for startup and shutdown operations (operations at or below 320 MWgross).

The Permittee indicated their desire to revise the BACT limits as follows:

a. Change the EQUI100 averaging period to a 30-day rolling average and remove the startup/shutdown/malfunction exemption so that all EQUI100 emissions are subject to the CO BACT limit;

b. Remove the EQUI85 startup/shutdown 320 MWgross threshold and the startup/shutdown lb/hr CO limit so that all EQUI85 emissions are subject to the 0.15 lb/mmBtu CO BACT limit;

c. Allow use of a 5% CO2 diluent cap for converting the CEMS ppmv data to lb/mmBtu data, to avoid over-calculation of CO lb/mmBtu emission rates that may occur during low operating loads associated with startup and shutdown.

No revised EQUI85 CO BACT analysis is necessary to make the requested change to the EQUI85 CO BACT limit. This is because elimination of the 28,826 lb/hr startup/shutdown CO limit results in a more stringent limit due to the application of the 0.15 lb/mmBtu limit to startup/shutdown emissions. At 0.15 lb/mmBtu, EQUI85 can emit no more than 1050 lb CO/hr at full load (6800 mmBtu/hr), which is considerably lower than the existing 28,826 lb/hr startup/shutdown CO limit. Also, EQUI85 operates at less than full load during startup and shutdown, so the actual CO emission rate will be less than 1050 lb/hr during startup and shutdown which further supports making the requested change to the EQUI85 CO BACT limit without requiring a revised EQUI85 BACT analysis.

For EQUI100, the Permittee submitted a BACT analysis for changing the EQUI100 CO BACT 24-hour averaging period to a 30-day rolling average period, and for removing the BACT exemption for startup, shutdown, and malfunction. The MPCA reviewed the analysis and agreed to lengthen the averaging period, but also requested CO CEMS data to determine if the existing 0.15 lb/mmBtu limit was BACT.

The Permittee submitted EQUI100 CO CEMS data for the period from 2012 through most of 2017. MPCA staff analyzed the data and determined an achievable EQUI100 CO BACT limit would be 0.11 lb/mmBtu on a 30-day rolling average basis. The Permittee then indicated there were economic issues that were not considered in the MPCA analysis of the CEMS data, and proposed a limit of 0.13 lb/mmBtu on a 30-day rolling average to account for the economic issues. The MPCA requested a revised EQUI100 CO BACT analysis with economic data supporting the 0.13 lb/mmBtu proposed limit. In lieu of submitting a revised analysis with supporting economic data, the Permittee withdrew the request to revise the EQUI100 BACT limit other than to remove the startup/shutdown/malfunction exemption, and add the 5% CO2 diluent cap.

The changes made to the EQUI85 and EQUI100 CO BACT requirements do not comprise a PSD permit action because the changes made the original BACT determinations more stringent by removing provisions for CO emissions during startup and shutdown. Finally, BACT remains good combustion practices for both units.

Also, CO CEMS data reduction requirements were added to COMG8 for determining the EQUI85 30-day rolling average emission rate and the EQUI100 24-hour rolling average CO emission rate. The requested 5% CO2 diluent cap was included in the equation for calculating hourly CO emission rates. The diluent cap concept was based on the use of the cap in part 75, Appendix F and part 63, subp. UUUUU, Appendix A to avoid issues caused by low CO2 diluent levels measured during low operating loads (that may occur during startup and shutdown).


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 the facility is in compliance with applicable requirements.

The Permittee submitted updated CAM proposals (Attachment 5) for EQUI82, EQUI83, EQUI85, and EQUI100 as required by 40 CFR Section 64.3.

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 emission limits; · the variability of emissions over time; · the type of available monitoring, process, maintenance, or control equipment data

for the subject item; · the technical and economic feasibility of possible periodic monitoring methods; and · monitoring requirements for similar units.

Table 15 summarizes the monitoring requirements. The EQUI100 Hg CEMS (EQUI109) is used to meet the requirements of Minn. R. 7011.0561, subp. 5(A) and Minn. Stat. § 216B.681 whereas the STRU13 sorbent trap (EQUI106) is used to monitor Hg in the common stack for EQUI82, EQUI83, and EQUI100 to meet the requirements of a monitoring plan submitted under Section 63.10000(d)(1). EQUI85 Hg CEMS (EQUI110) is used to meet Minn. R. 7011.0561, subp. 5(A), Minn. Stat. § 216B.681, and the MATS Hg monitoring requirements.

Table 15. Monitoring

Subject Item* Requirement (basis) Monitoring method Discussion

COMG1

EQUI82 & EQUI83 SO2 <= 1.18 lb/mmBtu 1-hr avg for each boiler when EQUI82&EQUI83 vent through STRU12. [Minn. R. 7009.0020]

SO2 CEMS with data recorded by data acquisition and handling system (DAHS)

CEMS provide real-time direct emissions measurement

COMG1

EQUI82 & EQUI83 SO2 <= 4.00 lb/mmBtu 1-hr avg for each boiler when EQUI82 & EQUI83 vent through STRU13 & EQUI100 & EQUI85 are operating. [Minn. R. 7009.0020]

SO2 CEMS and DAHS CEMS provide real-time direct emissions measurement

COMG1

EQUI85 SO2 <= 1.20 lb/mmBtu 1-hr avg when EQUI85 operates alone, or when EQUI82 & EQUI83 vent through STRU12, or when EQUI82, EQUI83, & EQUI100 vent through STRU13. [Minn. R. 7009.0020]


COMG1 EQUI100 SO2 <= 2.97 lb/mmBtu 1-hr avg when EQUI82 & EQUI83 are operating & vent through STRU12. [Minn. R. 7009.0020]


COMG1

EQUI100 SO2 <= 4.00 lb/mmBtu 1-hr avg when EQUI100 operates alone or, when EQUI82 & EQUI83 operate & vents through STRU13 & EQUI85 is operating. [Minn. R. 7009.0020]


COMG1 STRU14 SO2 <= 2600 lb/hr 1-hr avg. [40 CFR 50.17] SO2 CEMS and DAHS




COMG1 STRU13 SO2 <= 4450 lb/hr 1-hr avg. [40 CFR 50.17]

SO2 CEMS and DAHS

CEMS provide real-time direct emissions measurement; requirement to determine the 1-hour SO2 lb/hr emission rate using the EQUI105 DAS and SO2 CEMS (EQUI36, EQUI40, and EQUI44) for each of the three boilers that vent through STRU13 is listed under STRU13

COMG1

EQUI82, EQUI83, & EQUI100 SO2 for each boiler <= 4.00 lb/mmBtu 3-hr avg for solid fossil fuel. When solid & gaseous fossil fuels are co-fired, the applicable standard is deter-mined by the following formula: w = 4z/(x+z) where: w = allowable SO2 emissions in lb/mmBtu 3-hr avg for each boiler x = % heat input gaseous fossil fuel for each boiler z = % heat input solid fossil fuel for each boiler. This limit applies regardless of operation & venting of other COMG1 boilers. [Minn. Rs. 7011.0505, subp. 3 and 7011.0510, subp. 1]


COMG1

EQUI82 & EQUI83 SO2 <= 4.00 lb/mmBtu 3-hr avg for each boiler when EQUI82 & EQUI83 vent through STRU13 & EQUI100 is operating. [40 CFR 50.5]


COMG1

EQUI82&EQUI83 SO2 <= 1.18 lb/mmBtu 3-hr avg for each boiler when EQUI82&EQUI83 vent through STRU12. [40 CFR 50.5]


COMG1 EQUI100 SO2 <= 4.00 lb/mmBtu 3-hr avg when EQUI82 & EQUI83 vent through STRU13. [40 CFR 50.5]


COMG1

EQUI85 SO2 <= 1.20 lb/mmBtu 3-hr avg. [40 CFR 60.43(a)(2), Minn. R. 7011.0555, Title I Conditions: 40 CFR 52.21(j) (BACT) & (k) (modeling)]


COMG1

EQUI82&EQUI83 SO2 <= 0.700 lb/mmBtu 30-day rolling avg for each boiler. [CAAA of 1990, Minn. Rs. 7007.0100, subp. 7(A)&(B) & 7007.0800, subp. 1&2, Minn. Stat. § 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]




COMG1

EQUI85 & EQUI100 SO2 <= 0.030 lb/mmBtu 30-day rolling avg for each boiler. [CAAA of 1990, Minn. Rs. 7007.0100, subp. 7(A)&(B) & 7007.0800, subp. 1&2, Minn. Stat. § 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]


COMG1

For each COMG1 boiler: SO2 <= 0.20 lb/mmBtu, or SO2 <= 1.50 lb/MWhr; OR HCl <= 0.002 lb/mmBtu, or HCl <= 0.02 lb/MWhr. [40 CFR pt. 63, subp. UUUUU (Table 2), Minn. R. 7011.0563]

Quarterly HCl testing for EQUI82, EQUI83, & EQUI100; SO2 CEMS and DAHS for EQUI85

HCl testing required by NESHAP part 63, subp. UUUUU provides adequate monitoring of HCl emissions; SO2 CEMS directly measure EQUI85 emissions

COMG1

Before 2019, System-Wide Annual SO2 limit <= 7000 tpy on a calendar year basis. Commencing 2019 System-Wide SO2 limit <= 3,000 tpy on a calendar year basis. The Minnesota Power System is composed of Boswell, Laskin, Rapids, & Taconite Harbor Energy Centers. [CAAA of 1990, Minn. Rs. 7007.0100, subp. 7(A)&(B) & 7007.0800, subp. 1&2, Minn. Stat. § 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

SO2 CEMS and DAHS at Boswell, Taconite Harbor, & Rapids Energy; natural gas fuel consumption & calculation of emissions records at Laskin

SO2 CEMS directly measure emissions; natural gas usage and natural gas sulfur content or AP-42 ch. 1.4 SO2 emission factor can readily calculate SO2 emissions

COMG3

TREA2/CE044 (EQUI97/EU018) PM >= 79 % control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

Daily VE checks during daylight hours, recordkeeping of results and corrective actions

The control efficiency is assumed to be met when no VEs are observed because properly operated and maintained low temperature fabric filters will exhibit no VEs while attaining the required control efficiency

COMG3

TREA2/CE044 (EQUI97/EU018) PM10 >= 74 % control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]



COMG3

TREA2/CE044 (EQUI97/EU018) PM2.5 >= 43 % control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]





COMG3 TREA2/CE044 (EQUI97/EU018) Lead >= 79 % control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14]



COMG3

TREA23/CE032 (EQUI86/EU024 Unit 4 Lime Silo), TREA24/CE033 (EQUI87/EU025 Unit 4 Lime Day Bin A), TREA25/ CE034 (EQUI88/ EU026 Unit 4 Lime Day Bin B), TREA26/CE035 (EQUI89/EU027 Unit 4 Lime Day Bin C), TREA27/ CE036 (EQUI90/ EU028 Unit 4 Lime Day Bin D), TREA29/CE037 (EQUI91/EU029 Unit 4 Lime Day Bin E), & TREA30/CE038 (EQUI120/EU030 Unit 4 Activated Carbon Silo) PM >= 99.5 % control efficiency for each filter. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]



COMG3

TREA23/CE032 (EQUI86/EU024 Unit 4 Lime Silo), TREA24/CE033 (EQUI87/EU025 Unit 4 Lime Day Bin A), TREA25/ CE034 (EQUI88/ EU026 Unit 4 Lime Day Bin B), TREA26/CE035 (EQUI89/EU027 Unit 4 Lime Day Bin C), TREA27/ CE036 (EQUI90/ EU028 Unit 4 Lime Day Bin D), TREA29/CE037 (EQUI91/EU029 Unit 4 Lime Day Bin E), & TREA30/CE038 (EQUI120/EU030 Unit 4 Activated Carbon Silo) PM10 >= 99.5 % control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]



COMG3

TREA23/CE032 (EQUI86/EU024 Unit 4 Lime Silo), TREA24/CE033 (EQUI87/EU025 Unit 4 Lime Day Bin A), TREA25/ CE034 (EQUI88/ EU026 Unit 4 Lime Day Bin B), TREA26/CE035 (EQUI89/EU027 Unit 4 Lime Day Bin C), TREA27/ CE036 (EQUI90/ EU028 Unit 4 Lime Day Bin D), TREA29/CE037 (EQUI91/EU029 Unit 4 Lime Day Bin E), & TREA30/CE038 (EQUI120/EU030 Unit 4 Activated Carbon Silo) PM2.5 >= 99.5 % control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]





COMG3

TREA31/CE039 (EQUI93/EU031 Fly Ash Silo B PM >= 99.75% control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]



COMG3

TREA31/CE039 (EQUI93/EU031 Fly Ash Silo B) PM10 >= 99.75 % control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]



COMG3

TREA31/CE039 (EQUI93/EU031 Fly Ash Silo B) PM2.5 >= 99.75 % control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]



COMG3

TREA31/CE039 (EQUI93/EU031 Fly Ash Silo B) Lead >= 99.75 % control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14]



COMG3

TREA32/CE040 (EQUI94/EU032 Fly Ash Silo B Loadout - Truck Bay) PM >= 99.7% control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]



COMG3

TREA32/CE040 (EQUI94/EU032 Fly Ash Silo B Loadout - Truck Bay) PM10 >= 99.7 % control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]





COMG3

TREA32/CE040 (EQUI94/EU032 Fly Ash Silo B Loadout - Truck Bay) PM2.5 >= 99.7 % control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]



COMG3

TREA32/CE040 (EQUI94/EU032 Fly Ash Silo B Loadout - Truck Bay) Lead >= 99.7% control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14]



COMG3

TREA36/CE015 (EQUI98/EU017) PM >= 99.0 % control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]



COMG3

TREA36/CE015 (EQUI98/EU017) PM10 >= 93 % control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]



COMG3

TREA36/CE015 (EQUI98/EU017) PM2.5 >= 54.0 % control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]



COMG3 TREA36/CE015 (EQUI98/EU017) Lead >= 99.0% control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14]





COMG3

TREA36/CE015 (EQUI122 Fly Ash Silo A Loadout) PM >= 79 % control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]



COMG3

TREA36/CE015 (EQUI122 Fly Ash Silo A Loadout) PM10 >= 74 % control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]



COMG3

TREA36/CE015 (EQUI122 Fly Ash Silo A Loadout) PM2.5 >= 43 % control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]



COMG3

TREA36/ CE015 (EQUI122 Fly Ash Silo A Loadout) Lead >= 79 % control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14]



COMG3

TREA37/CE007 (EQUI1/EU011 Crusher House), TREA38/ CE008 (EQUI102/ EU012 Crusher House), TREA39/CE009 (EQUI3/EU003 Fly Ash - #1 & #2 Silo), & TREA40/CE010 (EQUI4/EU014 #1&2 Fly Ash Separator) PM >= 99% control efficiency for each filter. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14]



COMG3

TREA37/CE007 (EQUI1/EU011 Crusher House), TREA38/ CE008 (EQUI102/ EU012 Crusher House), TREA39/CE009 (EQUI3/EU003 Fly Ash - #1 & #2 Silo), & TREA40/ CE010 (EQUI4/ EU014 #1&2 Fly Ash Separator) PM10 >= 93 % control efficiency for each filter. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14,]





COMG3

TREA37/CE007 (EQUI1/EU011 Crusher House), TREA38/ CE008 (EQUI102/ EU012 Crusher House), TREA39/CE009 (EQUI3/EU003 Fly Ash - #1 & #2 Silo), & TREA40/ CE010 (EQUI4/ EU014 #1&2 Fly Ash Separator) PM2.5 >= 93 % control efficiency for each filter. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14]



COMG3

TREA37/CE007 (EQUI1/EU011 Crusher House), TREA38/ CE008 (EQUI102/ EU012 Crusher House), TREA39/CE009 (EQUI3/EU003 Fly Ash - #1 & #2 Silo), & TREA40/ CE010 (EQUI4/ EU014 #1&2 Fly Ash Separator Lead >= 99 % control efficiency for each filter. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14]



COMG3

TREA41/CE013 (EQUI99/EU015 Hg Additive Handling & Unit 3 PAC Silo), TREA1/CE016 (EQUI5/EU019 Unit 3 Limestone Silo), TREA42/ CE017 (EQUI6/ EU020 Unit 3 Limestone Day Bin 1), & TREA43/CE018 (EQUI7/EU021 Unit 3 Limestone Day Bin 2) PM >= 99% control efficiency for each filter. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]



COMG3

TREA41/CE013 (EQUI99/EU015 Hg Additive Handling & Unit 3 PAC Silo), TREA1/CE016 (EQUI5/EU019 Unit 3 Limestone Silo), TREA42/ CE017 (EQUI6/ EU020 Unit 3 Limestone Day Bin 1), & TREA43/CE018 (EQUI7/EU021 Unit 3 Limestone Day Bin 2) PM10 >= 99 % control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]



COMG3

TREA41/CE013 (EQUI99/EU015 Hg Additive Handling & Unit 3 PAC Silo), TREA1/CE016 (EQUI5/EU019 Unit 3 Limestone Silo), TREA42/ CE017 (EQUI6/ EU020 Unit 3 Limestone Day Bin 1), & TREA43/CE018 (EQUI7/EU021 Unit 3 Limestone Day Bin 2) PM2.5 >= 93 % control efficiency for each filter. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]





COMG3

TREA46/CE045 (EQUI111/EU035 Rail Unloading), TREA47/CE046 (EQUI112/EU036 Lowering Well & EQUI113/EU047 Coal Silo), TREA48/CE047 (EQUI114/EU037 C16/C18 Transfer House), TREA49/ CE048 (EQUI115/ EU038 C9/C10 Transfer House), TREA50/CE049 (EQUI116/EU039 Dust Tank), TREA51/CE050 (EQUI117/EU040 Units 1, 2, 3 Bunkers), & TREA52/CE051 (EQUI118/EU041 Unit 4 Bunkers) PM >= 99.0 % control efficiency for each filter. [Minn. R. 7011.0070]



COMG3

TREA46/CE045 (EQUI111/EU035 Rail Unloading), TREA47/CE046 (EQUI112/EU036 Lowering Well & EQUI113/EU047 Coal Silo), TREA48/CE047 (EQUI114/EU037 C16/C18 Transfer House), TREA49/ CE048 (EQUI115/ EU038 C9/C10 Transfer House), TREA50/CE049 (EQUI116/EU039 Dust Tank), TREA51/CE050 (EQUI117/EU040 Units 1, 2, 3 Bunkers), & TREA52/CE051 (EQUI118/EU041 Unit 4 Bunkers) PM10 >= 93.0 % control efficiency for each filter. [Minn. R. 7011.0070]



COMG3

TREA46/CE045 (EQUI111/EU035 Rail Unloading), TREA47/CE046 (EQUI112/EU036 Lowering Well & EQUI113/EU047 Coal Silo), TREA48/CE047 (EQUI114/EU037 C16/C18 Transfer House), TREA49/ CE048 (EQUI115/ EU038 C9/C10 Transfer House), TREA50/CE049 (EQUI116/EU039 Dust Tank), TREA51/CE050 (EQUI117/EU040 Units 1, 2, 3 Bunkers), & TREA52/CE051 (EQUI118/EU041 Unit 4 Bunkers) PM2.5 >= 93.0 % control efficiency. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14]



COMG3

TREA46/CE045 (EQUI111/EU035 Rail Unloading), TREA47/CE046 (EQUI112/EU036 Lowering Well & EQUI113/EU047 Coal Silo), TREA48/CE047 (EQUI114/EU037 C16/C18 Transfer House), TREA49/ CE048 (EQUI115/ EU038 C9/C10 Transfer House), TREA50/CE049 (EQUI116/EU039 Dust Tank), TREA51/CE050 (EQUI117/EU040 Units 1, 2, 3 Bunkers), & TREA52/CE051 (EQUI118/EU041 Unit 4 Bunkers) Lead >= 99.0 % control efficiency for each filter. [Minn. R. 7007.0800, subp. 2(A)&(B) & subp. 14]





COMG7

For each COMG7 boiler: Filterable PM <= 0.03 lb/mmBtu, or Filterable Total PM <= 0.30 lb/MWhr, OR, Total non-Hg HAP metals to <=5.0 E-05 lb/mmBtu from EQUI82, EQUI83, EQUI100, & EQUI85, or <=0.5 lb/GWhr OR, Antimony: <=8.0E-1 lb/TBtu or <=8.0E-3 lb/GWhr Arsenic: <=1.1E0 lb/TBtu or <=2.0E-2 lb/GWhr Beryllium: <=2.0E-1 lb/TBtu or <=2.0E-3 lb/GWhr Cadmium: <=3.0E-1 lb/TBtu or <=3.0E-3 lb/GWhr Chromium: <=2.8E0 lb/TBtu or <=3.0E-2 lb/GWhr Cobalt: <=8.0E-1 lb/TBtu or <=8.0E-3 lb/GWhr Lead: <=1.2E0 lb/TBtu or <=2.0E-2 lb/GWhr Manganese: <=4.0E0 lb/TBtu or <=5.0E-2 lb/GWhr Nickel: <=3.5E0 lb/TBtu or <=4.0E-2 lb/GWhr Selenium: <=5.0E0 lb/TBtu or <=6.0E-2 lb/GWhr. [40 CFR pt. 63, subp. UUUUU (Table 2), Minn. R. 7011.0563]

Permittee elects to meet the filterable PM limit through MATS-required stack testing

MATS is a post-1990 standard that contains adequate periodic monitoring requirements

COMG7

For each COMG7 boiler: Hg <= 1.2 lb/TBtu, or Hg <= 0.013 lb/GWhr. [40 CFR pt. 63, subp. UUUUU (Table 2), Minn. R. 7011.0563]

Use of Hg sorbent trap or CEMS and DAHS

MATS is a post-1990 standard that contains adequate periodic monitoring and sorbent trap and CEMS provide real-time direct emissions measurement

COMG7

For each COMG7 boiler: HCl <= 0.002 lb/mmBtu, or <= 0.02 lb/MWhr; OR, SO2 <= 0.20 lb/mmBtu, or SO2 <= 1.50 lb/MWhr. [40 CFR pt. 63, subp. UUUUU (Table 2), Minn. R. 7011.0563]

Permittee elects to comply with HCl limit for EQUI82, EQUI83, and EQUI100 through required stack testing, and comply with SO2 limit for EQUI85 using SO2 CEMS

MATS is a post-1990 standard that contains adequate periodic monitoring (HCl) requirements and SO2 CEMS provide real-time direct emissions measurement

COMG9

Hg >= 90% control efficiency from EQUI100 & EQUI85, or demonstrate EQUI100 & EQUI85 each emit no more than 0.8 lb/Tbtu, unless the commissioner establishes an alternate Hg emissions reduction. [Minn. R. 7011.0561, subp. 4(A)]

Hg CEMS CEMS provide real-time direct emissions measurement



COMG9

CO<= 319 tpy 12-month rolling sum for total COMG9 CO emissions from NG combustion in all igniter/ warm-up guns in EQUI82, EQUI83, EQUI85, & EQUI100. This excludes CO emissions from coal combustion & other permitted fuels. [Minn. R. 7007.0800, subp. 2(A)]

CO CEMS and fuel usage records

EQUI85 and EQUI100 CEMS provide real-time direct emissions measurement; EQUI82 and EQUI83 NG use and AP-42 emission factor are reliable methods to determine emissions

COMG9

System-Wide NOX <= 6700 tons per year on a calendar year basis. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. § 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

NOX CEMS CEMS provide real-time direct emissions measurement

EQUI1 PM <= 0.30 gr/dscf unless required to further reduce emissions. [Minn. R. 7011.0715, subp. 1(A)]

VE checks required at COMG3

No VEs indicates compliance with PM limit

EQUI1 Opacity <= 20%. [Minn. R. 7011.0715, subp. 1(B)]


Presence of any VEs prompts corrective action













EQUI5 PM <= 0.30 gr/dscf of exhaust gas unless required to further reduce emissions. [Minn. R. 7011.0715, subp. 1(A)]



EQUI5 PM <= 0.005 gr/dscf. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]



EQUI5 PM10 <= 0.005 gr/dscf. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]


No VEs indicates compliance with PM10 limit






























EQUI23

SO2 <= 0.5 lb/mmBtu. By 1/31/18, SO2 <= 0.0015 lb/mmBtu unless an alternate SO2 limit is established by modeling compliance with SO2 standards in Minn. R. 7009.0080. [Minn. R. 7011.2300, subp. 2]

None Required to use ultra-low sulfur diesel fuel results in inherently low SO2 emissions

EQUI23 Opacity <= 20% once operating temperatures have been attained. [Minn. R. 7011.2300, subp. 1]

None Required to use ultra-low sulfur diesel fuel results in inherently low VEs

EQUI23 CO<= 3.5 g/kw-hr. [40 CFR 60.4205(b), Minn. R. 7011.2305]

Compliance with requirement to install engine manufactured no earlier than 6/12/2006 and use only ultra-low sulfur diesel fuel results in inherent compliance with emission standards

NSPS subp. IIII is a post-1990 standard that contains adequate periodic monitoring (in the form of fuel parameters and engine manufacturing date) requirements

EQUI23 PM <= 0.20 g/kw-hr. [40 CFR 60.4205(b), Minn. R. 7011.2305]

EQUI23 NMHC+NOX <= 4.0 g/kw-hr. [40 CFR 60.4205(b), Minn. R. 7011.2305]

EQUI81





EQUI81 CO <= 3.5 g/kw-hr. [40 CFR 60.4205(b), Minn. R. 7011.2305]



EQUI81 PM <= 0.20 g/kw-hr. [40 CFR 60.4205(b), Minn. R. 7011.2305]

EQUI81 NMHC+NOx <= 4.0 g/kw-hr. [40 CFR 60.4205(b), Minn. R. 7011.2305]

EQUI82 Opacity <= 20% 6-minute avg except for one 6-minute period per hr <= 60%. [Minn. R. 7011.0510, subp. 2]

COMS COMS provide real-time direct emissions measurement



EQUI82 PM <= 0.60 lb/mmBtu 3-hr avg. [Minn. R. 7011.0510, subp. 1]

Fabric Filter pressure drop (CAM) and periodic stack testing

CAM plan justifies use of pressure drop range based on observed pressure drop values over the period of one or more months of operation that include a compliant PM stack test

EQUI82 PM <= 0.10 lb/mmBtu 24-hr block avg. [Title I Condition: 40 CFR 52.21(k) (modeling) & Minn. R. 7007.3000]

EQUI82

EQUI82 & EQUI83, combined Filterable PM <= 0.015 lb/mmBtu 3-hr avg. [CAAA of 1990, Minn. R. 7007.0100, subp 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. § 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]



EQUI82

EQUI82 NOX <= 0.200 lb/mmBtu 30-day rolling avg. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. § 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

CEMS CEMS provide real-time direct emissions measurement

EQUI82 EQUI82 NOX <= 0.46 lb/mmBtu calendar year avg. [40 CFR 76.7(a)(2)&(b), Minn. R. 7011.0553]

EQUI83 PM <= 0.10 lb/mmBtu 24-hr block avg. [Title I Condition: 40 CFR 52.21(k) (modeling) & Minn. R. 7007.3000] Fabric Filter pressure

drop (CAM) and periodic stack testing


EQUI83 PM <= 0.60 lb/mmBtu 3-hr avg. [Minn. R. 7011.0510, subp. 1]

EQUI83

EQUI82 & EQUI83 combined Filterable PM <= 0.015 lb/mmBtu 3-hr avg. [CAAA of 1990, Minn. R. 7007.0100, subp 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. § 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]



EQUI83 Opacity <= 20% 6-minute avg except for one 6-minute period per hr <= 60%. [Minn. R. 7011.0510, subp. 2]


EQUI83

EQUI83 NOX <= 0.200 lb/mmBtu 30-day rolling avg. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. § 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]



EQUI85 EQUI85 Opacity <= 20% 6-minute avg except for one 6-minute avg per hr <= 27%. [40 CFR 60.42(a)(2), Minn. R. 7011.0555]




EQUI85

EQUI85 Filterable PM <= 0.10 lb/mmBtu. [40 CFR 60.42(a)(1), Minn. R. 7011.0555, 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]


CAM plan justifies use of pressure drop range based on observed pressure drop values over the period of one or more months of operation that include a compliant PM, PM10, and PM2.5 stack tests

EQUI85 EQUI85 PM10 <= 0.020 lb/mmBtu. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI85 EQUI85 PM2.5 <= 0.020 lb/mmBtu. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI85

EQUI85 PM <= 0.015 lb/mmBtu 3-hr avg. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. § 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI85 EQUI85 Filterable PM <= 0.012 lb/mmBtu. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI85

EQUI85 CO <= 0.15 lb/mmBtu 30-day rolling avg including startup, shutdown, and malfunction. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]


EQUI85

EQUI85 Fluorides <= 0.0084 lb/mmBtu. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

SO2 CEMS data as indicator of fluorides compliance (CAM) and periodic stack testing

CAM plan justifies use of SO2 CEMS data based on observed SO2 emissions during compliant fluorides stack test

EQUI85

EQUI85 NOX <= 0.70 lb/mmBtu 3-hr avg for solid fossil fuels & <= 0.20 lb/mmBtu 3-hr avg for gaseous fossil fuels. When fossil fuels are co-fired in any combination, the applicable standard shall be determined by proration using the following formula: PS = [0.20x + 0.70z]/(x+z) where PS is the prorated NOX standard, x is the % heat input from gaseous fossil fuel & z is the % heat input from solid fossil fuel. [40 CFR 60.44(a)(1)&(3), 40 CFR 60.44(b), Minn. R. 7011.0555]


EQUI85

NOX <= 0.120 lb/mmBtu 30-day rolling avg. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. § 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI85 EQUI85 Nitrogen Oxides <= 0.40 lb/mmBtu calendar year avg. [40 CFR 76.7(a)(1)&(b), Minn. R. 7011.0553]

CEMS required by Acid Rain Program


EQUI85 EQUI85 Hg <= 26.0 lb/yr 12-month rolling sum. [Minn. R. 7007.0800, subp. 4&5, Minn. Stat. 216B.687, subd. 1&2]







EQUI86 PM <= 0.30 gr/dscf unless required to further reduce [Minn. R. 7011.0715, subp. 1(A)]






EQUI86 PM2.5 <= 0.005 gr/dscf. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]


No VEs indicates compliance with PM2.5 limit
































































NO VEs indicates compliance with PM10 limit













Np VEs indicates compliance with PM limit



















EQUI100 EQUI100 PM <= 0.60 lb/mmBtu. [Minn. R. 7011.0510, subp. 1]

Fabric Filter pressure drop (CAM) and

CAM plan justifies use of pressure drop range based



EQUI100

Filterable PM <= 0.015 lb/mmBtu 3-hr avg. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. § 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

periodic stack testing on observed pressure drop values over the period of one or more months of operation that include a compliant PM and PM10 stack tests

EQUI100 EQUI100 Filterable PM <= 0.014 lb/mmBtu 3-hr avg. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI100

EQUI100 PM10 <= 0.035 lb/mmBtu filterable plus organic & inorganic condensables. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI100 EQUI100 Opacity <= 20% 6-minute avg except for one 6-minute period per hr <=60%. [Minn. R. 7011.0510, subp. 2]


EQUI100

EQUI100 Fluorides <= 0.0018 lb/mmBtu. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

SO2 CEMS data as indicator of fluorides compliance and periodic stack testing

Use of SO2 CEMS data supported by observed SO2 emission rates during compliant fluorides stack tests demonstrating SO2 emissions are worst case compared to fluoride emissions (refer to Attachment 5; note EQUI100 fluorides are not subject to CAM but were included by Permittee in their CAM plans)

EQUI100

EQUI100 CO <= 0.15 lb/mmBtu on a 24-hour rolling avg including startup, shutdown, and malfunction. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]


EQUI100

NOX <= 0.060 lb/mmBtu 30-day rolling avg. [CAAA of 1990, Minn. R. 7007.0100, subp. 7, Minn. R. 7007.0800, subp. 1&2, Minn. Stat. § 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21] CEMS



EQUI100

EQUI100 Lead <= 0.00004 lb/mmBtu. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

Periodic stack testing

Test results are extremely low so 60-month test interval/monitoring is acceptable

EQUI100 EQUI100 Hg <= 10.0 lb/yr 12-month rolling sum. [Minn. R. 7007.0800, subp. 4&5, Minn. Stat. 216B.687, subd. 1&2]













EQUI111 Opacity <= 20% except for one 6-minute period per hr <=60%. [Minn. R. 7011.0710, subp. 1(B)]










































EQUI118 Opacity <= 20% opacity. [Minn. R. 7011.0715, subp. 1(B)]





EQUI119 CO <= 3.0 g/kw-hr. [40 CFR 60.4202(a)(2), 40 CFR 60.4205(b), 40 CFR 89.112(a), Minn. R. 7011.2305]



EQUI119 NMHC+NOx <= 4.0 0 g/kw-hr. [40 CFR 60.4202(a)(2), 40 CFR 60.4205(b), 40 CFR 89.112(a), Minn. R. 7011.2305]

EQUI119 Particulate Matter <= 0.20 g/kw-hr. [40 CFR 60.4202(a)(2), 40 CFR 60.4205(b), 40 CFR 89.112(a), Minn. R. 7011.2305]

EQUI119



































FUGI11

Coal Moisture Content >= 20% by weight. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

Recordkeeping of coal moisture content data for coal handled by FUGI11 portable conveyors

This data is readily available for each delivery for establishing and maintaining moisture content records



FUGI11

A maximum of 10 portable coal stockpile conveyors (11 drop points including drop onto pile) may be employed at any time. [Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

Recordkeeping of the number of operating portable coal stockpile conveyors

Records verify if the number of operating portable conveyors exceed the limit

FUGI11

Portable conveyor handling of Coal <= 450 tons per hour. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

Maintain a log of the hourly capacity of all FUGI11 portable conveyors

A log will verify if the capacity of any conveyor exceeds the limit

TREA9 TREA9 Pressure Drop >= 2.0 and <= 11.0 inches of water column 1-hour average. [40 CFR 64.3(a)(2), Minn. R. 7017.0200]


CAM plan justifies use of pressure drop range based on observed pressure drop during several months operation that included compliant PM and PM10 stack tests

TREA14

Filterable PM Compliance Assurance Monitoring (CAM): TREA14 Pressure Drop >= 2.0 and <= 14.0 inches of water column 1-hour average. [40 CFR 64.3(a)(2), Minn. R. 7017.0200, Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]


CAM plan justifies use of pressure drop range based on observed pressure drop during at least one month of operation that included compliant PM stack test

TREA16

Filterable PM Compliance Assurance Monitoring (CAM): TREA16 Pressure Drop >= 2.0 and <= 14.0 inches of water column 1-hour. [40 CFR 64.3(a)(2), Minn. R. 7017.0200, Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]


CAM plan justifies use of pressure drop range based on observed pressure drop during at least one month of operation that included compliant PM stack test

TREA21

TREA21 Pressure Drop >= 4.0 and <= 18.0 inches of water column 1-hour average. [40 CFR 64.3(a)(2), Minn. R. 7017.0200, 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]


CAM plan justifies use of pressure drop range based on observed pressure drop during several months operation that included compliant PM, PM10, and PM2.5 stack tests

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

3.6 Insignificant activities

Several facility operations are classified as insignificant activities under Minn. R. ch. 7007. These are listed in permit Appendix A.

The permit is required to include periodic monitoring for all emissions units, including insignificant activities, based on EPA guidance. The insignificant activities at this facility are only subject to general applicable requirements. Using the criteria outlined earlier in this TSD, the following table documents the justification why no additional periodic monitoring is necessary for the current insignificant activities. See Attachment 7 for PTE information for the insignificant activities.


Table 16. Insignificant activities

Insignificant activity General applicable emission limit Discussion

Indirect heating equipment with a capacity less than 420,000 Btu/hour, etc. (Minn. R. 7007.1300, subp. 3(B)(2))

PM <= 0.6 or 0.4, depending on year constructed Opacity <= 20% with exceptions (Minn. R. 7011.0510/0515)

Four Coal treatment system (CTS; formerly Clean Coal Solutions (CCS)) plant tankless water heaters, each with a capacity of 250 KBtu/hr. Design fuel (propane) ensures compliance; no monitoring warranted.

Emissions from a laboratory, as defined in Minn. R. 7007.1300, subp. 3(G)

PM, variable depending on airflow Opacity <= 20% (Minn. R. 7011.0710/0715)

Four lab hoods for ash, FGD waters, and boiler deposits analyses; minimal emissions - no monitoring warranted

Brazing, soldering or welding equipment (Minn. R. 7007.1300, subp. 3(H)(3))

PM, variable depending on airflow Opacity <= 20% (Minn. R. 7011.0710/0715)

Welding equipment that will readily comply with PM and opacity limits; minimal emissions - no monitoring warranted

Individual units with potential emissions less than 2000 lb/year of certain pollutants (Minn. R. 7007.1300, subp. 3(I))

PM, variable depending on airflow; Opacity <= 20% (Minn. R. 7011.0710/0715);

PM <= 0.6 or 0.4 lb/mmBtu, depending on year constructed; Opacity <= 20% with exceptions (Minn. R. 7011.0510/0515)

Control of fugitive particulate matter (Minn. R. 7011.0150)

Pneumatic unloading of dry urea and brucite (Mg(OH)2) each into a separate silo; no monitoring warranted due to use of bin filters and residual moisture content of materials Seven space heaters - Design fuel (natural gas) ensures compliance; no monitoring warranted.

Coal treatment systems (CTS; formerly Clean Coal Solutions) Process Haul Roads, Truck coal hopper loading and truck loading with coal: These sources are addressed by the fugitive emissions control plan

Individual units with potential or actual emissions meeting the criteria in Minn. R. 7007.1300, subp. 4(A)-(D)

Control of fugitive particulate matter (Minn. R. 7011.0150)

Coal Stockpile Loading, Conveyor Drops onto Stockpile Reclaimer, Conveyor Drops onto Stockpile - Side Chute, Rail Car Load Out: These sources are addressed by the fugitive emissions control plan

3.7 Permit organization

The permit both meets and deviates from MPCA Tempo Guidance for ordering and grouping of requirements.

SO2 limits are listed at COMG1 as has been done for the past twenty years (since the initial title V permit was issued) due to the complexity of applicable limits and operating scenarios. All low temperature fabric filter requirements are found in COMG3 due to the repetitive nature of the requirements for numerous low temperature fabric filters. The COMS and Part 75 CEMS requirements are also grouped in COMG4 and COMG6, respectively, except for ongoing QA/QC requirements listed under the appropriate EQUI subject item. The large number of requirements from the electric utility boiler NESHAP (pt. 63, subp. UUUUU) are grouped in COMG7 to reduce both permit length and to accommodate the option to average emissions among two or more utility boilers. CO CEMS requirements are located at


COMG8, except for the QA/QC requirements which are located under the appropriate EQUI subject item. Requirements from the 2014 Consent Decree, Acid Rain Program, Minnesota Hg rule requirements that apply individually to each EGU, ignitor gun CO requirements, and test burn requirements were grouped in COMG9.

The permit also deviates from the guidance in the use of appendices. While appendices are fully enforceable parts of the permit, in general, any requirement warranting electronic tracking (e.g., testing, submittals, etc.), should be in the Requirements table in TEMPO because appendices are word processing documents that are not part of the electronic tracking system. Violation of appendices can be enforced, but TEMPO does not automatically generate the necessary enforcement notices or documents; staff must generate these. This permit uses an Appendix E for specific calculation procedures from 40 CFR pt. 63, subp. UUUUU because these calculations are too complex to enter into Tempo.

3.8 Comments received (completed after the end of each comment period) Public Notice Period: [start date] – [end date] EPA Review Period: [start date] – [end date]

4. Permit fee assessment This permit action is primarily the reissuance of an individual Part 70 operating permit for which no application fees apply under Minn. R. 7002.0016, subp. 1 (including changes covered by the reissuance application that are unrelated to other incorporated applications). Attachment 4 contains the MPCA assessment of Application and Additional Points used to determine the permit application fee for this permit action as required by Minn. R. 7002.0019.

Additional points for review of two NSPSs (subps. Y for coal stockpile expansion and subp. IIII for new Unit 4 emergency generator), and a NESHAP (subp. ZZZZ for the Unit 4 emergency generator) are required. This permit action also includes requirements to limit the emission increases from the 2015 coal stockpile expansion project to less than the PSD 25 tpy PM significant emissions increase threshold.

This permit action includes revisions to existing EQUI85 and EQUI100 CO BACT determinations. Although a portion of the requested EQUI100 revision (from a 24-hour rolling average to a 30-day rolling average limit) was withdrawn by the Permittee and not included in this permit, fee calculation instructions require imposition of a for each pollutant when existing BACT is re-evaluated in any way and for any reason, even if the result is no changes to existing BACT conditions.

The permit action also includes 1-hour SO2 and 24-hour PM2.5 modeling reviews, but the reviews don’t incur additional fees because the modeling was required as part of the reissuance permit process, and because the reissuance permit isn’t subject to a fee, neither is the modeling review.

5. Conclusion Based on the information provided by Minnesota Power Inc. - Boswell Energy Center the MPCA has reasonable assurance that the proposed operation of the emission facility, as described in the Air Emission Permit No. 06100004-008 and this TSD, will not cause or contribute to a violation of applicable federal regulations and Minnesota Rules. Staff members on permit team: Marshall Cole (permit engineer)

Dick Cordes, P.E. (peer reviewer) Andy Place (compliance)


Marc Severin (compliance) Steve Palzkill (enforcement) Beckie Olson (permit writing assistant) Anne Jackson (State Hg requirements) Hongming Jiang (Hg and CO emissions analyses) Melissa Kuskie (Data Requirements Rule) Laurie O’Brien (administrative support)

TEMPO360 Activities:

Part 70 Reissuance (IND20110004) Minor Amendment (IND20150001) Major Amendment (IND20150002) Minor Amendment (IND20150003) Major Amendment (IND20170001)

Attachments: 1. Reissuance emission calculations

2. Coal stockpile expansion emission calculations 3. Subject item inventory and facility requirements 4. Points calculator 5. 2014 SO2 and PM2.5 Modeling Report Review 6. Updated CAM plans 7. 2014 Consent Decree 8. Insignificant activities emissions calculations

ATTACHMENT 1 – REISSUANCE EMISSION CALCULATIONS TECHNICAL SUPPORT DOCUMENT

MINNESOTA POWER BOSWELL ENERGY CENTER Permit Number: 06100004-008

of 102

GI-07-R SpreadsheetPotential to Emit - Supplemental

Information for Title V ReissuanceAir Quality Permit Program

Doc Type: Permit Application

1a) AQ Facility ID No.: 06100004 1b) Agency Interest ID No.: 24932) Facility Name: Minnesota Power Inc - Boswell Energy Center

Emissions By Source Table

c) d) c) d) c) d)

Pollutant Name CAS #Lbs per

HrUnc tpy

Limited tpy Pollutant Name CAS #

Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy

PM 16.1 18807.2 70.6 PM 13.7 15,920.6 59.8 PM 61.9 77,415.9 271.3PM10 40.3 4333.7 176.6 PM10 34.1 3,668.5 149.5 PM10 154.9 17,838.7 678.4PM2.5 40.3 1136.5 176.6 PM2.5 34.1 962.0 149.5 PM2.5 154.9 4,678.0 678.4CO 30.5 133.8 133.8 CO 25.9 113.2 113.2 CO 663.8 2,907.2 2,907.2NOX 215.0 3210.3 941.7 NOX 182.0 2,717.6 797.2 NOX 265.5 7,928.8 1,162.9

SO2 752.5 5618.1 3296.0 SO2 637.0 4,755.8 2,790.1 SO2 132.8 23,125.7 581.4VOC 3.7 16.1 16.1 VOC 3.1 13.6 13.6 VOC 15.1 66.1 66.1H2SO4 0.1 16.3 0.6 H2SO4 0.1 13.8 0.5 H2SO4 0.9 253.9 3.8

CO2 2.26E+05 9.89E+05 9.89E+05 CO2 1.91E+05 8.37E+05 8.37E+05 CO2 9.29E+05 4.07E+06 4.07E+06CH4 25.6 111.9 111.9 CH4 21.6 94.8 94.8 CH4 105.2 460.7 460.7N2O 3.7 16.3 16.3 N2O 3.1 13.8 13.8 N2O 15.3 67.0 67.0CO2-e 2.27E+05 9.96E+05 9.96E+05 CO2-e 1.93E+05 8.43E+05 8.43E+05 CO2-e 9.36E+05 4.10E+06 4.10E+06Total HAP 12.4262 366.0436 54.4266 Total HAP 10.5189 309.8603 46.0728 Total HAP 25.2870 1506.7434 110.7571Lead 3.66E-01 1.61E+00 1.61E+00 Lead 3.10E-01 1.36E+00 1.36E+00 Fluorides 7.97E+00 9.97E+01 3.49E+01Hydrogen Chloride 2.15E+00 3.21E+02 9.42E+00 Hydrogen Chloride 1.82E+00 2.72E+02 7.97E+00 Lead 1.77E-01 6.61E+00 7.75E-01Hydrogen Fluoride 9.16E+00 4.01E+01 4.01E+01 Hydrogen Fluoride 7.76E+00 3.40E+01 3.40E+01 Hydrogen Chloride 8.85E+00 1.32E+03 3.88E+01Benzene 7.94E-02 3.48E-01 3.48E-01 Benzene 6.72E-02 2.94E-01 2.94E-01 Hydrogen Fluoride 1.32E+01 1.65E+02 5.78E+01Hexane 4.09E-03 1.79E-02 1.79E-02 Hexane 3.46E-03 1.52E-02 1.52E-02 Benzene 3.27E-01 1.43E+00 1.43E+00Toluene 1.47E-02 6.42E-02 6.42E-02 Toluene 1.24E-02 5.44E-02 5.44E-02 Hexane 1.68E-02 7.38E-02 7.38E-02Xylenes 2.26E-03 9.90E-03 9.90E-03 Xylenes 1.91E-03 8.38E-03 8.38E-03 Toluene 6.03E-02 2.64E-01 2.64E-01Acetaldehyde 3.48E-02 1.52E-01 1.52E-01 Acetaldehyde 2.95E-02 1.29E-01 1.29E-01 Xylenes 9.30E-03 4.07E-02 4.07E-02Acetophenone 9.16E-04 4.01E-03 4.01E-03 Acetophenone 7.76E-04 3.40E-03 3.40E-03 Acetaldehyde 1.43E-01 6.28E-01 6.28E-01Acrolein 1.77E-02 7.76E-02 7.76E-02 Acrolein 1.50E-02 6.57E-02 6.57E-02 Acetophenone 3.77E-03 1.65E-02 1.65E-02Acenaphthylene 0.00E+00 0.00E+00 0.00E+00 Acenaphthylene 0.00E+00 0.00E+00 0.00E+00 Acrolein 7.29E-02 3.19E-01 3.19E-01Acenaphthene 0.00E+00 0.00E+00 0.00E+00 Acenaphthene 0.00E+00 0.00E+00 0.00E+00 Acenaphthylene 0.00E+00 0.00E+00 0.00E+00Anthracene 0.00E+00 0.00E+00 0.00E+00 Anthracene 0.00E+00 0.00E+00 0.00E+00 Acenaphthene 0.00E+00 0.00E+00 0.00E+00Antimony 1.10E-03 4.82E-03 4.82E-03 Antimony 9.31E-04 4.08E-03 4.08E-03 Anthracene 0.00E+00 0.00E+00 0.00E+00Arsenic 2.50E-02 1.10E-01 1.10E-01 Arsenic 2.12E-02 9.29E-02 9.29E-02 Antimony 4.53E-03 1.98E-02 1.98E-02Benzyl chloride 4.28E-02 1.87E-01 1.87E-01 Benzyl chloride 3.62E-02 1.59E-01 1.59E-01 Arsenic 1.03E-01 4.52E-01 4.52E-01Beryllium 1.28E-03 5.62E-03 5.62E-03 Beryllium 1.09E-03 4.76E-03 4.76E-03 Benzyl chloride 1.76E-01 7.71E-01 7.71E-01Biphenyl 2.08E-04 9.10E-04 9.10E-04 Biphenyl 1.76E-04 7.70E-04 7.70E-04 Beryllium 5.28E-03 2.31E-02 2.31E-02bis(2-Ethylhexyl)phthalate 4.46E-03 1.95E-02 1.95E-02 bis(2-Ethylhexyl)phthalate 3.77E-03 1.65E-02 1.65E-02 Biphenyl 8.55E-04 3.74E-03 3.74E-03

Bromoform 2.38E-03 1.04E-02 1.04E-02 Bromoform 2.02E-03 8.83E-03 8.83E-03 bis(2-Ethylhexyl)phthalate 1.84E-02 8.04E-02 8.04E-02

Cadmium 3.12E-03 1.36E-02 1.36E-02 Cadmium 2.64E-03 1.15E-02 1.15E-02 Bromoform 9.81E-03 4.29E-02 4.29E-02Carbon disulfide 7.94E-03 3.48E-02 3.48E-02 Carbon disulfide 6.72E-03 2.94E-02 2.94E-02 Cadmium 1.28E-02 5.62E-02 5.62E-022-Chloroacetophenone 4.28E-04 1.87E-03 1.87E-03 2-Chloroacetophenone 3.62E-04 1.59E-03 1.59E-03 Carbon disulfide 3.27E-02 1.43E-01 1.43E-01

Chlorobenzene 1.34E-03 5.89E-03 5.89E-03 Chlorobenzene 1.14E-03 4.98E-03 4.98E-03 2-Chloroacetophenone 1.76E-03 7.71E-03 7.71E-03

Chloroform 3.60E-03 1.58E-02 1.58E-02 Chloroform 3.05E-03 1.34E-02 1.34E-02 Chlorobenzene 5.53E-03 2.42E-02 2.42E-02Chromium 1.59E-02 6.96E-02 6.96E-02 Chromium 1.34E-02 5.89E-02 5.89E-02 Chloroform 1.48E-02 6.50E-02 6.50E-02Cobalt 6.11E-03 2.68E-02 2.68E-02 Cobalt 5.17E-03 2.26E-02 2.26E-02 Chromium 6.54E-02 2.86E-01 2.86E-01Cumene 3.24E-04 1.42E-03 1.42E-03 Cumene 2.74E-04 1.20E-03 1.20E-03 Cobalt 2.51E-02 1.10E-01 1.10E-01Cyanide Compounds (Cyanide) 1.53E-01 6.69E-01 6.69E-01 Cyanide Compounds (Cyanide) 1.29E-01 5.66E-01 5.66E-01 Cumene 1.33E-03 5.84E-03 5.84E-03

2,4-Dinitrotoluene 1.71E-05 7.49E-05 7.49E-05 2,4-Dinitrotoluene 1.45E-05 6.34E-05 6.34E-05 Cyanide Compounds (Cyanide) 6.29E-01 2.75E+00 2.75E+00

7,12-Dimethylbenz(a)anthracene 0.00E+00 0.00E+00 0.00E+00 7,12-Dimethylbenz(a)anthracene 0.00E+00 0.00E+00 0.00E+00 2,4-Dinitrotoluene 7.04E-05 3.08E-04 3.08E-04

Dimethyl sulfate 2.93E-03 1.28E-02 1.28E-02 Dimethyl sulfate 2.48E-03 1.09E-02 1.09E-02 7,12-Dimethylbenz(a)anthracene 0.00E+00 0.00E+00 0.00E+00

Ethylbenzene 5.74E-03 2.51E-02 2.51E-02 Ethylbenzene 4.86E-03 2.13E-02 2.13E-02 Dimethyl sulfate 1.21E-02 5.29E-02 5.29E-02Ethyl chloride 2.57E-03 1.12E-02 1.12E-02 Ethyl chloride 2.17E-03 9.51E-03 9.51E-03 Ethylbenzene 2.36E-02 1.04E-01 1.04E-01Ethylene dibromide 7.33E-05 3.21E-04 3.21E-04 Ethylene dibromide 6.20E-05 2.72E-04 2.72E-04 Ethyl chloride 1.06E-02 4.63E-02 4.63E-02Ethylene dichloride 2.44E-03 1.07E-02 1.07E-02 Ethylene dichloride 2.07E-03 9.06E-03 9.06E-03 Ethylene dibromide 3.02E-04 1.32E-03 1.32E-03Fluoranthene 0.00E+00 0.00E+00 0.00E+00 Fluoranthene 0.00E+00 0.00E+00 0.00E+00 Ethylene dichloride 1.01E-02 4.40E-02 4.40E-02Fluorene 0.00E+00 0.00E+00 0.00E+00 Fluorene 0.00E+00 0.00E+00 0.00E+00 Fluoranthene 0.00E+00 0.00E+00 0.00E+00Formaldehyde 1.47E-02 6.42E-02 6.42E-02 Formaldehyde 1.24E-02 5.44E-02 5.44E-02 Fluorene 0.00E+00 0.00E+00 0.00E+00Isophorone 3.54E-02 1.55E-01 1.55E-01 Isophorone 3.00E-02 1.31E-01 1.31E-01 Formaldehyde 6.03E-02 2.64E-01 2.64E-01Manganese 2.99E-02 1.31E-01 1.31E-01 Manganese 2.53E-02 1.11E-01 1.11E-01 Isophorone 1.46E-01 6.39E-01 6.39E-01Mercury 5.07E-03 2.22E-02 5.65E-03 Mercury 4.29E-03 1.88E-02 4.78E-03 Manganese 1.23E-01 5.40E-01 5.40E-01Methyl bromide 9.77E-03 4.28E-02 4.28E-02 Methyl bromide 8.27E-03 3.62E-02 3.62E-02 Mercury 2.09E-03 9.14E-02 5.00E-03Methyl chloride 3.24E-02 1.42E-01 1.42E-01 Methyl chloride 2.74E-02 1.20E-01 1.20E-01 Methyl bromide 4.02E-02 1.76E-01 1.76E-01Methyl ethyl ketone 2.38E-02 1.04E-01 1.04E-01 Methyl ethyl ketone 2.02E-02 8.83E-02 8.83E-02 Methyl chloride 1.33E-01 5.84E-01 5.84E-01

Alternate Format

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

a) Delta ID No.: EU 001 a) Delta ID No.: EU 002 a) Delta ID No.: EU 003

b) Tempo SI ID No.: EQUI82 b) Tempo SI ID No.: EQUI83 b) Tempo SI ID No.:

e) Potential e) Potential e) Potential

EQUI100

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GI-07-R SpreadsheetPotential to Emit - Supplemental

Information for Title V ReissuanceAir Quality Permit Program

Doc Type: Permit Application


Alternate Format

Methyl hydrazine 1.04E-02 4.55E-02 4.55E-02 Methyl hydrazine 8.79E-03 3.85E-02 3.85E-02 Methyl ethyl ketone 9.81E-02 4.29E-01 4.29E-01

Methyl methacrylate 1.22E-03 5.35E-03 5.35E-03 Methyl methacrylate 1.03E-03 4.53E-03 4.53E-03 Methyl hydrazine 4.27E-02 1.87E-01 1.87E-01

Methyl tert butyl ether 2.14E-03 9.36E-03 9.36E-03 Methyl tert butyl ether 1.81E-03 7.93E-03 7.93E-03 Methyl methacrylate 5.03E-03 2.20E-02 2.20E-02

3-Methylchloranthrene 0.00E+00 0.00E+00 0.00E+00 3-Methylchloranthrene 0.00E+00 0.00E+00 0.00E+00 Methyl tert butyl ether 8.80E-03 3.85E-02 3.85E-02

Methylene chloride 1.77E-02 7.76E-02 7.76E-02 Methylene chloride 1.50E-02 6.57E-02 6.57E-02 3-Methylchloranthrene 0.00E+00 0.00E+00 0.00E+00

2-Methylnaphthalene 0.00E+00 0.00E+00 0.00E+00 2-Methylnaphthalene 0.00E+00 0.00E+00 0.00E+00 Methylene chloride 7.29E-02 3.19E-01 3.19E-01

Naphthalene 0.00E+00 0.00E+00 0.00E+00 Naphthalene 0.00E+00 0.00E+00 0.00E+00 2-Methylnaphthalene 0.00E+00 0.00E+00 0.00E+00

Nickel 1.71E-02 7.49E-02 7.49E-02 Nickel 1.45E-02 6.34E-02 6.34E-02 Naphthalene 0.00E+00 0.00E+00 0.00E+00Phenanthrene 0.00E+00 0.00E+00 0.00E+00 Phenanthrene 0.00E+00 0.00E+00 0.00E+00 Nickel 7.04E-02 3.08E-01 3.08E-01Phenol 9.77E-04 4.28E-03 4.28E-03 Phenol 8.27E-04 3.62E-03 3.62E-03 Phenanthrene 0.00E+00 0.00E+00 0.00E+00Propionaldehyde 2.32E-02 1.02E-01 1.02E-01 Propionaldehyde 1.96E-02 8.61E-02 8.61E-02 Phenol 4.02E-03 1.76E-02 1.76E-02Pyrene 0.00E+00 0.00E+00 0.00E+00 Pyrene 0.00E+00 0.00E+00 0.00E+00 Propionaldehyde 9.55E-02 4.18E-01 4.18E-01Selenium 7.94E-02 3.48E-01 3.48E-01 Selenium 6.72E-02 2.94E-01 2.94E-01 Pyrene 0.00E+00 0.00E+00 0.00E+00Styrene 1.53E-03 6.69E-03 6.69E-03 Styrene 1.29E-03 5.66E-03 5.66E-03 Selenium 3.27E-01 1.43E+00 1.43E+00Tetrachloroethylene 2.63E-03 1.15E-02 1.15E-02 Tetrachloroethylene 2.22E-03 9.74E-03 9.74E-03 Styrene 6.29E-03 2.75E-02 2.75E-02

1,1,1 - trichloroethane 1.22E-03 5.35E-03 5.35E-03 1,1,1 - trichloroethane 1.03E-03 4.53E-03 4.53E-03 Tetrachloroethylene 1.08E-02 4.74E-02 4.74E-02

Vinyl acetate 4.64E-04 2.03E-03 2.03E-03 Vinyl acetate 3.93E-04 1.72E-03 1.72E-03 1,1,1 - trichloroethane 5.03E-03 2.20E-02 2.20E-02

Benzo(a)anthracene 0.00E+00 0.00E+00 0.00E+00 Benzo(a)anthracene 0.00E+00 0.00E+00 0.00E+00 Vinyl acetate 1.91E-03 8.37E-03 8.37E-03

Chrysene 0.00E+00 0.00E+00 0.00E+00 Chrysene 0.00E+00 0.00E+00 0.00E+00 Benzo(a)anthracene 0.00E+00 0.00E+00 0.00E+00

Benzo(b)fluoranthene 0.00E+00 0.00E+00 0.00E+00 Benzo(b)fluoranthene 0.00E+00 0.00E+00 0.00E+00 Chrysene 0.00E+00 0.00E+00 0.00E+00

Benzo(k)fluoranthene 0.00E+00 0.00E+00 0.00E+00 Benzo(k)fluoranthene 0.00E+00 0.00E+00 0.00E+00 Benzo(b)fluoranthene 0.00E+00 0.00E+00 0.00E+00

Benzo(a)pyrene 0.00E+00 0.00E+00 0.00E+00 Benzo(a)pyrene 0.00E+00 0.00E+00 0.00E+00 Benzo(k)fluoranthene 0.00E+00 0.00E+00 0.00E+00

Indeno(1,2,3-cd)pyrene 0.00E+00 0.00E+00 0.00E+00 Indeno(1,2,3-cd)pyrene 0.00E+00 0.00E+00 0.00E+00 Benzo(a)pyrene 0.00E+00 0.00E+00 0.00E+00

Dibenz(a,h)anthracene 0.00E+00 0.00E+00 0.00E+00 Dibenz(a,h)anthracene 0.00E+00 0.00E+00 0.00E+00 Indeno(1,2,3-cd)pyrene 0.00E+00 0.00E+00 0.00E+00Benzo(g,h,i)perylene 0.00E+00 0.00E+00 0.00E+00 Benzo(g,h,i)perylene 0.00E+00 0.00E+00 0.00E+00 Dibenz(a,h)anthracene 0.00E+00 0.00E+00 0.00E+002,3,7,8-TCDD 8.73E-10 3.83E-09 3.83E-09 2,3,7,8-TCDD 7.39E-10 3.24E-09 3.24E-09 Benzo(g,h,i)perylene 0.00E+00 0.00E+00 0.00E+00

Total PAH 0.00E+00 0.00E+00 0.00E+00 Total PAH 0.00E+00 0.00E+00 0.00E+00 2,3,7,8-TCDD 3.60E-09 1.57E-08 1.57E-08POM 2.24E-03 9.79E-03 9.79E-03 POM 1.89E-03 8.29E-03 8.29E-03 Total PAH 0.00E+00 0.00E+00 0.00E+00

POM 1.06E-02 4.65E-02 4.65E-02

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Air Quality Permit Program Doc Type: Permit Application



STRU13c) d) c) d) c) d)


HrUnc tpy


Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy

PM 81.6 118966.8 357.4 PM 28.8 126.3 126.3PM10 136.0 27413.1 595.7 PM10 19.4 85.0 85.0PM2.5 136.0 7188.8 595.7 PM2.5 0.1 0.3 0.3CO 1020.0 4467.6 4467.6NOX 816.0 12184.4 3574.1

SO2 4450.0 SO2 2600.0 35537.7 893.5VOC 23.2 101.5 101.5H2SO4 0.8 103.4 3.7

CO2 1.43E+06 6.25E+06 6.25E+06CH4 1.62E+02 7.08E+02 7.08E+02N2O 23.5 103.0 103.0CO2-e 1.44E+06 6.30E+06 6.30E+06Total HAP 24.1264 2483.9981 105.6737Fluorides 5.71E+01 2.50E+03 2.50E+02Lead 2.79E-02 1.79E+02 1.22E-01Hydrogen Chloride 1.36E+01 2.03E+03 5.96E+01Hydrogen Fluoride 5.80E+00 2.54E+02 2.54E+01Benzene 5.02E-01 2.20E+00 2.20E+00Hexane 2.59E-02 1.13E-01 1.13E-01Toluene 9.27E-02 4.06E-01 4.06E-01Xylenes 1.43E-02 6.26E-02 6.26E-02Acetaldehyde 2.20E-01 9.65E-01 9.65E-01Acetophenone 5.80E-03 2.54E-02 2.54E-02Acrolein 1.12E-01 4.91E-01 4.91E-01Acenaphthylene 0.00E+00 0.00E+00 0.00E+00Acenaphthene 0.00E+00 0.00E+00 0.00E+00Anthracene 0.00E+00 0.00E+00 0.00E+00Antimony 6.95E-03 3.05E-02 3.05E-02Arsenic 1.58E-01 6.94E-01 6.94E-01Benzyl chloride 2.70E-01 1.18E+00 1.18E+00Beryllium 8.11E-03 3.55E-02 3.55E-02Biphenyl 1.31E-03 5.75E-03 5.75E-03

bis(2-Ethylhexyl)phthalate 2.82E-02 1.24E-01 1.24E-01

Bromoform 1.51E-02 6.60E-02 6.60E-02Cadmium 1.97E-02 8.63E-02 8.63E-02Carbon disulfide 5.02E-02 2.20E-01 2.20E-01

2-Chloroacetophenone 2.70E-03 1.18E-02 1.18E-02

Chlorobenzene 8.50E-03 3.72E-02 3.72E-02Chloroform 2.28E-02 9.98E-02 9.98E-02Chromium 1.00E-01 4.40E-01 4.40E-01Cobalt 3.86E-02 1.69E-01 1.69E-01Cumene 2.05E-03 8.97E-03 8.97E-03Cyanide Compounds (Cyanide) 9.66E-01 4.23E+00 4.23E+00

2,4-Dinitrotoluene 1.08E-04 4.74E-04 4.74E-04,Dimethylbenz(a)anthra 0.00E+00 0.00E+00 0.00E+00

Dimethyl sulfate 1.85E-02 8.12E-02 8.12E-02Ethylbenzene 3.63E-02 1.59E-01 1.59E-01Ethyl chloride 1.62E-02 7.11E-02 7.11E-02Ethylene dibromide 4.64E-04 2.03E-03 2.03E-03Ethylene dichloride 1.55E-02 6.77E-02 6.77E-02Fluoranthene 0.00E+00 0.00E+00 0.00E+00Fluorene 0.00E+00 0.00E+00 0.00E+00Formaldehyde 9.27E-02 4.06E-01 4.06E-01Isophorone 2.24E-01 9.82E-01 9.82E-01Manganese 1.89E-01 8.29E-01 8.29E-01Mercury 3.21E-03 1.40E-01 1.30E-02Methyl bromide 6.18E-02 2.71E-01 2.71E-01Methyl chloride 2.05E-01 8.97E-01 8.97E-01

EU 004 a) Delta ID No.: EU 005

b) Tempo SI ID No.: FUGI2

e) Potential e) Potential

Alternate Format


a) Delta ID No.:a) Delta ID No.: SV 003

b) Tempo SI ID No.: EQUI85

e) Potential

b) Tempo SI ID No.:

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Alternate Format

Methyl ethyl ketone 1.51E-01 6.60E-01 6.60E-01

Methyl hydrazine 6.57E-02 2.88E-01 2.88E-01

Methyl methacrylate 7.73E-03 3.38E-02 3.38E-02Methyl tert butyl ether 1.35E-02 5.92E-02 5.92E-02

3-Methylchloranthrene 0.00E+00 0.00E+00 0.00E+00

Methylene chloride 1.12E-01 4.91E-01 4.91E-01

2-Methylnaphthalene 0.00E+00 0.00E+00 0.00E+00

Naphthalene 0.00E+00 0.00E+00 0.00E+00Nickel 1.08E-01 4.74E-01 4.74E-01Phenanthrene 0.00E+00 0.00E+00 0.00E+00Phenol 6.18E-03 2.71E-02 2.71E-02Propionaldehyde 1.47E-01 6.43E-01 6.43E-01Pyrene 0.00E+00 0.00E+00 0.00E+00Selenium 5.02E-01 2.20E+00 2.20E+00Styrene 9.66E-03 4.23E-02 4.23E-02

Tetrachloroethylene 1.66E-02 7.28E-02 7.28E-021,1,1 - trichloroethane 7.73E-03 3.38E-02 3.38E-02

Vinyl acetate 2.94E-03 1.29E-02 1.29E-02

Benzo(a)anthracene 0.00E+00 0.00E+00 0.00E+00

Chrysene 0.00E+00 0.00E+00 0.00E+00Benzo(b)fluoranthene 0.00E+00 0.00E+00 0.00E+00Benzo(k)fluoranthene 0.00E+00 0.00E+00 0.00E+00

Benzo(a)pyrene 0.00E+00 0.00E+00 0.00E+00Indeno(1,2,3-cd)pyrene 0.00E+00 0.00E+00 0.00E+00ne 0.00E+00 0.00E+00 0.00E+00Benzo(g,h,i)perylene 0.00E+00 0.00E+00 0.00E+00

2,3,7,8-TCDD 5.53E-09 2.42E-08 2.42E-08Total PAH 0.00E+00 0.00E+00 0.00E+00POM 1.63E-02 7.15E-02 7.15E-02

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c) d) c) d) c) d)


HrUnc tpy


Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy

PM 18.6 81.3 81.3 PM 0.2 70.1 0.7 PM 0.2 87.6 0.7PM10 12.5 54.7 54.7 PM10 0.3 21.0 1.4 PM10 0.4 26.3 1.4PM2.5 0.0 0.2 0.2 PM2.5 0.3 21.0 1.4 PM2.5 0.4 26.3 1.4

Lead 9.28E-07 4.06E-04 3.81E-06 Lead 1.16E-06 5.08E-04 3.81E-06

b) Tempo SI ID No.: EQUI1 b) Tempo SI ID No.: EQUI102

a) Delta ID No.: EU 006 EU 011 a) Delta ID No.: EU 012



Alternate Format


a) Delta ID No.:

of 102





c) d) c) d) c) d)


HrUnc tpy


Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy

PM 0.0 20.3 0.2 PM 0.0 20.3 0.2 PM 0.2 93.9 0.9PM10 0.2 13.1 0.9 PM10 0.2 13.1 0.9 PM10 0.2 93.9 0.9PM2.5 0.2 13.1 0.9 PM2.5 0.2 13.1 0.9 PM2.5 1.5 93.9 6.6Lead 2.83E-07 1.24E-04 1.24E-06 Lead 2.83E-07 1.24E-04 1.24E-06

EU 015

e) Potential e) Potentiale) Potential

b) Tempo SI ID No.:

a) Delta ID No.: EU 013

EQUI3 b) Tempo SI ID No.: EQUI4 b) Tempo SI ID No.: EQUI99

Alternate Format


a) Delta ID No.: EU 014 a) Delta ID No.:

of 102





c) d) c) d) c) d)


HrUnc tpy


Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy


Alternate Format


a) Delta ID No.: EU 018 a) Delta ID No.: EU 019a) Delta ID No.: EU 017

EQUI98


b) Tempo SI ID No.: b) Tempo SI ID No.: EQUI97 b) Tempo SI ID No.: EQUI5

of 102





c) d) c) d) c) d)


HrUnc tpy


Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy

PM 0.1 61.9 0.6 PM 0.1 61.9 0.6 PM 1.58E-01 3.95E-02 3.95E-02PM10 0.1 61.9 0.6 PM10 0.1 61.9 0.6 PM10 1.58E-01 3.95E-02 3.95E-02PM2.5 1.0 61.9 4.3 PM2.5 1.0 61.9 4.3 PM2.5 1.58E-01 3.95E-02 3.95E-02

Lead 2.88E-05 7.20E-06 7.20E-06SO2 4.85E-03 1.21E-03 1.21E-03

H2SO4 1.11E-04 2.78E-05 2.78E-05NOx 3.16E+00 7.89E-01 7.89E-01VOC 3.16E+00 7.89E-01 7.89E-01

CO 2.37E+00 5.92E-01 5.92E-01CO2 5.30E+02 1.32E+02 1.32E+02CH4 2.12E-02 5.29E-03 5.29E-03N2O 4.23E-03 1.06E-03 1.06E-03CO2-e 5.32E+02 1.33E+02 1.33E+02Benzene 2.99E-03 7.46E-04 7.46E-04Toluene 1.31E-03 3.27E-04 3.27E-04

Xylenes 9.12E-04 2.28E-04 2.28E-04

1,3-Butadiene 1.25E-04 3.13E-05 3.13E-05

Formaldehyde 3.78E-03 9.44E-04 9.44E-04

Acetaldehyde 2.45E-03 6.14E-04 6.14E-04

Acrolein 2.96E-04 7.40E-05 7.40E-05

Naphthalene 2.71E-04 6.78E-05 6.78E-05

Acenaphthylene 1.62E-05 4.05E-06 4.05E-06

Acenaphthene 4.54E-06 1.14E-06 1.14E-06

Fluorene 9.34E-05 2.34E-05 2.34E-05

Phenanthrene 9.41E-05 2.35E-05 2.35E-05

Anthracene 5.98E-06 1.50E-06 1.50E-06

Fluoranthene 2.44E-05 6.09E-06 6.09E-06

Pyrene 1.53E-05 3.82E-06 3.82E-06

Benzo(a)anthracene 5.38E-06 1.34E-06 1.34E-06

Chrysene 1.13E-06 2.82E-07 2.82E-07

Benzo(b)fluoranthene 3.17E-07 7.93E-08 7.93E-08

Benzo(k)fluoranthene 4.96E-07 1.24E-07 1.24E-07

Benzo(a)pyrene

6.02E-07 1.50E-07 1.50E-07

Indeno(1,2,3-cd)pyrene

1.20E-06 3.00E-07 3.00E-07

Dibenz(a,h)anthracene 1.87E-06 4.66E-07 4.66E-07

Benzo(g,h,i)perylene 1.56E-06 3.91E-07 3.91E-07

Total HAP

1.24E-02 3.11E-03 3.11E-03



Alternate Format


a) Delta ID No.: EU 021a) Delta ID No.: EU 020

e) Potential



of 102





c) d) c) d) c) d)


HrUnc tpy


Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy

PM 8.57E-02 7.8 3.75E-01 PM 6.43E-02 1.6 2.82E-01 PM 6.43E-02 1.6 2.82E-01PM10 8.57E-02 5.0 3.75E-01 PM10 6.43E-02 1.0 2.82E-01 PM10 6.43E-02 1.0 2.82E-01PM2.5 8.57E-02 5.0 3.75E-01 PM2.5 6.43E-02 1.0 2.82E-01 PM2.5 6.43E-02 1.0 2.82E-01


EU 026a) Delta ID No.: EU 024 a) Delta ID No.: EU 025

Alternate Format


a) Delta ID No.:

e) Potential


e) Potentiale) Potential

of 102





c) d) c) d) c) d)


HrUnc tpy


Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy

PM 6.43E-02 1.6 2.82E-01 PM 6.43E-02 1.6 2.82E-01 PM 6.43E-02 1.6 2.82E-01PM10 6.43E-02 1.0 2.82E-01 PM10 6.43E-02 1.0 2.82E-01 PM10 6.43E-02 1.0 2.82E-01PM2.5 6.43E-02 1.0 2.82E-01 PM2.5 6.43E-02 1.0 2.82E-01 PM2.5 6.43E-02 1.0 2.82E-01



EQUI90 b) Tempo SI ID No.:

EU 028 a) Delta ID No.: EU 029a) Delta ID No.: EU 027 a) Delta ID No.:

Alternate Format


b) Tempo SI ID No.:EQUI89

e) Potential

of 102





a) Delta ID No.: a) Delta ID No.:

b) Tempo SI ID No.: b) Tempo SI ID No.:

c) d) c) d) c) d)


HrUnc tpy


Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy

PM 4.29E-02 0.1 1.88E-01 PM 0.3 97.7 1.5 PM 0.5 97.7 2.2PM10 4.29E-02 0.1 1.88E-01 PM10 0.3 62.9 1.5 PM10 0.5 62.9 2.2PM2.5 4.29E-02 0.1 1.88E-01 PM2.5 0.3 62.9 1.5 PM2.5 0.5 62.9 2.2

Lead 3.41E-07 5.98E-04 1.49E-06 Lead 4.09E-07 5.98E-04 1.79E-06

e) Potential

EQUI120

e) Potential

EQUI94b) Tempo SI ID No.:


Alternate Format


EU 031EU 030

EQUI93

e) Potential

of 102





c) d) c) d) c) d)


HrUnc tpy


Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy

PM 1.31E-01 3.27E-02 3.27E-02 PM 1.46E-01 3.65E-02 3.65E-02 PM 8.37E-03 7.86E-01 7.86E-03PM10 1.31E-01 3.27E-02 3.27E-02 PM10 1.20E-01 3.00E-02 3.00E-02 PM10 2.77E-02 3.72E-01 2.60E-02PM2.5 1.31E-01 3.27E-02 3.27E-02 PM2.5 1.16E-01 2.91E-02 2.91E-02 PM2.5 4.19E-03 5.63E-02 3.94E-03Lead 2.51E-05 6.27E-06 6.27E-06 Lead 1.32E-04 3.29E-05 3.29E-05 Lead 4.85E-08 4.56E-06 4.56E-08SO2 4.22E-03 1.06E-03 1.06E-03 SO2 2.22E-02 5.55E-03 5.55E-03

H2SO4 9.70E-05 2.42E-05 2.42E-05 H2SO4 5.09E-04 1.27E-04 1.27E-04NOx 2.62E+00 6.55E-01 6.55E-01 NOx 2.47E+01 6.18E+00 6.18E+00VOC 2.62E+00 6.55E-01 6.55E-01 VOC 5.35E-01 1.34E-01 1.34E-01

CO 1.96E+00 4.91E-01 4.91E-01 CO 2.14E+00 5.35E-01 5.35E-01CO2 4.62E+02 1.15E+02 1.15E+02 CO2 2.42E+03 6.06E+02 6.06E+02CH4 1.84E-02 4.61E-03 4.61E-03 CH4 9.69E-02 2.42E-02 2.42E-02N2O 3.69E-03 9.22E-04 9.22E-04 N2O 1.94E-02 4.84E-03 4.84E-03CO2-e 4.63E+02 1.16E+02 1.16E+02 CO2-e 2.43E+03 6.08E+02 6.08E+02Benzene 2.60E-03 6.50E-04 6.50E-04 Benzene 1.14E-02 2.84E-03 2.84E-03Toluene 1.14E-03 2.85E-04 2.85E-04 Toluene 4.11E-03 1.03E-03 1.03E-03

Xylenes 7.94E-04 1.99E-04 1.99E-04 Xylenes 2.83E-03 7.07E-04 7.07E-04

1,3-Butadiene 1.09E-04 2.72E-05 2.72E-05 1,3-Butadiene 0.00E+00 0.00E+00 0.00E+00

Formaldehyde 3.29E-03 8.22E-04 8.22E-04 Formaldehyde 1.16E-03 2.89E-04 2.89E-04

Acetaldehyde 2.14E-03 5.34E-04 5.34E-04 Acetaldehyde 3.69E-04 9.23E-05 9.23E-05

Acrolein 2.58E-04 6.45E-05 6.45E-05 Acrolein 1.15E-04 2.88E-05 2.88E-05

Naphthalene 2.36E-04 5.91E-05 5.91E-05 Naphthalene 1.90E-03 4.76E-04 4.76E-04

Acenaphthylene 1.41E-05 3.53E-06 3.53E-06 Acenaphthylene 1.35E-04 3.38E-05 3.38E-05

Acenaphthene 3.96E-06 9.89E-07 9.89E-07 Acenaphthene 6.85E-05 1.71E-05 1.71E-05

Fluorene 8.14E-05 2.03E-05 2.03E-05 Fluorene 1.87E-04 4.69E-05 4.69E-05

Phenanthrene 8.19E-05 2.05E-05 2.05E-05 Phenanthrene 5.97E-04 1.49E-04 1.49E-04

Anthracene 5.21E-06 1.30E-06 1.30E-06 Anthracene 1.80E-05 4.50E-06 4.50E-06

Fluoranthene 2.12E-05 5.30E-06 5.30E-06 Fluoranthene 5.90E-05 1.48E-05 1.48E-05

Pyrene 1.33E-05 3.33E-06 3.33E-06 Pyrene 5.43E-05 1.36E-05 1.36E-05

Benzo(a)anthracene 4.68E-06 1.17E-06 1.17E-06 Benzo(a)anthracene 9.11E-06 2.28E-06 2.28E-06

Chrysene 9.84E-07 2.46E-07 2.46E-07 Chrysene 2.24E-05 5.60E-06 5.60E-06

Benzo(b)fluoranthene 2.76E-07 6.91E-08 6.91E-08 Benzo(b)fluoranthene 1.63E-05 4.06E-06 4.06E-06

Benzo(k)fluoranthene 4.32E-07 1.08E-07 1.08E-07 Benzo(k)fluoranthene 3.19E-06 7.98E-07 7.98E-07

Benzo(a)pyrene

5.24E-07 1.31E-07 1.31E-07

Benzo(a)pyrene

3.76E-06 9.41E-07 9.41E-07


1.05E-06 2.61E-07 2.61E-07


6.06E-06 1.52E-06 1.52E-06

Dibenz(a,h)anthracene 1.62E-06 4.06E-07 4.06E-07 Dibenz(a,h)anthracene 5.07E-06 1.27E-06 1.27E-06

Benzo(g,h,i)perylene 1.36E-06 3.41E-07 3.41E-07 Benzo(g,h,i)perylene 8.14E-06 2.04E-06 2.04E-06

Total HAP

1.08E-02 2.71E-03 2.71E-03

Total HAP

2.32E-02 5.79E-03 5.79E-03

b) Tempo SI ID No.: EQUI11EQUI119

Alternate Format


a) Delta ID No.: EU 035a) Delta ID No.: EU 034a) Delta ID No.: EU 033

b) Tempo SI ID No.: EQUI23 b) Tempo SI ID No.:

e) Potentiale) Potential e) Potential

of 102





c) d) c) d) c) d)


HrUnc tpy


Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy

PM 1.08E-02 1.57E+00 1.57E-02 PM 2.39E-03 7.86E-01 7.86E-03 PM 1.91E-03 7.86E-01 7.86E-03PM10 3.56E-02 7.43E-01 5.20E-02 PM10 7.91E-03 3.72E-01 2.60E-02 PM10 6.33E-03 3.72E-01 2.60E-02PM2.5 5.39E-03 1.13E-01 7.88E-03 PM2.5 1.20E-03 5.63E-02 3.94E-03 PM2.5 9.59E-04 5.63E-02 3.94E-03Lead 6.24E-08 9.11E-06 9.11E-08 Lead 1.39E-08 4.56E-06 4.56E-08 Lead 1.11E-08 4.56E-06 4.56E-08




Alternate Format

a) Delta ID No.: EU 036 a) Delta ID No.: EU 037



of 102





c) d) c) d) c) d)


HrUnc tpy


Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy

PM 2.56E-02 1.12E+01 1.12E-01 PM 5.26E-03 3.81E-01 3.81E-03 PM 4.30E-03 4.04E-01 4.04E-03PM10 1.15E-01 7.21E+00 5.04E-01 PM10 1.74E-02 1.80E-01 1.26E-02 PM10 1.42E-02 1.91E-01 1.34E-02PM2.5 1.15E-01 7.21E+00 5.04E-01 PM2.5 2.64E-03 2.73E-02 1.91E-03 PM2.5 2.16E-03 2.90E-02 2.03E-03Lead 1.56E-07 6.85E-05 6.85E-07 Lead 3.05E-08 2.21E-06 2.21E-08 Lead 2.50E-08 2.35E-06 2.35E-08

b) Tempo SI ID No.: EQUI116 b) Tempo SI ID No.: b) Tempo SI ID No.: EQUI118

e) Potential




Alternate Format



EQUI117

of 102





c) d) c) d) c) d)


HrUnc tpy


Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy

PM 1.91E-03 7.86E-01 7.86E-03 PM 5.74E+00 2.84E+01 5.97E+00 PMPM10 6.33E-03 3.72E-01 2.60E-02 PM10 3.36E+00 1.34E+01 3.50E+00 PM10PM2.5 9.59E-04 5.63E-02 3.94E-03 PM2.5 1.12E+00 2.04E+00 1.16E+00 PM2.5Lead 1.11E-08 4.56E-06 4.56E-08 Lead 3.51E-05 1.67E-04 3.65E-05 Lead

e) Potential

b) Tempo SI ID No.: EQUI113 b) Tempo SI ID No.: EQUI122 b) Tempo SI ID No.:

Alternate Format


a) Delta ID No.: EU 042 a) Delta ID No.:a) Delta ID No.: EU 047


of 102





c) d) c) d) c) d)


HrUnc tpy


Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy

PM PM 3.7 16.2 16.2 PM 0.0 0.0 0.0PM10 PM10 1.8 8.1 8.1 PM10 0.0 0.0 0.0PM2.5 PM2.5 0.3 1.2 1.2 PM2.5 0.0 0.0 0.0Lead Lead 2.14E-05 9.38E-05 9.38E-05 Lead 0.00E+00 0.00E+00 0.00E+00

e) Potential

b) Tempo SI ID No.: FUGI9b) Tempo SI ID No.:

a) Delta ID No.:



a) Delta ID No.: FS 001

Alternate Format



of 102





c) d) c) d) c) d)


HrUnc tpy


Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy

PM 3.7 16.1 16.1 PM 18.7 245.9 26.1 PM 73.0 319.7 319.7PM10 1.8 8.1 8.1 PM10 11.0 82.4 10.4 PM10 26.1 114.4 114.4PM2.5 0.3 1.2 1.2 PM2.5 1.8 8.2 1.3 PM2.5 6.8 29.8 29.8Lead 2.25E-05 9.87E-05 9.87E-05 Lead 7.48E-05 8.14E-04 9.05E-05 Lead 4.43E-04 1.94E-03 1.94E-03


FUGI3b) Tempo SI ID No.:

a) Delta ID No.: FS 003 a) Delta ID No.: FS 004

Alternate Format

e) Potentiale) Potential e) Potential

b) Tempo SI ID No.: FUGI5 b) Tempo SI ID No.: FUGI6


of 102





c) d) c) d) c) d)


HrUnc tpy


Lbs per Hr

Unc tpy


Lbs per Hr

Unc tpy

Limited tpy


e) Potentiale) Potential


b) Tempo SI ID No.: FUGI11 b) Tempo SI ID No.: FUGI10

Alternate Format



e) Potential

FUGI4b) Tempo SI ID No.:


of 102




Total Facility Emissions Summary Table

c) d) f)


HrUnc tpy

Limited tpy Pollutant Name Unrestricted Limited

PM 7.9 34.5 34.5 PM 232,868.9 1,445.55PM10 3.9 17.3 17.3 PM10 54,190.8 1,934.4PM2.5 0.6 2.6 2.6 PM2.5 14,525.9 1,686.0Lead 4.83E-05 2.11E-04 2.11E-04 CO 7,623.4 7,623.4

NOX 26,048.7 6,483.5SO2 69,037.3 7,561.0VOC 198.8 198.8H2SO4 387.5 8.7CO2 12,151,354.3 12,151,354.3CH4 1,375.5 1,375.5N2O 200.1 200.1CO2-e 12,245,365.1 12,245,365.1Total HAP 4,666.7 316.9Flourides 2.60E+03 2.85E+02Lead 1.88E+02 3.86E+00Hydrogen Chloride 3.94E+03 1.16E+02Hydrogen Fluoride 4.93E+02 1.57E+02Benzene 4.28E+00 4.28E+00Hexane 2.20E-01 2.20E-01Toluene 7.91E-01 7.91E-01Xylenes 1.23E-01 1.23E-011,3-Butadiene 5.85E-05 5.85E-05Acetaldehyde 1.88E+00 1.88E+00Acetophenone 4.93E-02 4.93E-02Acrolein 9.54E-01 9.54E-01Acenaphthylene 4.14E-05 4.14E-05Acenaphthene 1.93E-05 1.93E-05Anthracene 7.30E-06 7.30E-06Antimony 5.92E-02 5.92E-02Arsenic 1.35E+00 1.35E+00Benzyl chloride 2.30E+00 2.30E+00Beryllium 6.90E-02 6.90E-02

Biphenyl 1.12E-02 1.12E-02

bis(2-Ethylhexyl)phthalate 2.40E-01 2.40E-01Bromoform 1.28E-01 1.28E-01Cadmium 1.68E-01 1.68E-01

Carbon disulfide 4.27E-01 4.27E-012-Chloroacetophenone 2.30E-02 2.30E-02Chlorobenzene 7.23E-02 7.23E-02Chloroform 1.94E-01 1.94E-01Chromium 8.55E-01 8.55E-01Cobalt 3.29E-01 3.29E-01

Cumene 1.74E-02 1.74E-02y Compounds 8.22E+00 8.22E+002,4-Dinitrotoluene 9.20E-04 9.20E-04,Dimethylbenz(a)anthra 0.00E+00 0.00E+00Dimethyl sulfate 1.58E-01 1.58E-01Ethylbenzene 3.09E-01 3.09E-01Ethyl chloride 1.38E-01 1.38E-01Ethylene dibromide 3.94E-03 3.94E-03Ethylene dichloride 1.31E-01 1.31E-01Fluoranthene 2.61E-05 2.61E-05Fluorene 9.06E-05 9.06E-05Formaldehyde 7.91E-01 7.91E-01Isophorone 1.91E+00 1.91E+00Manganese 1.61E+00 1.61E+00Mercury 2.73E-01 2.84E-02Methyl bromide 5.26E-01 5.26E-01

e) Potential g) Potential (tons/year)


Alternate Format


of 102




Alternate Format

Methyl chloride 1.74E+00 1.74E+00

Methyl ethyl ketone 1.28E+00 1.28E+00

Methyl hydrazine 5.59E-01 5.59E-01

Methyl methacrylate 6.57E-02 6.57E-02

Methyl tert butyl ether 1.15E-01 1.15E-01

3-Methylchloranthrene 0.00E+00 0.00E+00

Methylene chloride 9.53E-01 9.53E-01

2-Methylnaphthalene 0.00E+00 0.00E+00Naphthalene 6.03E-04 6.03E-04Nickel 9.20E-01 9.20E-01Phenanthrene 1.93E-04 1.93E-04Phenol 5.26E-02 5.26E-02Propionaldehyde 1.25E+00 1.25E+00Pyrene 2.07E-05 2.07E-05Selenium 4.27E+00 4.27E+00

Styrene 8.22E-02 8.22E-02

Tetrachloroethylene 1.41E-01 1.41E-011,1,1 - trichloroethane 6.57E-02 6.57E-02

Vinyl acetate 2.50E-02 2.50E-02

Benzo(a)anthracene 4.79E-06 4.79E-06

Chrysene 6.13E-06 6.13E-06Benzo(b)fluoranthene 4.21E-06 4.21E-06Benzo(k)fluoranthene 1.03E-06 1.03E-06

Benzo(a)pyrene 1.22E-06 1.22E-06cd)pyrene 2.08E-06 2.08E-06ne 2.14E-06 2.14E-06

Benzo(g,h,i)perylene 2.77E-06 2.77E-062,3,7,8-TCDD 4.70E-08 4.70E-08Total PAH 0.00E+00 0.00E+00POM 1.36E-01 1.36E-01

Minnesota PowerBoswell Permit Renewal ApplicationPotential to Emit Calculations - Uncontrolled PTE Summary

EU / FS SV CE Unit Name lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy1 3 Boiler 1 4,293.89 18,807.25 989.43 4,333.69 259.47 1,136.46 30.54 133.76 732.95 3,210.34 1,282.67 5,618.102 3 Boiler 2 3,634.83 15,920.55 837.56 3,668.52 219.64 962.03 25.85 113.23 620.45 2,717.59 1,085.80 4,755.783 3 Boiler 3 17,674.86 77,415.88 4,072.76 17,838.69 1,068.03 4,677.99 663.75 2,907.23 1,810.23 7,928.80 5,279.83 23,125.654 4 Boiler 4 27,161.36 118,966.77 6,258.70 27,413.13 1,641.27 7,188.77 1,020.00 4,467.60 2,781.82 12,184.36 8,113.64 35,537.735 5 Unit 4 Cooling Tower 28.84 126.33 19.42 85.04 0.06 0.276 6 Unit 3 Cooling Tower 18.57 81.32 12.50 54.75 0.04 0.189 9 Emergency Generator 3 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

10 10 Emergency Generator 4 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.0023 22 NA Emergency Generator 3-APCE 0.16 0.04 0.16 0.04 0.16 0.04 2.37 0.59 3.16 0.79 0.00 0.0033 33 Emergency Generator 3-250kw 0.13 0.03 0.13 0.03 0.13 0.03 1.96 0.49 2.62 0.65 0.00 0.0034 34 Unit 4 Emergency Generator 0.15 0.04 0.12 0.03 0.12 0.03 2.14 0.53 24.71 6.18 0.02 0.0111 11 7 Coal Handling - Crusher Building 16.00 70.08 4.80 21.02 4.80 21.02

12 12 8Coal Handling - Crusher and Sampling

House 20.00 87.60 6.00 26.28 6.00 26.2813 13 9 Fly Ash Silo 4.63 20.28 2.98 13.06 2.98 13.0614 14 10 Fly Ash Hoppers #1/#2 4.63 20.28 2.98 13.06 2.98 13.0615 15 13 Unit 3 Activated Carbon Silo 21.43 93.86 21.43 93.86 21.43 93.8617 17 15 Fly Ash Silo A 39.43 81.42 20.72 47.56 9.75 36.1518 18 44 Fly Ash Loadout Building 5.47 5.69 2.59 2.69 0.39 0.4119 19 16 Limestone Silo 8.57 37.54 8.57 37.54 8.57 37.5420 20 17 Limestone Day Silo #1 14.14 61.95 14.14 61.95 14.14 61.9521 21 18 Limestone Day Silo #2 14.14 61.95 14.14 61.95 14.14 61.9524 24 32 Lime Storage Bin Vent 1.77 7.76 1.14 5.00 1.14 5.0025 25 33 Lime Day Bin A Bin Vent 0.35 1.55 0.23 1.00 0.23 1.0026 26 34 Lime Day Bin B Bin Vent 0.35 1.55 0.23 1.00 0.23 1.0027 27 35 Lime Day Bin C Bin Vent 0.35 1.55 0.23 1.00 0.23 1.0028 28 36 Lime Day Bin D Bin Vent 0.35 1.55 0.23 1.00 0.23 1.0029 29 37 Lime Day Bin E Bin Vent 0.35 1.55 0.23 1.00 0.23 1.0030 30 38 Unit 4 Activated Carbon Silo 0.03 0.14 0.02 0.09 0.02 0.0931 31 39 Waste Ash Silo 22.30 97.66 14.36 62.88 14.36 62.8832 32 40 Waste Ash Silo Truck Bay 22.30 97.66 14.36 62.88 14.36 62.8836 36 46 Lowering Well 1.08 1.57 0.51 0.74 0.08 0.1141 41 51 Unit 4 Bunkers 0.43 0.40 0.20 0.19 0.03 0.0335 35 45 Rail Unloading 0.84 0.79 0.40 0.37 0.06 0.0638 38 48 C-9/C-10 Transfer House 0.19 0.79 0.09 0.37 0.01 0.0640 40 50 Units 1, 2, 3 Bunkers 0.53 0.38 0.25 0.18 0.04 0.0337 37 47 C-16/C-18 Transfer House 0.24 0.79 0.11 0.37 0.02 0.0639 39 49 Dust Tank 2.56 11.19 1.65 7.21 1.65 7.2147 36 46 Storage Silos 0.19 0.79 0.09 0.37 0.01 0.0642 17 15 Fly Ash Silo A - Loadout 27.33 28.43 12.93 13.44 1.96 2.04

Point Source Totals 53,043 232,115 12,336 53,932 3,309 14,477 1,747 7,623 5,976 26,049 15,762 69,037

PM PM10 PM2.5 CO NOX SO2

FS 001 Coal Stockpile - Wind Erosion 3.69 16.18 1.85 8.09 0.28 1.21FS 002 Bottom Ash Pond - Wind Erosion 0.00 0.00 0.00 0.00 0.00 0.00FS 003 Fly Ash Pond - Wind Erosion 3.68 16.13 1.84 8.06 0.28 1.21FS 004 Unpaved Road Dust 149.11 245.85 55.65 82.43 5.57 8.24

FS 005Coal Stockpile & Flyash Pond Maintenance

(Bulldozer) 73.00 319.72 26.11 114.37 6.79 29.76FS 006 Coal Stockpile Material Handling 3.26 14.27 1.54 6.75 0.23 1.02FS 007 Paved Road Dust 73.74 105.71 14.75 21.14 3.62 5.19

FS 008Fly Ash Handling - Unloading to Disposal

Cell 1.50 1.56 0.93 0.74 0.49 0.11FS 009 Fly Ash Disposal Cell - Wind Erosion 7.89 34.54 3.94 17.27 0.59 2.59

Fugitive Source Totals 316 754 107 259 18 49 0 0 0 0 0 0Facility Total 53,359 232,869 12,443 54,191 3,327 14,526 1,747 7,623 5,976 26,049 15,762 69,037


EU / FS SV CE Unit Name1 3 Boiler 12 3 Boiler 23 3 Boiler 34 4 Boiler 45 5 Unit 4 Cooling Tower6 6 Unit 3 Cooling Tower9 9 Emergency Generator 3

10 10 Emergency Generator 423 22 NA Emergency Generator 3-APCE33 33 Emergency Generator 3-250kw34 34 Unit 4 Emergency Generator11 11 7 Coal Handling - Crusher Building


House13 13 9 Fly Ash Silo14 14 10 Fly Ash Hoppers #1/#215 15 13 Unit 3 Activated Carbon Silo17 17 15 Fly Ash Silo A 18 18 44 Fly Ash Loadout Building19 19 16 Limestone Silo20 20 17 Limestone Day Silo #121 21 18 Limestone Day Silo #224 24 32 Lime Storage Bin Vent25 25 33 Lime Day Bin A Bin Vent26 26 34 Lime Day Bin B Bin Vent27 27 35 Lime Day Bin C Bin Vent28 28 36 Lime Day Bin D Bin Vent29 29 37 Lime Day Bin E Bin Vent30 30 38 Unit 4 Activated Carbon Silo31 31 39 Waste Ash Silo32 32 40 Waste Ash Silo Truck Bay36 36 46 Lowering Well41 41 51 Unit 4 Bunkers35 35 45 Rail Unloading38 38 48 C-9/C-10 Transfer House40 40 50 Units 1, 2, 3 Bunkers37 37 47 C-16/C-18 Transfer House39 39 49 Dust Tank47 36 46 Storage Silos42 17 15 Fly Ash Silo A - Loadout

Point Source Totals

lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy3.66 16.05 3.73 16.35 0.37 1.61 83.57 366.04 225,749 988,7803.10 13.59 3.16 13.84 0.31 1.36 70.74 309.86 191,099 837,014

15.09 66.07 22.76 99.68 57.98 253.94 1.51 6.61 344.01 1,506.74 929,246 4,070,09623.18 101.54 571.20 2,501.86 23.61 103.41 40.80 178.70 567.12 2,484.00 1,427,993 6,254,610

0.00 0.00 0.00E+00 0.00E+00 0.00 0.000.00 0.00 0.00E+00 0.00E+00 0.00 0.003.16 0.79 1.11E-04 2.78E-05 2.88E-05 7.20E-06 0.01 0.00 530 1322.62 0.65 9.70E-05 2.42E-05 2.51E-05 6.27E-06 0.01 0.00 462 1150.53 0.13 5.09E-04 1.27E-04 1.32E-04 3.29E-05 0.02 0.01 2,425 606

9.28E-05 4.06E-04

1.16E-04 5.08E-042.83E-05 1.24E-042.83E-05 1.24E-040.00E+00 0.00E+002.41E-04 4.98E-043.35E-05 3.48E-050.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+001.36E-04 5.98E-041.36E-04 5.98E-046.24E-06 9.11E-062.50E-06 2.35E-064.85E-06 4.56E-061.11E-06 4.56E-063.05E-06 2.21E-061.39E-06 4.56E-061.56E-05 6.85E-051.11E-06 4.56E-061.67E-04 1.67E-04

51 199 594 2,602 88 388 43 188 1,065 4,667 2,777,503 12,151,354

CO2Total HAPVOC Fluorides H2SO4 Lead

FS 001 Coal Stockpile - Wind ErosionFS 002 Bottom Ash Pond - Wind ErosionFS 003 Fly Ash Pond - Wind ErosionFS 004 Unpaved Road Dust


(Bulldozer)FS 006 Coal Stockpile Material HandlingFS 007 Paved Road Dust


CellFS 009 Fly Ash Disposal Cell - Wind Erosion

Fugitive Source TotalsFacility Total

2.14E-05 9.38E-050.00E+00 0.00E+002.25E-05 9.87E-055.14E-04 8.14E-04

4.43E-04 1.94E-031.89E-05 8.28E-050.00E+00 0.00E+00

9.19E-06 9.56E-064.83E-05 2.11E-04

0 0 0 0 0 0 0 0 0 0 0 051 199 594 2,602 88 388 43 188 1,065 4,667 2,777,503 12,151,354



10 10 Emergency Generator 423 22 NA Emergency Generator 3-APCE33 33 Emergency Generator 3-250kw34 34 Unit 4 Emergency Generator11 11 7 Coal Handling - Crusher Building


House13 13 9 Fly Ash Silo14 14 10 Fly Ash Hoppers #1/#215 15 13 Unit 3 Activated Carbon Silo17 17 15 Fly Ash Silo A 18 18 44 Fly Ash Loadout Building19 19 16 Limestone Silo20 20 17 Limestone Day Silo #121 21 18 Limestone Day Silo #224 24 32 Lime Storage Bin Vent25 25 33 Lime Day Bin A Bin Vent26 26 34 Lime Day Bin B Bin Vent27 27 35 Lime Day Bin C Bin Vent28 28 36 Lime Day Bin D Bin Vent29 29 37 Lime Day Bin E Bin Vent30 30 38 Unit 4 Activated Carbon Silo31 31 39 Waste Ash Silo32 32 40 Waste Ash Silo Truck Bay36 36 46 Lowering Well41 41 51 Unit 4 Bunkers35 35 45 Rail Unloading38 38 48 C-9/C-10 Transfer House40 40 50 Units 1, 2, 3 Bunkers37 37 47 C-16/C-18 Transfer House39 39 49 Dust Tank47 36 46 Storage Silos42 17 15 Fly Ash Silo A - Loadout

Point Source Totals

lb/hr tpy lb/hr tpy lb/hr tpy25.56 111.93 3.72 16.28 227,496 996,43021.63 94.75 3.15 13.78 192,578 843,490

105.19 460.75 15.30 67.02 936,435 4,101,586161.65 708.04 23.51 102.99 1,439,042 6,303,002

0.02 0.01 0.00 0.00 532 1330.02 0.00 0.00 0.00 463 1160.10 0.02 0.02 0.00 2,433 608

314 1,376 46 200 2,798,978 12,245,365

CH4 N2O CO2-e



(Bulldozer)FS 006 Coal Stockpile Material HandlingFS 007 Paved Road Dust



Fugitive Source TotalsFacility Total

0 0 0 0 0 0314 1,376 46 200 2,798,978 12,245,365

Minnesota PowerBoswell Permit Renewal ApplicationPotential to Emit Calculations - Controlled PTE Summary

EU / FS SV CE Unit Name lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy1 3 Boiler 1 16.13 70.63 40.31 176.57 40.31 176.57 30.54 133.76 215.00 941.70 752.50 3,295.952 3 Boiler 2 13.65 59.79 34.13 149.47 34.13 149.47 25.85 113.23 182.00 797.16 637.00 2,790.063 3 Boiler 3 61.95 271.34 154.88 678.35 154.88 678.35 663.75 2,907.23 265.50 1,162.89 132.75 581.454 4 Boiler 4 81.60 357.41 136.00 595.68 136.00 595.68 1,020.00 4,467.60 816.00 3,574.08 2,600.00 893.525 5 Unit 4 Cooling Tower 28.84 126.33 19.42 85.04 0.06 0.276 6 Unit 3 Cooling Tower 18.57 81.32 12.50 54.75 0.04 0.189 9 Emergency Generator 3 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

10 10 Emergency Generator 4 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.0023 22 Emergency Generator 3-APCE 0.16 0.04 0.16 0.04 0.16 0.04 2.37 0.59 3.16 0.79 4.85E-03 1.21E-0333 33 Emergency Generator 3-250kw 0.13 0.03 0.13 0.03 0.13 0.03 1.96 0.49 2.62 0.65 0.00 0.0034 34 Unit 4 Emergency Generator 0.15 0.04 0.12 0.03 0.12 0.03 2.14 0.53 24.71 6.18 0.02 0.0111 11 Coal Handling - Crusher Building 0.16 0.66 0.34 1.38 0.34 1.38

12 12Coal Handling - Crusher and Sampling

House 0.20 0.66 0.42 1.38 0.42 1.3813 13 Fly Ash Silo 0.05 0.20 0.21 0.91 0.21 0.9114 14 Fly Ash Hoppers #1/#2 0.05 0.20 0.21 0.91 0.21 0.9115 15 Unit 3 Activated Carbon Silo 0.21 0.94 0.21 0.94 1.50 6.5717 17 Fly Ash Silo A 5.86 6.50 3.91 5.88 4.70 16.8618 18 Fly Ash Loadout Building 1.15 1.19 0.67 0.70 0.22 0.2319 19 Limestone Silo 0.09 0.38 0.09 0.38 0.60 2.6320 20 Limestone Day Silo #1 0.14 0.62 0.14 0.62 0.99 4.3421 21 Limestone Day Silo #2 0.14 0.62 0.14 0.62 0.99 4.3424 24 Lime Storage Bin Vent 0.09 0.38 0.09 0.38 0.09 0.3825 25 Lime Day Bin A Bin Vent 0.06 0.28 0.06 0.28 0.06 0.2826 26 Lime Day Bin B Bin Vent 0.06 0.28 0.06 0.28 0.06 0.2827 27 Lime Day Bin C Bin Vent 0.06 0.28 0.06 0.28 0.06 0.2828 28 Lime Day Bin D Bin Vent 0.06 0.28 0.06 0.28 0.06 0.2829 29 Lime Day Bin E Bin Vent 0.06 0.28 0.06 0.28 0.06 0.2830 30 Unit 4 Activated Carbon Silo 0.04 0.19 0.04 0.19 0.04 0.1931 31 Waste Ash Silo 0.33 1.45 0.33 1.45 0.33 1.4532 32 Waste Ash Silo Truck Bay 0.50 2.20 0.50 2.20 0.50 2.2036 36 46 Lowering Well 0.01 0.02 0.04 0.05 0.01 0.0141 41 51 Unit 4 Bunkers 0.00 0.00 0.01 0.01 0.00 0.0035 35 45 Rail Unloading 0.01 0.01 0.03 0.03 0.00 0.0038 38 48 C-9/C-10 Transfer House 0.00 0.01 0.01 0.03 0.00 0.0040 40 50 Units 1, 2, 3 Bunkers 0.01 0.00 0.02 0.01 0.00 0.0037 37 47 C-16/C-18 Transfer House 0.00 0.01 0.01 0.03 0.00 0.0039 39 49 Dust Tank 0.03 0.11 0.12 0.50 0.12 0.5047 36 46 Storage Silos 0.00 0.01 0.01 0.03 0.00 0.0042 17 15 Fly Ash Silo A - Loadout 5.74 5.97 3.36 3.50 1.12 1.16

Point Source Totals 236.30 990.65 408.85 1,763.49 378.53 1,647.48 1,746.61 7,623.44 1,508.98 6,483.45 4,122.28 7,560.98

PM PM10 PM2.5 CO NOX SO2

FS 001 Coal Stockpile - Wind Erosion 3.69 16.18 1.85 8.09 0.28 1.21FS 002 Bottom Ash Pond - Wind Erosion 0.00 0.00 0.00 0.00 0.00 0.00FS 003 Fly Ash Pond - Wind Erosion 3.68 16.13 1.84 8.06 0.28 1.21FS 004 Unpaved Road Dust 18.74 26.08 11.01 10.37 1.84 1.32

FS 005Coal Stockpile & Flyash Pond

Maintenance (Bulldozer) 73.00 319.72 26.11 114.37 6.79 29.76FS 006 Coal Stockpile Material Handling 3.26 14.27 1.54 6.75 0.23 1.02FS 007 Paved Road Dust 18.43 26.43 3.69 5.29 0.90 1.30


Cell 1.50 1.56 0.93 0.74 0.49 0.11FS 009 Fly Ash Disposal Cell - Wind Erosion 7.89 34.54 3.94 17.27 0.59 2.59

Fugitive Source Totals 130 455 51 171 11 39 0 0 0 0 0 0Facility Totals 366 1,446 460 1,934 390 1,686 1,747 7,623 1,509 6,483 4,122 7,561



10 10 Emergency Generator 423 22 Emergency Generator 3-APCE33 33 Emergency Generator 3-250kw34 34 Unit 4 Emergency Generator11 11 Coal Handling - Crusher Building


House13 13 Fly Ash Silo14 14 Fly Ash Hoppers #1/#215 15 Unit 3 Activated Carbon Silo17 17 Fly Ash Silo A 18 18 Fly Ash Loadout Building19 19 Limestone Silo20 20 Limestone Day Silo #121 21 Limestone Day Silo #224 24 Lime Storage Bin Vent25 25 Lime Day Bin A Bin Vent26 26 Lime Day Bin B Bin Vent27 27 Lime Day Bin C Bin Vent28 28 Lime Day Bin D Bin Vent29 29 Lime Day Bin E Bin Vent30 30 Unit 4 Activated Carbon Silo31 31 Waste Ash Silo32 32 Waste Ash Silo Truck Bay36 36 46 Lowering Well41 41 51 Unit 4 Bunkers35 35 45 Rail Unloading38 38 48 C-9/C-10 Transfer House40 40 50 Units 1, 2, 3 Bunkers37 37 47 C-16/C-18 Transfer House39 39 49 Dust Tank47 36 46 Storage Silos42 17 15 Fly Ash Silo A - Loadout

Point Source Totals

lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy3.66 16.05 0.13 0.59 0.37 1.61 12.43 54.43 225,749 988,7803.10 13.59 0.11 0.50 0.31 1.36 10.52 46.07 191,099 837,014

15.09 66.07 7.97 34.89 0.88 3.84 0.18 0.78 25.29 110.76 929,246 4,070,09623.18 101.54 57.12 250.19 0.85 3.72 0.03 0.12 24.13 105.67 1,427,993 6,254,610

0.00 0.00 0.00 0.00 0.00 0.000.00 0.00 0.00 0.00 0.00 0.003.16 0.79 1.11E-04 2.78E-05 2.88E-05 7.20E-06 0.01 0.00 529.91 132.482.62 0.65 9.70E-05 2.42E-05 0.00 0.00 0.01 0.00 461.55 115.390.53 0.13 5.09E-04 1.27E-04 0.00 0.00 0.02 0.01 2,424.98 606.25

9.28E-07 3.81E-06

1.16E-06 3.81E-062.83E-07 1.24E-062.83E-07 1.24E-060.00E+00 0.00E+003.59E-05 3.98E-057.03E-06 7.31E-060.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+000.00E+00 0.00E+003.41E-07 1.49E-064.09E-07 1.79E-066.24E-08 9.11E-082.50E-08 2.35E-084.85E-08 4.56E-081.11E-08 4.56E-083.05E-08 2.21E-081.39E-08 4.56E-081.56E-07 6.85E-071.11E-08 4.56E-083.51E-05 3.65E-05

51.35 198.83 65.09 285.07 1.98 8.65 0.88 3.86 72.40 316.94 2,777,503 12,151,354

CO2Total HAPLeadVOC Fluorides H2SO4



Maintenance (Bulldozer)FS 006 Coal Stockpile Material HandlingFS 007 Paved Road Dust



Fugitive Source TotalsFacility Totals

2.14E-05 9.38E-050.00E+00 0.00E+002.25E-05 9.87E-057.48E-05 9.05E-05

4.43E-04 1.94E-031.89E-05 8.28E-050.00E+00 0.00E+00

9.19E-06 9.56E-064.83E-05 2.11E-04

0 0 0 0 0 0 0 0 0 0 0 051 199 65 285 2 9 1 4 72 317 2,777,503 12,151,354



10 10 Emergency Generator 423 22 Emergency Generator 3-APCE33 33 Emergency Generator 3-250kw34 34 Unit 4 Emergency Generator11 11 Coal Handling - Crusher Building


House13 13 Fly Ash Silo14 14 Fly Ash Hoppers #1/#215 15 Unit 3 Activated Carbon Silo17 17 Fly Ash Silo A 18 18 Fly Ash Loadout Building19 19 Limestone Silo20 20 Limestone Day Silo #121 21 Limestone Day Silo #224 24 Lime Storage Bin Vent25 25 Lime Day Bin A Bin Vent26 26 Lime Day Bin B Bin Vent27 27 Lime Day Bin C Bin Vent28 28 Lime Day Bin D Bin Vent29 29 Lime Day Bin E Bin Vent30 30 Unit 4 Activated Carbon Silo31 31 Waste Ash Silo32 32 Waste Ash Silo Truck Bay36 36 46 Lowering Well41 41 51 Unit 4 Bunkers35 35 45 Rail Unloading38 38 48 C-9/C-10 Transfer House40 40 50 Units 1, 2, 3 Bunkers37 37 47 C-16/C-18 Transfer House39 39 49 Dust Tank47 36 46 Storage Silos42 17 15 Fly Ash Silo A - Loadout

Point Source Totals

lb/hr tpy lb/hr tpy lb/hr tpy25.56 111.93 3.72 16.28 227,496 996,43021.63 94.75 3.15 13.78 192,578 843,490

105.19 460.75 15.30 67.02 936,435 4,101,586161.65 708.04 23.51 102.99 1,439,042 6,303,002

0.02 0.01 0.00 0.00 531.70 132.920.02 0.00 0.00 0.00 463.11 115.780.10 0.02 0.02 0.00 2,433.18 608.29

314.17 1,375.52 45.71 200.08 2,798,978 12,245,365

CH4 N2O CO2-e



Maintenance (Bulldozer)FS 006 Coal Stockpile Material HandlingFS 007 Paved Road Dust



Fugitive Source TotalsFacility Totals

0 0 0 0 0 0314 1,376 46 200 2,798,978 12,245,365

Minnesota PowerBoswell Permit Renewal ApplicationPotential to Emit Calculations - HAP SummaryUpdate: 7/18/2017

NoteControlled PTE (lb/hr)

Uncontrolled PTE (tpy)

Controlled PTE (tpy)

Controlled PTE (lb/hr)
























1,1,1 - trichloroethane 1.22E-03 5.35E-03 5.35E-03 1.03E-03 4.53E-03 4.53E-03 5.03E-03 2.20E-02 2.20E-02 7.73E-03 3.38E-02 3.38E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 6.57E-02 6.57E-021,3-Butadiene 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.25E-04 3.13E-05 3.13E-05 1.09E-04 2.72E-05 2.72E-05 0.00E+00 0.00E+00 0.00E+00 5.85E-05 5.85E-052,4-Dinitrotoluene 1.71E-05 7.49E-05 7.49E-05 1.45E-05 6.34E-05 6.34E-05 7.04E-05 3.08E-04 3.08E-04 1.08E-04 4.74E-04 4.74E-04 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 9.20E-04 9.20E-042-Chloroacetophenone 4.28E-04 1.87E-03 1.87E-03 3.62E-04 1.59E-03 1.59E-03 1.76E-03 7.71E-03 7.71E-03 2.70E-03 1.18E-02 1.18E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 2.30E-02 2.30E-022-Methylnaphthalene (1) 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+003-Methylchloranthrene (1) 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+007,12-Dimethylbenz(a)anthracene (1) 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00Acenaphthene (1) 4.54E-06 1.14E-06 1.14E-06 3.96E-06 9.89E-07 9.89E-07 6.85E-05 1.71E-05 1.71E-05 1.93E-05 1.93E-05Acenaphthylene (1) 1.62E-05 4.05E-06 4.05E-06 1.41E-05 3.53E-06 3.53E-06 1.35E-04 3.38E-05 3.38E-05 4.14E-05 4.14E-05Acetaldehyde 3.48E-02 1.52E-01 1.52E-01 2.95E-02 1.29E-01 1.29E-01 1.43E-01 6.28E-01 6.28E-01 2.20E-01 9.65E-01 9.65E-01 2.45E-03 6.14E-04 6.14E-04 2.14E-03 5.34E-04 5.34E-04 3.69E-04 9.23E-05 9.23E-05 1.88E+00 1.88E+00Acetophenone 9.16E-04 4.01E-03 4.01E-03 7.76E-04 3.40E-03 3.40E-03 3.77E-03 1.65E-02 1.65E-02 5.80E-03 2.54E-02 2.54E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 4.93E-02 4.93E-02Acrolein 1.77E-02 7.76E-02 7.76E-02 1.50E-02 6.57E-02 6.57E-02 7.29E-02 3.19E-01 3.19E-01 1.12E-01 4.91E-01 4.91E-01 2.96E-04 7.40E-05 7.40E-05 2.58E-04 6.45E-05 6.45E-05 1.15E-04 2.88E-05 2.88E-05 9.54E-01 9.54E-01Anthracene (1) 5.98E-06 1.50E-06 1.50E-06 5.21E-06 1.30E-06 1.30E-06 1.80E-05 4.50E-06 4.50E-06 7.30E-06 7.30E-06Antimony 1.10E-03 4.82E-03 4.82E-03 9.31E-04 4.08E-03 4.08E-03 4.53E-03 1.98E-02 1.98E-02 6.95E-03 3.05E-02 3.05E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 5.92E-02 5.92E-02Arsenic 2.50E-02 1.10E-01 1.10E-01 2.12E-02 9.29E-02 9.29E-02 1.03E-01 4.52E-01 4.52E-01 1.58E-01 6.94E-01 6.94E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.35E+00 1.35E+00Benzene 7.94E-02 3.48E-01 3.48E-01 6.72E-02 2.94E-01 2.94E-01 3.27E-01 1.43E+00 1.43E+00 5.02E-01 2.20E+00 2.20E+00 2.99E-03 7.46E-04 7.46E-04 2.60E-03 6.50E-04 6.50E-04 1.14E-02 2.84E-03 2.84E-03 4.28E+00 4.28E+00Benzo(a)anthracene (1) 5.38E-06 1.34E-06 1.34E-06 4.68E-06 1.17E-06 1.17E-06 9.11E-06 2.28E-06 2.28E-06 4.79E-06 4.79E-06Benzo(a)pyrene (1) 6.02E-07 1.50E-07 1.50E-07 5.24E-07 1.31E-07 1.31E-07 3.76E-06 9.41E-07 9.41E-07 1.22E-06 1.22E-06Benzo(b)fluoranthene (1) 3.17E-07 7.93E-08 7.93E-08 2.76E-07 6.91E-08 6.91E-08 1.63E-05 4.06E-06 4.06E-06 4.21E-06 4.21E-06Benzo(g,h,i)perylene (1) 1.56E-06 3.91E-07 3.91E-07 1.36E-06 3.41E-07 3.41E-07 8.14E-06 2.04E-06 2.04E-06 2.77E-06 2.77E-06Benzo(k)fluoranthene (1) 4.96E-07 1.24E-07 1.24E-07 4.32E-07 1.08E-07 1.08E-07 3.19E-06 7.98E-07 7.98E-07 1.03E-06 1.03E-06Benzyl chloride 4.28E-02 1.87E-01 1.87E-01 3.62E-02 1.59E-01 1.59E-01 1.76E-01 7.71E-01 7.71E-01 2.70E-01 1.18E+00 1.18E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 2.30E+00 2.30E+00Beryllium 1.28E-03 5.62E-03 5.62E-03 1.09E-03 4.76E-03 4.76E-03 5.28E-03 2.31E-02 2.31E-02 8.11E-03 3.55E-02 3.55E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 6.90E-02 6.90E-02Biphenyl 2.08E-04 9.10E-04 9.10E-04 1.76E-04 7.70E-04 7.70E-04 8.55E-04 3.74E-03 3.74E-03 1.31E-03 5.75E-03 5.75E-03 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.12E-02 1.12E-02bis(2-Ethylhexyl)phthalate 4.46E-03 1.95E-02 1.95E-02 3.77E-03 1.65E-02 1.65E-02 1.84E-02 8.04E-02 8.04E-02 2.82E-02 1.24E-01 1.24E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 2.40E-01 2.40E-01Bromoform 2.38E-03 1.04E-02 1.04E-02 2.02E-03 8.83E-03 8.83E-03 9.81E-03 4.29E-02 4.29E-02 1.51E-02 6.60E-02 6.60E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.28E-01 1.28E-01Cadmium 3.12E-03 1.36E-02 1.36E-02 2.64E-03 1.15E-02 1.15E-02 1.28E-02 5.62E-02 5.62E-02 1.97E-02 8.63E-02 8.63E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.68E-01 1.68E-01Carbon disulfide 7.94E-03 3.48E-02 3.48E-02 6.72E-03 2.94E-02 2.94E-02 3.27E-02 1.43E-01 1.43E-01 5.02E-02 2.20E-01 2.20E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 4.27E-01 4.27E-01Chlorobenzene 1.34E-03 5.89E-03 5.89E-03 1.14E-03 4.98E-03 4.98E-03 5.53E-03 2.42E-02 2.42E-02 8.50E-03 3.72E-02 3.72E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 7.23E-02 7.23E-02Chloroform 3.60E-03 1.58E-02 1.58E-02 3.05E-03 1.34E-02 1.34E-02 1.48E-02 6.50E-02 6.50E-02 2.28E-02 9.98E-02 9.98E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.94E-01 1.94E-01Chromium 1.59E-02 6.96E-02 6.96E-02 1.34E-02 5.89E-02 5.89E-02 6.54E-02 2.86E-01 2.86E-01 1.00E-01 4.40E-01 4.40E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 8.55E-01 8.55E-01Chrysene (1) 1.13E-06 2.82E-07 2.82E-07 9.84E-07 2.46E-07 2.46E-07 2.24E-05 5.60E-06 5.60E-06 6.13E-06 6.13E-06Cobalt 6.11E-03 2.68E-02 2.68E-02 5.17E-03 2.26E-02 2.26E-02 2.51E-02 1.10E-01 1.10E-01 3.86E-02 1.69E-01 1.69E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 3.29E-01 3.29E-01Cumene 3.24E-04 1.42E-03 1.42E-03 2.74E-04 1.20E-03 1.20E-03 1.33E-03 5.84E-03 5.84E-03 2.05E-03 8.97E-03 8.97E-03 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.74E-02 1.74E-02Cyanide Compounds (Cyanide) 1.53E-01 6.69E-01 6.69E-01 1.29E-01 5.66E-01 5.66E-01 6.29E-01 2.75E+00 2.75E+00 9.66E-01 4.23E+00 4.23E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 8.22E+00 8.22E+00Dibenz(a,h)anthracene (1) 1.87E-06 4.66E-07 4.66E-07 1.62E-06 4.06E-07 4.06E-07 5.07E-06 1.27E-06 1.27E-06 2.14E-06 2.14E-06Dichlorobenzene 1.69E-04 7.42E-04 7.42E-04 1.69E-04 7.42E-04 7.42E-04 5.65E-04 2.47E-03 2.47E-03 9.13E-04 4.00E-03 4.00E-03 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 7.96E-03 7.96E-03Dimethyl sulfate 2.93E-03 1.28E-02 1.28E-02 2.48E-03 1.09E-02 1.09E-02 1.21E-02 5.29E-02 5.29E-02 1.85E-02 8.12E-02 8.12E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.58E-01 1.58E-01Ethyl chloride 2.57E-03 1.12E-02 1.12E-02 2.17E-03 9.51E-03 9.51E-03 1.06E-02 4.63E-02 4.63E-02 1.62E-02 7.11E-02 7.11E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.38E-01 1.38E-01Ethylbenzene 5.74E-03 2.51E-02 2.51E-02 4.86E-03 2.13E-02 2.13E-02 2.36E-02 1.04E-01 1.04E-01 3.63E-02 1.59E-01 1.59E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 3.09E-01 3.09E-01Ethylene dibromide 7.33E-05 3.21E-04 3.21E-04 6.20E-05 2.72E-04 2.72E-04 3.02E-04 1.32E-03 1.32E-03 4.64E-04 2.03E-03 2.03E-03 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 3.94E-03 3.94E-03Ethylene dichloride 2.44E-03 1.07E-02 1.07E-02 2.07E-03 9.06E-03 9.06E-03 1.01E-02 4.40E-02 4.40E-02 1.55E-02 6.77E-02 6.77E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.31E-01 1.31E-01Fluoranthene (1) 2.44E-05 6.09E-06 6.09E-06 2.12E-05 5.30E-06 5.30E-06 5.90E-05 1.48E-05 1.48E-05 2.61E-05 2.61E-05Fluorene (1) 9.34E-05 2.34E-05 2.34E-05 8.14E-05 2.03E-05 2.03E-05 1.87E-04 4.69E-05 4.69E-05 9.06E-05 9.06E-05Formaldehyde 1.47E-02 6.42E-02 6.42E-02 1.24E-02 5.44E-02 5.44E-02 6.03E-02 2.64E-01 2.64E-01 9.27E-02 4.06E-01 4.06E-01 3.78E-03 9.44E-04 9.44E-04 3.29E-03 8.22E-04 8.22E-04 1.16E-03 2.89E-04 2.89E-04 7.91E-01 7.91E-01Hexane 4.09E-03 1.79E-02 1.79E-02 3.46E-03 1.52E-02 1.52E-02 1.68E-02 7.38E-02 7.38E-02 2.59E-02 1.13E-01 1.13E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 2.20E-01 2.20E-01Hydrogen Chloride 2.15E+00 3.21E+02 9.42E+00 1.82E+00 2.72E+02 7.97E+00 8.85E+00 1.32E+03 3.88E+01 1.36E+01 2.03E+03 5.96E+01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 3.94E+03 1.16E+02Hydrogen Fluoride 9.16E+00 4.01E+01 4.01E+01 7.76E+00 3.40E+01 3.40E+01 1.32E+01 1.65E+02 5.78E+01 5.80E+00 2.54E+02 2.54E+01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 4.93E+02 1.57E+02Indeno(1,2,3-cd)pyrene (1) 1.20E-06 3.00E-07 3.00E-07 1.05E-06 2.61E-07 2.61E-07 6.06E-06 1.52E-06 1.52E-06 2.08E-06 2.08E-06Isophorone 3.54E-02 1.55E-01 1.55E-01 3.00E-02 1.31E-01 1.31E-01 1.46E-01 6.39E-01 6.39E-01 2.24E-01 9.82E-01 9.82E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.91E+00 1.91E+00Lead 3.66E-01 1.61E+00 1.61E+00 3.10E-01 1.36E+00 1.36E+00 1.77E-01 6.61E+00 7.75E-01 2.79E-02 1.79E+02 1.22E-01 2.88E-05 7.20E-06 7.20E-06 2.51E-05 6.27E-06 6.27E-06 1.32E-04 3.29E-05 3.29E-05 4.67E-05 2.99E-03 6.30E-05 6.38E-04 3.25E-03 2.53E-03 1.88E+02 3.86E+00Manganese 2.99E-02 1.31E-01 1.31E-01 2.53E-02 1.11E-01 1.11E-01 1.23E-01 5.40E-01 5.40E-01 1.89E-01 8.29E-01 8.29E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.61E+00 1.61E+00Mercury 5.07E-03 2.22E-02 2.22E-02 4.29E-03 1.88E-02 1.88E-02 2.09E-03 9.14E-02 9.14E-03 3.21E-03 1.40E-01 1.40E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 2.73E-01 6.42E-02Methyl bromide 9.77E-03 4.28E-02 4.28E-02 8.27E-03 3.62E-02 3.62E-02 4.02E-02 1.76E-01 1.76E-01 6.18E-02 2.71E-01 2.71E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 5.26E-01 5.26E-01Methyl chloride 3.24E-02 1.42E-01 1.42E-01 2.74E-02 1.20E-01 1.20E-01 1.33E-01 5.84E-01 5.84E-01 2.05E-01 8.97E-01 8.97E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.74E+00 1.74E+00Methyl ethyl ketone 2.38E-02 1.04E-01 1.04E-01 2.02E-02 8.83E-02 8.83E-02 9.81E-02 4.29E-01 4.29E-01 1.51E-01 6.60E-01 6.60E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.28E+00 1.28E+00Methyl hydrazine 1.04E-02 4.55E-02 4.55E-02 8.79E-03 3.85E-02 3.85E-02 4.27E-02 1.87E-01 1.87E-01 6.57E-02 2.88E-01 2.88E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 5.59E-01 5.59E-01Methyl methacrylate 1.22E-03 5.35E-03 5.35E-03 1.03E-03 4.53E-03 4.53E-03 5.03E-03 2.20E-02 2.20E-02 7.73E-03 3.38E-02 3.38E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 6.57E-02 6.57E-02Methyl tert butyl ether 2.14E-03 9.36E-03 9.36E-03 1.81E-03 7.93E-03 7.93E-03 8.80E-03 3.85E-02 3.85E-02 1.35E-02 5.92E-02 5.92E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.15E-01 1.15E-01Methylene chloride 1.77E-02 7.76E-02 7.76E-02 1.50E-02 6.57E-02 6.57E-02 7.29E-02 3.19E-01 3.19E-01 1.12E-01 4.91E-01 4.91E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 9.53E-01 9.53E-01Naphthalene (1) 2.71E-04 6.78E-05 6.78E-05 2.36E-04 5.91E-05 5.91E-05 1.90E-03 4.76E-04 4.76E-04 6.03E-04 6.03E-04Nickel 1.71E-02 7.49E-02 7.49E-02 1.45E-02 6.34E-02 6.34E-02 7.04E-02 3.08E-01 3.08E-01 1.08E-01 4.74E-01 4.74E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 9.20E-01 9.20E-01Phenanthrene (1) 9.41E-05 2.35E-05 2.35E-05 8.19E-05 2.05E-05 2.05E-05 5.97E-04 1.49E-04 1.49E-04 1.93E-04 1.93E-04Phenol 9.77E-04 4.28E-03 4.28E-03 8.27E-04 3.62E-03 3.62E-03 4.02E-03 1.76E-02 1.76E-02 6.18E-03 2.71E-02 2.71E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 5.26E-02 5.26E-02Propionaldehyde 2.32E-02 1.02E-01 1.02E-01 1.96E-02 8.61E-02 8.61E-02 9.55E-02 4.18E-01 4.18E-01 1.47E-01 6.43E-01 6.43E-01 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.25E+00 1.25E+00Pyrene (1) 1.53E-05 3.82E-06 3.82E-06 1.33E-05 3.33E-06 3.33E-06 5.43E-05 1.36E-05 1.36E-05 2.07E-05 2.07E-05Selenium 7.94E-02 3.48E-01 3.48E-01 6.72E-02 2.94E-01 2.94E-01 3.27E-01 1.43E+00 1.43E+00 5.02E-01 2.20E+00 2.20E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 4.27E+00 4.27E+00Styrene 1.53E-03 6.69E-03 6.69E-03 1.29E-03 5.66E-03 5.66E-03 6.29E-03 2.75E-02 2.75E-02 9.66E-03 4.23E-02 4.23E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 8.22E-02 8.22E-02Tetrachloroethylene 2.63E-03 1.15E-02 1.15E-02 2.22E-03 9.74E-03 9.74E-03 1.08E-02 4.74E-02 4.74E-02 1.66E-02 7.28E-02 7.28E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 1.41E-01 1.41E-01Toluene 1.47E-02 6.42E-02 6.42E-02 1.24E-02 5.44E-02 5.44E-02 6.03E-02 2.64E-01 2.64E-01 9.27E-02 4.06E-01 4.06E-01 1.31E-03 3.27E-04 3.27E-04 1.14E-03 2.85E-04 2.85E-04 4.11E-03 1.03E-03 1.03E-03 7.91E-01 7.91E-01Vinyl acetate 4.64E-04 2.03E-03 2.03E-03 3.93E-04 1.72E-03 1.72E-03 1.91E-03 8.37E-03 8.37E-03 2.94E-03 1.29E-02 1.29E-02 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 2.50E-02 2.50E-02Xylenes 2.26E-03 9.90E-03 9.90E-03 1.91E-03 8.38E-03 8.38E-03 9.30E-03 4.07E-02 4.07E-02 1.43E-02 6.26E-02 6.26E-02 9.12E-04 2.28E-04 2.28E-04 7.94E-04 1.99E-04 1.99E-04 2.83E-03 7.07E-04 7.07E-04 1.23E-01 1.23E-012,3,7,8-TCDD (2) 8.73E-10 3.83E-09 3.83E-09 7.39E-10 3.24E-09 3.24E-09 3.60E-09 1.57E-08 1.57E-08 5.53E-09 2.42E-08 2.42E-08 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 4.70E-08 4.70E-08Total PAH (1) 0.00E+00 0.00E+00POM 2.24E-03 9.79E-03 9.79E-03 1.89E-03 8.29E-03 8.29E-03 1.06E-02 4.65E-02 4.65E-02 1.63E-02 7.15E-02 7.15E-02 1.36E-01 1.36E-01Total HAP 12.43 366.04 54.43 10.52 309.86 46.07 25.29 1506.74 110.76 24.13 2484.00 105.67 0.01 0.00 0.00 0.01 0.00 0.00 0.02 0.01 0.01 0.00 0.00 0.00 0.00 0.00 0.00 4666.66 316.94

Notes:(1) For boiler combustion purposes, all compounds footnoted with (1) are compound subsets of POM. To avoid double counting these boiler compound emissions are removed as POM accounts for all of these individual compounds.

(2) Only 2,3,7,8-TCDD is a listed HAP. Other dioxin compounds are calculated at the individual boilers but not included for estimating total HAP emissions.

Total Uncontrolled

PTE (tpy)

Total Controlled PTE (tpy)HAP

Boiler 1 Boiler 2 Boiler 3 Boiler 4 Emergency Generator 3-APCE Emergency Generator 3-250kw Unit 4 Emergency Generator Material Handling Sources Fugitive Sources

H:\MP BEC\draft documents\Public Notice Documents w_App & Attach\TSD Attachments Public Notice\TSD Att 1 - MPCA Calculations.xlsxBoiler 1

Date Printed: 8/15/2018Page 48 of 102

Minnesota PowerBoswell Permit Renewal ApplicationPotential to Emit Calculations - Boiler 1Update:

SV EU

Maximum Rated Capacity

(MMBtu/hr)Data

Source Fuel Pollutant Source lb/hr tons/yearControl

Efficiency Source lb/hr tons/year Source lb/hr tons/yearSV 003 EU 001 1075 [01] Coal 61.08 Tons/hour CO 5.00E-01 lb/ton [01] 30.54 133.76 0.0% [01] 30.54 133.76 30.54 133.76SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Lead 6.00E-03 lb/ton [01] 0.37 1.61 0.0% [01] 0.37 1.61 0.37 1.61SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour NOx 1.20E+01 lb/ton [01] 732.95 3,210.34 70.7% [01] 215.00 941.70 0.200 lb/mmbtu [27] 215.00 941.70SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour PM 7.03E+01 lb/ton [01] 4,293.89 18,807.25 99.6% [01] 16.13 70.63 0.015 lb/mmbtu [27] 16.13 70.63SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour PM10 1.62E+01 lb/ton [01] 989.43 4,333.69 95.9% [01] 40.31 176.57 0.038 lb/mmbtu 40.31 176.57SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour PM2.5 4.25E+00 lb/ton [01] 259.47 1,136.46 84.5% [01] 40.31 176.57 0.038 lb/mmbtu 40.31 176.57SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour SO2 2.10E+01 lb/ton [01] 1,282.67 5,618.10 41.3% [01] 752.50 3,295.95 0.700 lb/mmbtu [27] 752.50 3,295.95SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Sulfuric Acid Mist 6.11E-02 lb/ton [01] 3.73 16.35 96.4% [01] 0.13 0.59 2.20E-03 lb/ton 0.13 0.59SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour VOC 6.00E-02 lb/ton [01] 3.66 16.05 0.0% [01] 3.66 16.05 3.66 16.05SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour CO2 3.70E+03 lb/ton [01] 225,748.93 988,780.29 0.0% [01] 225,749 988,780 225,749 988,780SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour CH4 4.18E-01 lb/ton [01] 25.56 111.93 0.0% [01] 25.56 111.93 25.56 111.93SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour N2O 6.09E-02 lb/ton [01] 3.72 16.28 0.0% [01] 3.72 16.28 3.72 16.28SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour CO2-e 3.72E+03 lb/ton [01] 227,495.54 996,430.44 0.0% [01] 227,496 996,430 227,496 996,430SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Acetaldehyde 5.70E-04 lb/ton [01] 3.48E-02 1.52E-01 unknown [01] 3.48E-02 1.52E-01 3.48E-02 1.52E-01SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Acetophenone 1.50E-05 lb/ton [01] 9.16E-04 4.01E-03 unknown [01] 9.16E-04 4.01E-03 9.16E-04 4.01E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Acrolein 2.90E-04 lb/ton [01] 1.77E-02 7.76E-02 unknown [01] 1.77E-02 7.76E-02 1.77E-02 7.76E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Antimony 1.80E-05 lb/ton [01] 1.10E-03 4.82E-03 unknown [01] 1.10E-03 4.82E-03 1.10E-03 4.82E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Arsenic 4.10E-04 lb/ton [01] 2.50E-02 1.10E-01 unknown [01] 2.50E-02 1.10E-01 2.50E-02 1.10E-01SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Benzene 1.30E-03 lb/ton [01] 7.94E-02 3.48E-01 unknown [01] 7.94E-02 3.48E-01 7.94E-02 3.48E-01SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Benzyl chloride 7.00E-04 lb/ton [01] 4.28E-02 1.87E-01 unknown [01] 4.28E-02 1.87E-01 4.28E-02 1.87E-01SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Beryllium 2.10E-05 lb/ton [01] 1.28E-03 5.62E-03 unknown [01] 1.28E-03 5.62E-03 1.28E-03 5.62E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Biphenyl 1.70E-06 lb/ton [01] 1.04E-04 4.55E-04 unknown [01] 1.04E-04 4.55E-04 1.04E-04 4.55E-04SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour bis(2-Ethylhexyl)phthalate 7.30E-05 lb/ton [01] 4.46E-03 1.95E-02 unknown [01] 4.46E-03 1.95E-02 4.46E-03 1.95E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Bromoform 3.90E-05 lb/ton [01] 2.38E-03 1.04E-02 unknown [01] 2.38E-03 1.04E-02 2.38E-03 1.04E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Cadmium 5.10E-05 lb/ton [01] 3.12E-03 1.36E-02 unknown [01] 3.12E-03 1.36E-02 3.12E-03 1.36E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Carbon disulfide 1.30E-04 lb/ton [01] 7.94E-03 3.48E-02 unknown [01] 7.94E-03 3.48E-02 7.94E-03 3.48E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour 2-Chloroacetophenone 7.00E-06 lb/ton [01] 4.28E-04 1.87E-03 unknown [01] 4.28E-04 1.87E-03 4.28E-04 1.87E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Chlorobenzene 2.20E-05 lb/ton [01] 1.34E-03 5.89E-03 unknown [01] 1.34E-03 5.89E-03 1.34E-03 5.89E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Chloroform 5.90E-05 lb/ton [01] 3.60E-03 1.58E-02 unknown [01] 3.60E-03 1.58E-02 3.60E-03 1.58E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Chromium 2.60E-04 lb/ton [01] 1.59E-02 6.96E-02 unknown [01] 1.59E-02 6.96E-02 1.59E-02 6.96E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Cobalt 1.00E-04 lb/ton [01] 6.11E-03 2.68E-02 unknown [01] 6.11E-03 2.68E-02 6.11E-03 2.68E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Cumene 5.30E-06 lb/ton [01] 3.24E-04 1.42E-03 unknown [01] 3.24E-04 1.42E-03 3.24E-04 1.42E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Cyanide Compounds (Cyanide 2.50E-03 lb/ton [01] 1.53E-01 6.69E-01 unknown [01] 1.53E-01 6.69E-01 1.53E-01 6.69E-01SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour 2,4-Dinitrotoluene 2.80E-07 lb/ton [01] 1.71E-05 7.49E-05 unknown [01] 1.71E-05 7.49E-05 1.71E-05 7.49E-05SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Dimethyl sulfate 4.80E-05 lb/ton [01] 2.93E-03 1.28E-02 unknown [01] 2.93E-03 1.28E-02 2.93E-03 1.28E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Ethylbenzene 9.40E-05 lb/ton [01] 5.74E-03 2.51E-02 unknown [01] 5.74E-03 2.51E-02 5.74E-03 2.51E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Ethyl chloride 4.20E-05 lb/ton [01] 2.57E-03 1.12E-02 unknown [01] 2.57E-03 1.12E-02 2.57E-03 1.12E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Ethylene dibromide 1.20E-06 lb/ton [01] 7.33E-05 3.21E-04 unknown [01] 7.33E-05 3.21E-04 7.33E-05 3.21E-04SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Ethylene dichloride 4.00E-05 lb/ton [01] 2.44E-03 1.07E-02 unknown [01] 2.44E-03 1.07E-02 2.44E-03 1.07E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Formaldehyde 2.40E-04 lb/ton [01] 1.47E-02 6.42E-02 unknown [01] 1.47E-02 6.42E-02 1.47E-02 6.42E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Hexane 6.70E-05 lb/ton [01] 4.09E-03 1.79E-02 unknown [01] 4.09E-03 1.79E-02 4.09E-03 1.79E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Isophorone 5.80E-04 lb/ton [01] 3.54E-02 1.55E-01 unknown [01] 3.54E-02 1.55E-01 3.54E-02 1.55E-01

61.08 Tons/hour Hydrogen Fluoride 1.50E-01 lb/ton [01] 9.16E+00 4.01E+01 unknown [01] 9.16E+00 4.01E+01 9.16E+00 4.01E+01SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Hydrogen Chloride 1.20E+00 lb/ton [01] 7.33E+01 3.21E+02 97.1% [01] 2.15E+00 9.42E+00 2.0E-03 lb/mmbtu [01] 2.15E+00 9.42E+00SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Manganese 4.90E-04 lb/ton [01] 2.99E-02 1.31E-01 unknown [01] 2.99E-02 1.31E-01 2.99E-02 1.31E-01SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Mercury 8.30E-05 lb/ton [01] 5.07E-03 2.22E-02 unknown [01] 5.07E-03 2.22E-02 1.2E-06 lb/mmbtu (30-d [01] 1.29E-03 5.65E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Methyl bromide 1.60E-04 lb/ton [01] 9.77E-03 4.28E-02 unknown [01] 9.77E-03 4.28E-02 9.77E-03 4.28E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Methyl chloride 5.30E-04 lb/ton [01] 3.24E-02 1.42E-01 unknown [01] 3.24E-02 1.42E-01 3.24E-02 1.42E-01SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Methyl ethyl ketone 3.90E-04 lb/ton [01] 2.38E-02 1.04E-01 unknown [01] 2.38E-02 1.04E-01 2.38E-02 1.04E-01SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Methyl hydrazine 1.70E-04 lb/ton [01] 1.04E-02 4.55E-02 unknown [01] 1.04E-02 4.55E-02 1.04E-02 4.55E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Methyl methacrylate 2.00E-05 lb/ton [01] 1.22E-03 5.35E-03 unknown [01] 1.22E-03 5.35E-03 1.22E-03 5.35E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Methyl tert butyl ether 3.50E-05 lb/ton [01] 2.14E-03 9.36E-03 unknown [01] 2.14E-03 9.36E-03 2.14E-03 9.36E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Methylene chloride 2.90E-04 lb/ton [01] 1.77E-02 7.76E-02 unknown [01] 1.77E-02 7.76E-02 1.77E-02 7.76E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Naphthalene 1.30E-05 lb/ton [01] 7.94E-04 3.48E-03 unknown [01] 7.94E-04 3.48E-03 7.94E-04 3.48E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Nickel 2.80E-04 lb/ton [01] 1.71E-02 7.49E-02 unknown [01] 1.71E-02 7.49E-02 1.71E-02 7.49E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Phenol 1.60E-05 lb/ton [01] 9.77E-04 4.28E-03 unknown [01] 9.77E-04 4.28E-03 9.77E-04 4.28E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Propionaldehyde 3.80E-04 lb/ton [01] 2.32E-02 1.02E-01 unknown [01] 2.32E-02 1.02E-01 2.32E-02 1.02E-01SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Selenium 1.30E-03 lb/ton [01] 7.94E-02 3.48E-01 unknown [01] 7.94E-02 3.48E-01 7.94E-02 3.48E-01SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Styrene 2.50E-05 lb/ton [01] 1.53E-03 6.69E-03 unknown [01] 1.53E-03 6.69E-03 1.53E-03 6.69E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Tetrachloroethylene 4.30E-05 lb/ton [01] 2.63E-03 1.15E-02 unknown [01] 2.63E-03 1.15E-02 2.63E-03 1.15E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour 1,1,1 - trichloroethane 2.00E-05 lb/ton [01] 1.22E-03 5.35E-03 unknown [01] 1.22E-03 5.35E-03 1.22E-03 5.35E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Toluene 2.40E-04 lb/ton [01] 1.47E-02 6.42E-02 unknown [01] 1.47E-02 6.42E-02 1.47E-02 6.42E-02SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Xylenes 3.70E-05 lb/ton [01] 2.26E-03 9.90E-03 unknown [01] 2.26E-03 9.90E-03 2.26E-03 9.90E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Vinyl acetate 7.60E-06 lb/ton [01] 4.64E-04 2.03E-03 unknown [01] 4.64E-04 2.03E-03 4.64E-04 2.03E-03SV 003 EU 001 1075 [01] Coal 61.08 Tons/hour Total PCDD/PCDF 1.76E-09 lbs/ton [28] 1.08E-07 4.71E-07 Unknown [28] 1.08E-07 4.71E-07SV 003 EU 001 1075 SV 001 Coal 61.08 Tons/hour 2,3,7,8-TCDD 1.43E-11 lbs/ton [28] 8.73E-10 3.83E-09 Unknown [28] 8.73E-10 3.83E-09

Fuel Usage Emission Factor Emission Limit

Limited EmissionsEmission Factor Uncontrolled Emissions Controls Controlled Emissions

6/9/2017

Fuel Information



SV EU


(MMBtu/hr)Data


Efficiency Source lb/hr tons/year Source lb/hr tons/yearFuel Usage Emission Factor Emission Limit

Limited EmissionsEmission Factor Uncontrolled Emissions Controls Controlled EmissionsFuel Information

SV 003 EU 001 1075 SV 001 Coal 61.08 Tons/hour Total TCDD 9.28E-11 lbs/ton [28] 5.67E-09 2.48E-08 Unknown [28] 5.67E-09 2.48E-08SV 003 EU 001 1075 SV 001 Coal 61.08 Tons/hour Total PeCDD 4.47E-11 lbs/ton [28] 2.73E-09 1.20E-08 Unknown [28] 2.73E-09 1.20E-08SV 003 EU 001 1075 SV 001 Coal 61.08 Tons/hour Total HxCDD 2.87E-11 lbs/ton [28] 1.75E-09 7.68E-09 Unknown [28] 1.75E-09 7.68E-09SV 003 EU 001 1075 SV 001 Coal 61.08 Tons/hour Total HpCDD 8.34E-11 lbs/ton [28] 5.09E-09 2.23E-08 Unknown [28] 5.09E-09 2.23E-08SV 003 EU 001 1075 SV 001 Coal 61.08 Tons/hour Total OCDD 4.16E-10 lbs/ton [28] 2.54E-08 1.11E-07 Unknown [28] 2.54E-08 1.11E-07SV 003 EU 001 1075 SV 001 Coal 61.08 Tons/hour Total PCDD 6.66E-10 lbs/ton [28] 4.07E-08 1.78E-07 Unknown [28] 4.07E-08 1.78E-07SV 003 EU 001 1075 SV 001 Coal 61.08 Tons/hour 2,3,7,8-TCDF 5.10E-11 lbs/ton [28] 3.12E-09 1.36E-08 Unknown [28] 3.12E-09 1.36E-08SV 003 EU 001 1075 SV 001 Coal 61.08 Tons/hour Total TCDF 4.04E-10 lbs/ton [28] 2.47E-08 1.08E-07 Unknown [28] 2.47E-08 1.08E-07SV 003 EU 001 1075 SV 001 Coal 61.08 Tons/hour Total PeCDF 3.53E-10 lbs/ton [28] 2.16E-08 9.44E-08 Unknown [28] 2.16E-08 9.44E-08SV 003 EU 001 1075 SV 001 Coal 61.08 Tons/hour Total HxCDF 1.92E-10 lbs/ton [28] 1.17E-08 5.14E-08 Unknown [28] 1.17E-08 5.14E-08SV 003 EU 001 1075 SV 001 Coal 61.08 Tons/hour Total HpCDF 7.68E-11 lbs/ton [28] 4.69E-09 2.05E-08 Unknown [28] 4.69E-09 2.05E-08SV 003 EU 001 1075 SV 001 Coal 61.08 Tons/hour Total OCDF 6.63E-11 lbs/ton [28] 4.05E-09 1.77E-08 Unknown [28] 4.05E-09 1.77E-08SV 003 EU 001 1075 SV 001 Coal 61.08 Tons/hour Total PCDF 1.09E-09 lbs/ton [28] 6.66E-08 2.92E-07 Unknown [28] 6.66E-08 2.92E-07SV 003 EU 001 1075 [01] Coal 61.08 Tons/hour Total PAH 2.08E-05 lbs/ton [29] 1.27E-03 5.55E-03 Unknown [29] 1.27E-03 5.55E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Biphenyl 1.70E-06 lbs/ton [29] 1.04E-04 4.55E-04 Unknown [29] 1.04E-04 4.55E-04SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Acenaphthene 5.10E-07 lbs/ton [29] 3.12E-05 1.36E-04 Unknown [29] 3.12E-05 1.36E-04SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Acenaphthylene 2.50E-07 lbs/ton [29] 1.53E-05 6.69E-05 Unknown [29] 1.53E-05 6.69E-05SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Anthracene 2.10E-07 lbs/ton [29] 1.28E-05 5.62E-05 Unknown [29] 1.28E-05 5.62E-05SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Benzo(a)anthracene 8.00E-08 lbs/ton [29] 4.89E-06 2.14E-05 Unknown [29] 4.89E-06 2.14E-05SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Benzo(a)pyrene 3.80E-08 lbs/ton [29] 2.32E-06 1.02E-05 Unknown [29] 2.32E-06 1.02E-05SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Benzo(b,j,k)fluoranthene 1.10E-07 lbs/ton [29] 6.72E-06 2.94E-05 Unknown [29] 6.72E-06 2.94E-05SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Benzo(g,h,i)perylene 2.70E-08 lbs/ton [29] 1.65E-06 7.22E-06 Unknown [29] 1.65E-06 7.22E-06SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Chrysene 1.00E-07 lbs/ton [29] 6.11E-06 2.68E-05 Unknown [29] 6.11E-06 2.68E-05SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Fluoranthene 7.10E-07 lbs/ton [29] 4.34E-05 1.90E-04 Unknown [29] 4.34E-05 1.90E-04SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Fluorene 9.10E-07 lbs/ton [29] 5.56E-05 2.43E-04 Unknown [29] 5.56E-05 2.43E-04SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Indeno(1,2,3-cd)pyrene 6.10E-08 lbs/ton [29] 3.73E-06 1.63E-05 Unknown [29] 3.73E-06 1.63E-05SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Naphthalene 1.30E-05 lbs/ton [29] 7.94E-04 3.48E-03 Unknown [29] 7.94E-04 3.48E-03SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Phenanthrene 2.70E-06 lbs/ton [29] 1.65E-04 7.22E-04 Unknown [29] 1.65E-04 7.22E-04SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour Pyrene 3.30E-07 lbs/ton [29] 2.02E-05 8.83E-05 Unknown [29] 2.02E-05 8.83E-05SV 003 SV 001 SV 1075 SV 001 Coal 61.08 Tons/hour 5-Methyl chrysene 2.20E-08 lbs/ton [29] 1.34E-06 5.89E-06 Unknown [29] 1.34E-06 5.89E-06

SV 003 EU 001 1075 [01] Coal 61.08 Tons/hour POM 2.08 lb/1012 Btu [30] 2.24E-03 9.79E-03 Unknown [30] 2.24E-03 9.79E-03SV 003 EU 001 144 [01] Natural Gas, Startup 0.14 MMscf/hr CO 8.40E+01 lb/MMscf [02] 11.86 51.94 0.0% [02] 11.86 51.94 11.86 51.94SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Lead 5.00E-04 lb/MMscf [02] 0.00 0.00 0.0% [02] 0.00 0.00 0.00 0.00SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr NOx 1.75E+02 lb/MMscf [02] 24.76 108.46 0.0% [02] 24.76 108.46 24.76 108.46SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr PM 2.00E-01 lb/MMscf [02] 0.03 0.12 0.0% [02] 0.03 0.12 0.03 0.12SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr PM10 5.20E-01 lb/MMscf [02] 0.07 0.32 0.0% [02] 0.07 0.32 0.07 0.32SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr PM2.5 5.20E-01 lb/MMscf [02] 0.07 0.32 0.0% [02] 0.07 0.32 0.07 0.32SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr SO2 6.000E-01 lb/MMscf [02] 0.08 0.37 0.0% [02] 0.08 0.37 0.08 0.37SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr VOC 5.50E+00 lb/MMscf [02] 0.78 3.40 0.0% [02] 0.78 3.40 0.78 3.40SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr CO2 1.20E+05 lb/MMscf [02] 16,946.71 74,226.61 0.0% [02] 16,946.71 74,226.61 16,946.71 74,226.61SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr CH4 2.26E+00 lb/MMscf [02] 0.32 1.40 0.0% [02] 0.32 1.40 0.32 1.40SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr N2O 2.26E-01 lb/MMscf [02] 0.03 0.14 0.0% [02] 0.03 0.14 0.03 0.14SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr CO2-e 1.20E+05 lb/MMscf [02] 16,964.22 74,303.27 0.0% [02] 16,964.22 74,303.27 16,964.22 74,303.27SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr 2-Methylnaphthalene 2.40E-05 lb/MMscf [02] 3.39E-06 1.48E-05 0.0% [02] 3.39E-06 1.48E-05 3.39E-06 1.48E-05SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr 3-Methylchloranthrene 1.80E-06 lb/MMscf [02] 2.54E-07 1.11E-06 0.0% [02] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr 7,12-Dimethylbenz(a)anthrace 1.60E-05 lb/MMscf [02] 2.26E-06 9.89E-06 0.0% [02] 2.26E-06 9.89E-06 2.26E-06 9.89E-06SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Acenaphthene 1.80E-06 lb/MMscf [02] 2.54E-07 1.11E-06 0.0% [02] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Acenaphthylene 1.80E-06 lb/MMscf [02] 2.54E-07 1.11E-06 0.0% [02] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Anthracene 2.40E-06 lb/MMscf [02] 3.39E-07 1.48E-06 0.0% [02] 3.39E-07 1.48E-06 3.39E-07 1.48E-06SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Arsenic 2.00E-04 lb/MMscf [02] 2.82E-05 1.24E-04 0.0% [02] 2.82E-05 1.24E-04 2.82E-05 1.24E-04SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Benzo(a)anthracene 1.80E-06 lb/MMscf [02] 2.54E-07 1.11E-06 0.0% [02] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Benzene 2.10E-03 lb/MMscf [02] 2.96E-04 1.30E-03 0.0% [02] 2.96E-04 1.30E-03 2.96E-04 1.30E-03SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Benzo(a)pyrene 1.20E-06 lb/MMscf [02] 1.69E-07 7.42E-07 0.0% [02] 1.69E-07 7.42E-07 1.69E-07 7.42E-07SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Benzo(b)fluoranthene 1.80E-06 lb/MMscf [02] 2.54E-07 1.11E-06 0.0% [02] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Benzo(g,h,i)perylene 1.20E-06 lb/MMscf [02] 1.69E-07 7.42E-07 0.0% [02] 1.69E-07 7.42E-07 1.69E-07 7.42E-07SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Benzo(k)fluoranthene 1.80E-06 lb/MMscf [02] 2.54E-07 1.11E-06 0.0% [02] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Beryllium 1.20E-05 lb/MMscf [02] 1.69E-06 7.42E-06 0.0% [02] 1.69E-06 7.42E-06 1.69E-06 7.42E-06SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Cadmium 1.10E-03 lb/MMscf [02] 1.55E-04 6.80E-04 0.0% [02] 1.55E-04 6.80E-04 1.55E-04 6.80E-04SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Chromium 1.40E-03 lb/MMscf [02] 1.98E-04 8.66E-04 0.0% [02] 1.98E-04 8.66E-04 1.98E-04 8.66E-04SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Chrysene 1.80E-06 lb/MMscf [02] 2.54E-07 1.11E-06 0.0% [02] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Cobalt 8.40E-05 lb/MMscf [02] 1.19E-05 5.19E-05 0.0% [02] 1.19E-05 5.19E-05 1.19E-05 5.19E-05SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Dibenz(a,h)anthracene 1.20E-06 lb/MMscf [02] 1.69E-07 7.42E-07 0.0% [02] 1.69E-07 7.42E-07 1.69E-07 7.42E-07SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Dichlorobenzene 1.20E-03 lb/MMscf [02] 1.69E-04 7.42E-04 0.0% [02] 1.69E-04 7.42E-04 1.69E-04 7.42E-04SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Fluoranthene 3.00E-06 lb/MMscf [02] 4.24E-07 1.86E-06 0.0% [02] 4.24E-07 1.86E-06 4.24E-07 1.86E-06SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Fluorene 2.80E-06 lb/MMscf [02] 3.95E-07 1.73E-06 0.0% [02] 3.95E-07 1.73E-06 3.95E-07 1.73E-06SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Formaldehyde 7.50E-02 lb/MMscf [02] 1.06E-02 4.64E-02 0.0% [02] 1.06E-02 4.64E-02 1.06E-02 4.64E-02SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Hexane 1.80E+00 lb/MMscf [02] 2.54E-01 1.11E+00 0.0% [02] 2.54E-01 1.11E+00 2.54E-01 1.11E+00SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Indeno(1,2,3-cd)pyrene 1.80E-06 lb/MMscf [02] 2.54E-07 1.11E-06 0.0% [02] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Manganese 3.80E-04 lb/MMscf [02] 5.36E-05 2.35E-04 0.0% [02] 5.36E-05 2.35E-04 5.36E-05 2.35E-04SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Mercury 2.60E-04 lb/MMscf [02] 3.67E-05 1.61E-04 0.0% [02] 3.67E-05 1.61E-04 3.67E-05 1.61E-04SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Naphthalene 6.10E-04 lb/MMscf [02] 8.61E-05 3.77E-04 0.0% [02] 8.61E-05 3.77E-04 8.61E-05 3.77E-04SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Nickel 2.10E-03 lb/MMscf [02] 2.96E-04 1.30E-03 0.0% [02] 2.96E-04 1.30E-03 2.96E-04 1.30E-03SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Phenanthrene 1.70E-05 lb/MMscf [02] 2.40E-06 1.05E-05 0.0% [02] 2.40E-06 1.05E-05 2.40E-06 1.05E-05



SV EU


(MMBtu/hr)Data




SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Pyrene 5.00E-06 lb/MMscf [02] 7.06E-07 3.09E-06 0.0% [02] 7.06E-07 3.09E-06 7.06E-07 3.09E-06SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Selenium 2.40E-05 lb/MMscf [02] 3.39E-06 1.48E-05 0.0% [02] 3.39E-06 1.48E-05 3.39E-06 1.48E-05SV 003 SV 001 SV 144 SV 001 Natural Gas, Startup 0.14 MMscf/hr Toluene 3.40E-03 lb/MMscf [02] 4.80E-04 2.10E-03 0.0% [02] 4.80E-04 2.10E-03 4.80E-04 2.10E-03SV 003 EU 001 CO 30.54 133.76 0.0% 30.54 133.76 30.54 133.76

SV 003 EU 001 Worst Case Coal = 56.8 tph (1000 MMBtu/hr)

Lead 0.37 1.61 0.0% 0.37 1.61 0.37 1.61


NOx 732.95 3,210.34 70.7% 215.00 941.70 215.00 941.70


PM 4,293.89 18,807.25 99.6% 16.13 70.63 16.13 70.63


PM10 989.43 4,333.69 95.9% 40.31 176.57 40.31 176.57


PM2.5 259.47 1,136.46 84.5% 40.31 176.57 40.31 176.57


SO2 1,282.67 5,618.10 41.3% 752.50 3,295.95 752.50 3,295.95


Sulfuric Acid Mist 3.73 16.35 96.4% 0.13 0.59 0.13 0.59


VOC 3.66 16.05 0.0% 3.66 16.05 3.66 16.05


CO2 225,749 988,780 0.0% 225,749 988,780 225,749 988,780


CH4 25.56 111.93 0.0% 25.56 111.93 25.56 111.93


N2O 3.72 16.28 0.0% 3.72 16.28 3.72 16.28


CO2-e 227,496 996,430 0.0% 227,496 996,430 227,496 996,430


Arsenic 2.50E-02 1.10E-01 unknown 2.50E-02 1.10E-01 2.50E-02 1.10E-01


Benzene 7.94E-02 3.48E-01 unknown 7.94E-02 3.48E-01 7.94E-02 3.48E-01


Beryllium 1.28E-03 5.62E-03 unknown 1.28E-03 5.62E-03 1.28E-03 5.62E-03


Cadmium 3.12E-03 1.36E-02 unknown 3.12E-03 1.36E-02 3.12E-03 1.36E-02


Chromium 1.59E-02 6.96E-02 unknown 1.59E-02 6.96E-02 1.59E-02 6.96E-02


Cobalt 6.11E-03 2.68E-02 unknown 6.11E-03 2.68E-02 6.11E-03 2.68E-02

SV 003 EU 001 Worst Case NG = 0.1 MMscf/hr

Formaldehyde 0.00E+00 0.00E+00 0.0% 0.00E+00 0.00E+00 0.00E+00 0.00E+00


Hexane 0.00E+00 0.00E+00 0.0% 0.00E+00 0.00E+00 0.00E+00 0.00E+00


Manganese 2.99E-02 1.31E-01 unknown 2.99E-02 1.31E-01 2.99E-02 1.31E-01


Mercury 5.07E-03 2.22E-02 unknown 5.07E-03 2.22E-02 5.07E-03 2.22E-02


Naphthalene 7.94E-04 3.48E-03 unknown 7.94E-04 3.48E-03 7.94E-04 3.48E-03


Nickel 1.71E-02 7.49E-02 unknown 1.71E-02 7.49E-02 1.71E-02 7.49E-02


Selenium 7.94E-02 3.48E-01 unknown 7.94E-02 3.48E-01 7.94E-02 3.48E-01


Toluene 1.47E-02 6.42E-02 unknown 1.47E-02 6.42E-02 1.47E-02 6.42E-02

Coal Only Emission Factor Coal = 56.8 tph (1000 MMBtu/hr)

Total PCDD/PCDF 1.08E-07 4.71E-07 Unknown 1.08E-07 4.71E-07


2,3,7,8-TCDD 8.73E-10 3.83E-09 Unknown 8.73E-10 3.83E-09


Total TCDD 5.67E-09 2.48E-08 Unknown 5.67E-09 2.48E-08


Total PeCDD 2.73E-09 1.20E-08 Unknown 2.73E-09 1.20E-08


Total HxCDD 1.75E-09 7.68E-09 Unknown 1.75E-09 7.68E-09


Total HpCDD 5.09E-09 2.23E-08 Unknown 5.09E-09 2.23E-08


Total OCDD 2.54E-08 1.11E-07 Unknown 2.54E-08 1.11E-07

Worst Case Coal = 56.8 tph (1000 MMBtu/hr)



SV EU


(MMBtu/hr)Data





Total PCDD 4.07E-08 1.78E-07 Unknown 4.07E-08 1.78E-07


2,3,7,8-TCDF 3.12E-09 1.36E-08 Unknown 3.12E-09 1.36E-08


Total TCDF 2.47E-08 1.08E-07 Unknown 2.47E-08 1.08E-07


Total PeCDF 2.16E-08 9.44E-08 Unknown 2.16E-08 9.44E-08


Total HxCDF 1.17E-08 5.14E-08 Unknown 1.17E-08 5.14E-08


Total HpCDF 4.69E-09 2.05E-08 Unknown 4.69E-09 2.05E-08


Total OCDF 4.05E-09 1.77E-08 Unknown 4.05E-09 1.77E-08


Total PCDF 6.66E-08 2.92E-07 Unknown 6.66E-08 2.92E-07


Total PAH 1.27E-03 5.55E-03 Unknown 1.27E-03 5.55E-03


Biphenyl 1.04E-04 4.55E-04 Unknown 1.04E-04 4.55E-04


Acenaphthene 3.12E-05 1.36E-04 Unknown 3.12E-05 1.36E-04


Acenaphthylene 1.53E-05 6.69E-05 Unknown 1.53E-05 6.69E-05


Anthracene 1.28E-05 5.62E-05 Unknown 1.28E-05 5.62E-05


Benzo(a)anthracene 4.89E-06 2.14E-05 Unknown 4.89E-06 2.14E-05


Benzo(a)pyrene 2.32E-06 1.02E-05 Unknown 2.32E-06 1.02E-05


Benzo(b,j,k)fluoranthene 6.72E-06 2.94E-05 Unknown 6.72E-06 2.94E-05


Benzo(g,h,i)perylene 1.65E-06 7.22E-06 Unknown 1.65E-06 7.22E-06


Chrysene 6.11E-06 2.68E-05 Unknown 6.11E-06 2.68E-05


Fluoranthene 4.34E-05 1.90E-04 Unknown 4.34E-05 1.90E-04


Fluorene 5.56E-05 2.43E-04 Unknown 5.56E-05 2.43E-04


Indeno(1,2,3-cd)pyrene 3.73E-06 1.63E-05 Unknown 3.73E-06 1.63E-05


Naphthalene 7.94E-04 3.48E-03 Unknown 7.94E-04 3.48E-03


Phenanthrene 1.65E-04 7.22E-04 Unknown 1.65E-04 7.22E-04


Pyrene 2.02E-05 8.83E-05 Unknown 2.02E-05 8.83E-05


5-Methyl chrysene 1.34E-06 5.89E-06 Unknown 1.34E-06 5.89E-06


POM 2.24E-03 9.79E-03 Unknown 2.24E-03 9.79E-03

SV 003 EU 001 Coal Only Emission Factor Coal = 56.8 tph (1000 MMBtu/hr)

Acetaldehyde 3.48E-02 1.52E-01 unknown 3.48E-02 1.52E-01 3.48E-02 1.52E-01


Acetophenone 9.16E-04 4.01E-03 unknown 9.16E-04 4.01E-03 9.16E-04 4.01E-03


Acrolein 1.77E-02 7.76E-02 unknown 1.77E-02 7.76E-02 1.77E-02 7.76E-02


Antimony 1.10E-03 4.82E-03 unknown 1.10E-03 4.82E-03 1.10E-03 4.82E-03


Benzyl chloride 4.28E-02 1.87E-01 unknown 4.28E-02 1.87E-01 4.28E-02 1.87E-01


Biphenyl 1.04E-04 4.55E-04 unknown 1.04E-04 4.55E-04 1.04E-04 4.55E-04


bis(2-Ethylhexyl)phthalate 4.46E-03 1.95E-02 unknown 4.46E-03 1.95E-02 4.46E-03 1.95E-02


Bromoform 2.38E-03 1.04E-02 unknown 2.38E-03 1.04E-02 2.38E-03 1.04E-02


Carbon disulfide 7.94E-03 3.48E-02 unknown 7.94E-03 3.48E-02 7.94E-03 3.48E-02


2-Chloroacetophenone 4.28E-04 1.87E-03 unknown 4.28E-04 1.87E-03 4.28E-04 1.87E-03



SV EU


(MMBtu/hr)Data





Chlorobenzene 1.34E-03 5.89E-03 unknown 1.34E-03 5.89E-03 1.34E-03 5.89E-03


Chloroform 3.60E-03 1.58E-02 unknown 3.60E-03 1.58E-02 3.60E-03 1.58E-02


Cumene 3.24E-04 1.42E-03 unknown 3.24E-04 1.42E-03 3.24E-04 1.42E-03


Cyanide Compounds (Cyanide) 1.53E-01 6.69E-01 unknown 1.53E-01 6.69E-01 1.53E-01 6.69E-01


2,4-Dinitrotoluene 1.71E-05 7.49E-05 unknown 1.71E-05 7.49E-05 1.71E-05 7.49E-05


Dimethyl sulfate 2.93E-03 1.28E-02 unknown 2.93E-03 1.28E-02 2.93E-03 1.28E-02


Ethylbenzene 5.74E-03 2.51E-02 unknown 5.74E-03 2.51E-02 5.74E-03 2.51E-02


Ethyl chloride 2.57E-03 1.12E-02 unknown 2.57E-03 1.12E-02 2.57E-03 1.12E-02


Ethylene dibromide 7.33E-05 3.21E-04 unknown 7.33E-05 3.21E-04 7.33E-05 3.21E-04


Ethylene dichloride 2.44E-03 1.07E-02 unknown 2.44E-03 1.07E-02 2.44E-03 1.07E-02


Formaldehyde 1.47E-02 6.42E-02 unknown 1.47E-02 6.42E-02 1.47E-02 6.42E-02


Hexane 4.09E-03 1.79E-02 unknown 4.09E-03 1.79E-02 4.09E-03 1.79E-02


Isophorone 3.54E-02 1.55E-01 unknown 3.54E-02 1.55E-01 3.54E-02 1.55E-01


Hydrogen Chloride 7.33E+01 3.21E+02 97.1% 2.15E+00 9.42E+00 2.15E+00 9.42E+00


Hydrogen Fluoride 9.16E+00 4.01E+01 unknown 9.16E+00 4.01E+01 9.16E+00 4.01E+01


Methyl bromide 9.77E-03 4.28E-02 unknown 9.77E-03 4.28E-02 9.77E-03 4.28E-02


Methyl chloride 3.24E-02 1.42E-01 unknown 3.24E-02 1.42E-01 3.24E-02 1.42E-01


Methyl ethyl ketone 2.38E-02 1.04E-01 unknown 2.38E-02 1.04E-01 2.38E-02 1.04E-01


Methyl hydrazine 1.04E-02 4.55E-02 unknown 1.04E-02 4.55E-02 1.04E-02 4.55E-02


Methyl methacrylate 1.22E-03 5.35E-03 unknown 1.22E-03 5.35E-03 1.22E-03 5.35E-03


Methyl tert butyl ether 2.14E-03 9.36E-03 unknown 2.14E-03 9.36E-03 2.14E-03 9.36E-03


Methylene chloride 1.77E-02 7.76E-02 unknown 1.77E-02 7.76E-02 1.77E-02 7.76E-02


Phenol 9.77E-04 4.28E-03 unknown 9.77E-04 4.28E-03 9.77E-04 4.28E-03


Propionaldehyde 2.32E-02 1.02E-01 unknown 2.32E-02 1.02E-01 2.32E-02 1.02E-01


Styrene 1.53E-03 6.69E-03 unknown 1.53E-03 6.69E-03 1.53E-03 6.69E-03


Tetrachloroethylene 2.63E-03 1.15E-02 unknown 2.63E-03 1.15E-02 2.63E-03 1.15E-02


1,1,1 - trichloroethane 1.22E-03 5.35E-03 unknown 1.22E-03 5.35E-03 1.22E-03 5.35E-03


Xylenes 2.26E-03 9.90E-03 unknown 2.26E-03 9.90E-03 2.26E-03 9.90E-03


Vinyl acetate 4.64E-04 2.03E-03 unknown 4.64E-04 2.03E-03 4.64E-04 2.03E-03

SV 003 EU 001 Natural Gas Only Emission Factor NG = 0.1 MMscf/hr

2-Methylnaphthalene 3.39E-06 1.48E-05 0.0% 3.39E-06 1.48E-05 3.39E-06 1.48E-05


3-Methylchloranthrene 2.54E-07 1.11E-06 0.0% 2.54E-07 1.11E-06 2.54E-07 1.11E-06


7,12-Dimethylbenz(a)anthracene 2.26E-06 9.89E-06 0.0% 2.26E-06 9.89E-06 2.26E-06 9.89E-06


Acenaphthene 2.54E-07 1.11E-06 0.0% 2.54E-07 1.11E-06 2.54E-07 1.11E-06


Acenaphthylene 2.54E-07 1.11E-06 0.0% 2.54E-07 1.11E-06 2.54E-07 1.11E-06


Anthracene 3.39E-07 1.48E-06 0.0% 3.39E-07 1.48E-06 3.39E-07 1.48E-06


Benzo(a)anthracene 2.54E-07 1.11E-06 0.0% 2.54E-07 1.11E-06 2.54E-07 1.11E-06



SV EU


(MMBtu/hr)Data





Benzo(a)pyrene 1.69E-07 7.42E-07 0.0% 1.69E-07 7.42E-07 1.69E-07 7.42E-07


Benzo(b)fluoranthene 2.54E-07 1.11E-06 0.0% 2.54E-07 1.11E-06 2.54E-07 1.11E-06


Benzo(g,h,i)perylene 1.69E-07 7.42E-07 0.0% 1.69E-07 7.42E-07 1.69E-07 7.42E-07


Benzo(k)fluoranthene 2.54E-07 1.11E-06 0.0% 2.54E-07 1.11E-06 2.54E-07 1.11E-06


Chrysene 2.54E-07 1.11E-06 0.0% 2.54E-07 1.11E-06 2.54E-07 1.11E-06


Dibenz(a,h)anthracene 1.69E-07 7.42E-07 0.0% 1.69E-07 7.42E-07 1.69E-07 7.42E-07


Dichlorobenzene 1.69E-04 7.42E-04 0.0% 1.69E-04 7.42E-04 1.69E-04 7.42E-04


Fluoranthene 4.24E-07 1.86E-06 0.0% 4.24E-07 1.86E-06 4.24E-07 1.86E-06


Fluorene 3.95E-07 1.73E-06 0.0% 3.95E-07 1.73E-06 3.95E-07 1.73E-06


Indeno(1,2,3-cd)pyrene 2.54E-07 1.11E-06 0.0% 2.54E-07 1.11E-06 2.54E-07 1.11E-06


Phenanthrene 2.40E-06 1.05E-05 0.0% 2.40E-06 1.05E-05 2.40E-06 1.05E-05


Pyrene 7.06E-07 3.09E-06 0.0% 7.06E-07 3.09E-06 7.06E-07 3.09E-06




SV EU


(MMBtu/hr)Data


Efficiency Source lb/hr tons/year Source lb/hr tons/yearSV 003 EU 002 910 [03] Coal 51.70 Tons/hour CO 5.00E-01 lb/ton [03] 25.85 113.23 0.0% [03] 25.85 113.23 25.85 113.23SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Lead 6.00E-03 lb/ton [03] 0.31 1.36 0.0% [03] 0.31 1.36 0.31 1.36SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour NOx 1.20E+01 lb/ton [03] 620.45 2,717.59 70.7% [03] 182.00 797.16 0.200 lb/mmbtu [27] 182.00 797.16SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour PM 7.03E+01 lb/ton [03] 3,634.83 15,920.55 99.6% [03] 13.65 59.79 0.015 lb/mmbtu [27] 13.65 59.79SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour PM10 1.62E+01 lb/ton [03] 837.56 3,668.52 95.9% [03] 34.13 149.47 0.038 lb/mmbtu 34.13 149.47SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour PM2.5 4.25E+00 lb/ton [03] 219.64 962.03 84.5% [03] 34.13 149.47 0.038 lb/mmbtu 34.13 149.47SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour SO2 2.10E+01 lb/ton [03] 1,085.80 4,755.78 41.3% [03] 637.00 2,790.06 0.700 lb/mmbtu [27] 637.00 2,790.06SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Sulfuric Acid Mist 6.11E-02 lb/ton [03] 3.16 13.84 96.4% [03] 0.11 0.50 2.20E-03 lb/ton 0.11 0.50SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour VOC 6.00E-02 lb/ton [03] 3.10 13.59 0.0% [03] 3.10 13.59 3.10 13.59SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour CO2 3.70E+03 lb/ton [03] 191,099 837,014 0.0% [03] 191,099 837,014 191,099 837,014.02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour CH4 4.18E-01 lb/ton [03] 21.63 94.75 0.0% [03] 21.63 94.75 21.63 94.75SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour N2O 6.09E-02 lb/ton [03] 3.15 13.78 0.0% [03] 3.15 13.78 3.15 13.78SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour CO2-e 3.72E+03 lb/ton [03] 192,578 843,490 0.0% [03] 192,578 843,490 192,578 843,489.96SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Acetaldehyde 5.70E-04 lb/ton [03] 2.95E-02 1.29E-01 unknown [03] 2.95E-02 1.29E-01 2.95E-02 1.29E-01SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Acetophenone 1.50E-05 lb/ton [03] 7.76E-04 3.40E-03 unknown [03] 7.76E-04 3.40E-03 7.76E-04 3.40E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Acrolein 2.90E-04 lb/ton [03] 1.50E-02 6.57E-02 unknown [03] 1.50E-02 6.57E-02 1.50E-02 6.57E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Antimony 1.80E-05 lb/ton [03] 9.31E-04 4.08E-03 unknown [03] 9.31E-04 4.08E-03 9.31E-04 4.08E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Arsenic 4.10E-04 lb/ton [03] 2.12E-02 9.29E-02 unknown [03] 2.12E-02 9.29E-02 2.12E-02 9.29E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Benzene 1.30E-03 lb/ton [03] 6.72E-02 2.94E-01 unknown [03] 6.72E-02 2.94E-01 6.72E-02 2.94E-01SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Benzyl chloride 7.00E-04 lb/ton [03] 3.62E-02 1.59E-01 unknown [03] 3.62E-02 1.59E-01 3.62E-02 1.59E-01SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Beryllium 2.10E-05 lb/ton [03] 1.09E-03 4.76E-03 unknown [03] 1.09E-03 4.76E-03 1.09E-03 4.76E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Biphenyl 1.70E-06 lb/ton [03] 8.79E-05 3.85E-04 unknown [03] 8.79E-05 3.85E-04 8.79E-05 3.85E-04SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour bis(2-Ethylhexyl)phthalate 7.30E-05 lb/ton [03] 3.77E-03 1.65E-02 unknown [03] 3.77E-03 1.65E-02 3.77E-03 1.65E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Bromoform 3.90E-05 lb/ton [03] 2.02E-03 8.83E-03 unknown [03] 2.02E-03 8.83E-03 2.02E-03 8.83E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Cadmium 5.10E-05 lb/ton [03] 2.64E-03 1.15E-02 unknown [03] 2.64E-03 1.15E-02 2.64E-03 1.15E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Carbon disulfide 1.30E-04 lb/ton [03] 6.72E-03 2.94E-02 unknown [03] 6.72E-03 2.94E-02 6.72E-03 2.94E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour 2-Chloroacetophenone 7.00E-06 lb/ton [03] 3.62E-04 1.59E-03 unknown [03] 3.62E-04 1.59E-03 3.62E-04 1.59E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Chlorobenzene 2.20E-05 lb/ton [03] 1.14E-03 4.98E-03 unknown [03] 1.14E-03 4.98E-03 1.14E-03 4.98E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Chloroform 5.90E-05 lb/ton [03] 3.05E-03 1.34E-02 unknown [03] 3.05E-03 1.34E-02 3.05E-03 1.34E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Chromium 2.60E-04 lb/ton [03] 1.34E-02 5.89E-02 unknown [03] 1.34E-02 5.89E-02 1.34E-02 5.89E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Cobalt 1.00E-04 lb/ton [03] 5.17E-03 2.26E-02 unknown [03] 5.17E-03 2.26E-02 5.17E-03 2.26E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Cumene 5.30E-06 lb/ton [03] 2.74E-04 1.20E-03 unknown [03] 2.74E-04 1.20E-03 2.74E-04 1.20E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Cyanide Compounds (Cyanide) 2.50E-03 lb/ton [03] 1.29E-01 5.66E-01 unknown [03] 1.29E-01 5.66E-01 1.29E-01 5.66E-01SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour 2,4-Dinitrotoluene 2.80E-07 lb/ton [03] 1.45E-05 6.34E-05 unknown [03] 1.45E-05 6.34E-05 1.45E-05 6.34E-05SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Dimethyl sulfate 4.80E-05 lb/ton [03] 2.48E-03 1.09E-02 unknown [03] 2.48E-03 1.09E-02 2.48E-03 1.09E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Ethylbenzene 9.40E-05 lb/ton [03] 4.86E-03 2.13E-02 unknown [03] 4.86E-03 2.13E-02 4.86E-03 2.13E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Ethyl chloride 4.20E-05 lb/ton [03] 2.17E-03 9.51E-03 unknown [03] 2.17E-03 9.51E-03 2.17E-03 9.51E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Ethylene dibromide 1.20E-06 lb/ton [03] 6.20E-05 2.72E-04 unknown [03] 6.20E-05 2.72E-04 6.20E-05 2.72E-04SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Ethylene dichloride 4.00E-05 lb/ton [03] 2.07E-03 9.06E-03 unknown [03] 2.07E-03 9.06E-03 2.07E-03 9.06E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Formaldehyde 2.40E-04 lb/ton [03] 1.24E-02 5.44E-02 unknown [03] 1.24E-02 5.44E-02 1.24E-02 5.44E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Hexane 6.70E-05 lb/ton [03] 3.46E-03 1.52E-02 unknown [03] 3.46E-03 1.52E-02 3.46E-03 1.52E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Isophorone 5.80E-04 lb/ton [03] 3.00E-02 1.31E-01 unknown [03] 3.00E-02 1.31E-01 3.00E-02 1.31E-01SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Hydrogen Fluoride 1.50E-01 lb/ton [03] 7.76E+00 3.40E+01 unknown [03] 7.76E+00 3.40E+01 7.76E+00 3.40E+01SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Hydrogen Chloride 1.20E+00 lb/ton [03] 6.20E+01 2.72E+02 97.1% [03] 1.82E+00 7.97E+00 2.0E-03 lb/mmbtu [03] 1.82E+00 7.97E+00SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Manganese 4.90E-04 lb/ton [03] 2.53E-02 1.11E-01 unknown [03] 2.53E-02 1.11E-01 2.53E-02 1.11E-01SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Mercury 8.30E-05 lb/ton [03] 4.29E-03 1.88E-02 unknown [03] 4.29E-03 1.88E-02 1.2E-06 lb/mmbtu (30-d [03] 1.09E-03 4.78E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Methyl bromide 1.60E-04 lb/ton [03] 8.27E-03 3.62E-02 unknown [03] 8.27E-03 3.62E-02 8.27E-03 3.62E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Methyl chloride 5.30E-04 lb/ton [03] 2.74E-02 1.20E-01 unknown [03] 2.74E-02 1.20E-01 2.74E-02 1.20E-01SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Methyl ethyl ketone 3.90E-04 lb/ton [03] 2.02E-02 8.83E-02 unknown [03] 2.02E-02 8.83E-02 2.02E-02 8.83E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Methyl hydrazine 1.70E-04 lb/ton [03] 8.79E-03 3.85E-02 unknown [03] 8.79E-03 3.85E-02 8.79E-03 3.85E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Methyl methacrylate 2.00E-05 lb/ton [03] 1.03E-03 4.53E-03 unknown [03] 1.03E-03 4.53E-03 1.03E-03 4.53E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Methyl tert butyl ether 3.50E-05 lb/ton [03] 1.81E-03 7.93E-03 unknown [03] 1.81E-03 7.93E-03 1.81E-03 7.93E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Methylene chloride 2.90E-04 lb/ton [03] 1.50E-02 6.57E-02 unknown [03] 1.50E-02 6.57E-02 1.50E-02 6.57E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Naphthalene 1.30E-05 lb/ton [03] 6.72E-04 2.94E-03 unknown [03] 6.72E-04 2.94E-03 6.72E-04 2.94E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Nickel 2.80E-04 lb/ton [03] 1.45E-02 6.34E-02 unknown [03] 1.45E-02 6.34E-02 1.45E-02 6.34E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Phenol 1.60E-05 lb/ton [03] 8.27E-04 3.62E-03 unknown [03] 8.27E-04 3.62E-03 8.27E-04 3.62E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Propionaldehyde 3.80E-04 lb/ton [03] 1.96E-02 8.61E-02 unknown [03] 1.96E-02 8.61E-02 1.96E-02 8.61E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Selenium 1.30E-03 lb/ton [03] 6.72E-02 2.94E-01 unknown [03] 6.72E-02 2.94E-01 6.72E-02 2.94E-01SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Styrene 2.50E-05 lb/ton [03] 1.29E-03 5.66E-03 unknown [03] 1.29E-03 5.66E-03 1.29E-03 5.66E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Tetrachloroethylene 4.30E-05 lb/ton [03] 2.22E-03 9.74E-03 unknown [03] 2.22E-03 9.74E-03 2.22E-03 9.74E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour 1,1,1 - trichloroethane 2.00E-05 lb/ton [03] 1.03E-03 4.53E-03 unknown [03] 1.03E-03 4.53E-03 1.03E-03 4.53E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Toluene 2.40E-04 lb/ton [03] 1.24E-02 5.44E-02 unknown [03] 1.24E-02 5.44E-02 1.24E-02 5.44E-02SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Xylenes 3.70E-05 lb/ton [03] 1.91E-03 8.38E-03 unknown [03] 1.91E-03 8.38E-03 1.91E-03 8.38E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Vinyl acetate 7.60E-06 lb/ton [03] 3.93E-04 1.72E-03 unknown [03] 3.93E-04 1.72E-03 3.93E-04 1.72E-03SV 003 EU 002 910 [03] Coal 51.70 Tons/hour Total PCDD/PCDF 1.76E-09 lbs/ton [28] 9.10E-08 3.99E-07 Unknown [28] 9.10E-08 3.99E-07SV 003 EU 002 910 SV 003 Coal 51.70 Tons/hour 2,3,7,8-TCDD 1.43E-11 lbs/ton [28] 7.39E-10 3.24E-09 Unknown [28] 7.39E-10 3.24E-09SV 003 EU 002 910 SV 003 Coal 51.70 Tons/hour Total TCDD 9.28E-11 lbs/ton [28] 4.80E-09 2.10E-08 Unknown [28] 4.80E-09 2.10E-08SV 003 EU 002 910 SV 003 Coal 51.70 Tons/hour Total PeCDD 4.47E-11 lbs/ton [28] 2.31E-09 1.01E-08 Unknown [28] 2.31E-09 1.01E-08SV 003 EU 002 910 SV 003 Coal 51.70 Tons/hour Total HxCDD 2.87E-11 lbs/ton [28] 1.48E-09 6.50E-09 Unknown [28] 1.48E-09 6.50E-09

6/9/2017

Fuel Information Emission Factor Uncontrolled Emissions Controls Limited Emissions


Controlled Emissions



SV EU


(MMBtu/hr)Data


Efficiency Source lb/hr tons/year Source lb/hr tons/year




SV 003 EU 002 910 SV 003 Coal 51.70 Tons/hour Total HpCDD 8.34E-11 lbs/ton [28] 4.31E-09 1.89E-08 Unknown [28] 4.31E-09 1.89E-08SV 003 EU 002 910 SV 003 Coal 51.70 Tons/hour Total OCDD 4.16E-10 lbs/ton [28] 2.15E-08 9.42E-08 Unknown [28] 2.15E-08 9.42E-08SV 003 EU 002 910 SV 003 Coal 51.70 Tons/hour Total PCDD 6.66E-10 lbs/ton [28] 3.44E-08 1.51E-07 Unknown [28] 3.44E-08 1.51E-07SV 003 EU 002 910 SV 003 Coal 51.70 Tons/hour 2,3,7,8-TCDF 5.10E-11 lbs/ton [28] 2.64E-09 1.15E-08 Unknown [28] 2.64E-09 1.15E-08SV 003 EU 002 910 SV 003 Coal 51.70 Tons/hour Total TCDF 4.04E-10 lbs/ton [28] 2.09E-08 9.15E-08 Unknown [28] 2.09E-08 9.15E-08SV 003 EU 002 910 SV 003 Coal 51.70 Tons/hour Total PeCDF 3.53E-10 lbs/ton [28] 1.83E-08 7.99E-08 Unknown [28] 1.83E-08 7.99E-08SV 003 EU 002 910 SV 003 Coal 51.70 Tons/hour Total HxCDF 1.92E-10 lbs/ton [28] 9.93E-09 4.35E-08 Unknown [28] 9.93E-09 4.35E-08SV 003 EU 002 910 SV 003 Coal 51.70 Tons/hour Total HpCDF 7.68E-11 lbs/ton [28] 3.97E-09 1.74E-08 Unknown [28] 3.97E-09 1.74E-08SV 003 EU 002 910 SV 003 Coal 51.70 Tons/hour Total OCDF 6.63E-11 lbs/ton [28] 3.43E-09 1.50E-08 Unknown [28] 3.43E-09 1.50E-08SV 003 EU 002 910 SV 003 Coal 51.70 Tons/hour Total PCDF 1.09E-09 lbs/ton [28] 5.64E-08 2.47E-07 Unknown [28] 5.64E-08 2.47E-07SV 003 EU 002 910 [03] Coal 51.70 Tons/hour Total PAH 2.08E-05 lbs/ton [29] 1.07E-03 4.70E-03 Unknown [29] 1.07E-03 4.70E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Biphenyl 1.70E-06 lbs/ton [29] 8.79E-05 3.85E-04 Unknown [29] 8.79E-05 3.85E-04SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Acenaphthene 5.10E-07 lbs/ton [29] 2.64E-05 1.15E-04 Unknown [29] 2.64E-05 1.15E-04SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Acenaphthylene 2.50E-07 lbs/ton [29] 1.29E-05 5.66E-05 Unknown [29] 1.29E-05 5.66E-05SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Anthracene 2.10E-07 lbs/ton [29] 1.09E-05 4.76E-05 Unknown [29] 1.09E-05 4.76E-05SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Benzo(a)anthracene 8.00E-08 lbs/ton [29] 4.14E-06 1.81E-05 Unknown [29] 4.14E-06 1.81E-05SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Benzo(a)pyrene 3.80E-08 lbs/ton [29] 1.96E-06 8.61E-06 Unknown [29] 1.96E-06 8.61E-06SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Benzo(b,j,k)fluoranthene 1.10E-07 lbs/ton [29] 5.69E-06 2.49E-05 Unknown [29] 5.69E-06 2.49E-05SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Benzo(g,h,i)perylene 2.70E-08 lbs/ton [29] 1.40E-06 6.11E-06 Unknown [29] 1.40E-06 6.11E-06SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Chrysene 1.00E-07 lbs/ton [29] 5.17E-06 2.26E-05 Unknown [29] 5.17E-06 2.26E-05SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Fluoranthene 7.10E-07 lbs/ton [29] 3.67E-05 1.61E-04 Unknown [29] 3.67E-05 1.61E-04SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Fluorene 9.10E-07 lbs/ton [29] 4.71E-05 2.06E-04 Unknown [29] 4.71E-05 2.06E-04SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Indeno(1,2,3-cd)pyrene 6.10E-08 lbs/ton [29] 3.15E-06 1.38E-05 Unknown [29] 3.15E-06 1.38E-05SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Naphthalene 1.30E-05 lbs/ton [29] 6.72E-04 2.94E-03 Unknown [29] 6.72E-04 2.94E-03SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Phenanthrene 2.70E-06 lbs/ton [29] 1.40E-04 6.11E-04 Unknown [29] 1.40E-04 6.11E-04SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour Pyrene 3.30E-07 lbs/ton [29] 1.71E-05 7.47E-05 Unknown [29] 1.71E-05 7.47E-05SV 003 SV 002 SV 910 SV 003 Coal 51.70 Tons/hour 5-Methyl chrysene 2.20E-08 lbs/ton [29] 1.14E-06 4.98E-06 Unknown [29] 1.14E-06 4.98E-06SV 003 EU 002 910 [03] Coal 51.70 Tons/hour POM 2.08 lb/1012 Btu [30] 1.89E-03 8.29E-03 Unknown [30] 1.89E-03 8.29E-03SV 003 EU 002 144 [03] Natural Gas, Startup 0.14 MMscf/hr CO 8.40E+01 lb/MMscf [04] 11.86 51.94 0.0% [04] 11.86 51.94 11.86 51.94SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Lead 5.00E-04 lb/MMscf [04] 0.00 0.00 0.0% [04] 0.00 0.00 0.00 0.00SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr NOx 1.78E+02 lb/MMscf [04] 25.06 109.76 0.0% [04] 25.06 109.76 25.06 109.76SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr PM 2.00E-01 lb/MMscf [04] 0.03 0.12 0.0% [04] 0.03 0.12 0.03 0.12SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr PM10 5.20E-01 lb/MMscf [04] 0.07 0.32 0.0% [04] 0.07 0.32 0.07 0.32SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr PM2.5 5.20E-01 lb/MMscf [04] 0.07 0.32 0.0% [04] 0.07 0.32 0.07 0.32SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr SO2 6.000E-01 lb/MMscf [04] 0.08 0.37 0.0% [04] 0.08 0.37 0.08 0.37SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr VOC 5.50E+00 lb/MMscf [04] 0.78 3.40 0.0% [04] 0.78 3.40 0.78 3.40SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr CO2 1.20E+05 lb/MMscf [04] 16,947 74,227 0.0% [04] 16,947 74,227 16,946.71 74,226.61SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr CH4 2.26E+00 lb/MMscf [04] 0.32 1.40 0.0% [04] 0.32 1.40 0.32 1.40SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr N2O 2.26E-01 lb/MMscf [04] 0.03 0.14 0.0% [04] 0.03 0.14 0.03 0.14SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr CO2-e 1.20E+05 lb/MMscf [04] 16,964 74,303 0.0% [04] 1.70E+04 7.43E+04 1.70E+04 7.43E+04SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr 2-Methylnaphthalene 2.40E-05 lb/MMscf [04] 3.39E-06 1.48E-05 0.0% [04] 3.39E-06 1.48E-05 3.39E-06 1.48E-05SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr 3-Methylchloranthrene 1.80E-06 lb/MMscf [04] 2.54E-07 1.11E-06 0.0% [04] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr 7,12-Dimethylbenz(a)anthracene 1.60E-05 lb/MMscf [04] 2.26E-06 9.89E-06 0.0% [04] 2.26E-06 9.89E-06 2.26E-06 9.89E-06SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Acenaphthene 1.80E-06 lb/MMscf [04] 2.54E-07 1.11E-06 0.0% [04] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Acenaphthylene 1.80E-06 lb/MMscf [04] 2.54E-07 1.11E-06 0.0% [04] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Anthracene 2.40E-06 lb/MMscf [04] 3.39E-07 1.48E-06 0.0% [04] 3.39E-07 1.48E-06 3.39E-07 1.48E-06SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Arsenic 2.00E-04 lb/MMscf [04] 2.82E-05 1.24E-04 0.0% [04] 2.82E-05 1.24E-04 2.82E-05 1.24E-04SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Benzo(a)anthracene 1.80E-06 lb/MMscf [04] 2.54E-07 1.11E-06 0.0% [04] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Benzene 2.10E-03 lb/MMscf [04] 2.96E-04 1.30E-03 0.0% [04] 2.96E-04 1.30E-03 2.96E-04 1.30E-03SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Benzo(a)pyrene 1.20E-06 lb/MMscf [04] 1.69E-07 7.42E-07 0.0% [04] 1.69E-07 7.42E-07 1.69E-07 7.42E-07SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Benzo(b)fluoranthene 1.80E-06 lb/MMscf [04] 2.54E-07 1.11E-06 0.0% [04] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Benzo(g,h,i)perylene 1.20E-06 lb/MMscf [04] 1.69E-07 7.42E-07 0.0% [04] 1.69E-07 7.42E-07 1.69E-07 7.42E-07SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Benzo(k)fluoranthene 1.80E-06 lb/MMscf [04] 2.54E-07 1.11E-06 0.0% [04] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Beryllium 1.20E-05 lb/MMscf [04] 1.69E-06 7.42E-06 0.0% [04] 1.69E-06 7.42E-06 1.69E-06 7.42E-06SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Cadmium 1.10E-03 lb/MMscf [04] 1.55E-04 6.80E-04 0.0% [04] 1.55E-04 6.80E-04 1.55E-04 6.80E-04SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Chromium 1.40E-03 lb/MMscf [04] 1.98E-04 8.66E-04 0.0% [04] 1.98E-04 8.66E-04 1.98E-04 8.66E-04SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Chrysene 1.80E-06 lb/MMscf [04] 2.54E-07 1.11E-06 0.0% [04] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Cobalt 8.40E-05 lb/MMscf [04] 1.19E-05 5.19E-05 0.0% [04] 1.19E-05 5.19E-05 1.19E-05 5.19E-05SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Dibenz(a,h)anthracene 1.20E-06 lb/MMscf [04] 1.69E-07 7.42E-07 0.0% [04] 1.69E-07 7.42E-07 1.69E-07 7.42E-07SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Dichlorobenzene 1.20E-03 lb/MMscf [04] 1.69E-04 7.42E-04 0.0% [04] 1.69E-04 7.42E-04 1.69E-04 7.42E-04SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Fluoranthene 3.00E-06 lb/MMscf [04] 4.24E-07 1.86E-06 0.0% [04] 4.24E-07 1.86E-06 4.24E-07 1.86E-06SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Fluorene 2.80E-06 lb/MMscf [04] 3.95E-07 1.73E-06 0.0% [04] 3.95E-07 1.73E-06 3.95E-07 1.73E-06SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Formaldehyde 7.50E-02 lb/MMscf [04] 1.06E-02 4.64E-02 0.0% [04] 1.06E-02 4.64E-02 1.06E-02 4.64E-02SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Hexane 1.80E+00 lb/MMscf [04] 2.54E-01 1.11E+00 0.0% [04] 2.54E-01 1.11E+00 2.54E-01 1.11E+00SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Indeno(1,2,3-cd)pyrene 1.80E-06 lb/MMscf [04] 2.54E-07 1.11E-06 0.0% [04] 2.54E-07 1.11E-06 2.54E-07 1.11E-06SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Manganese 3.80E-04 lb/MMscf [04] 5.36E-05 2.35E-04 0.0% [04] 5.36E-05 2.35E-04 5.36E-05 2.35E-04SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Mercury 2.60E-04 lb/MMscf [04] 3.67E-05 1.61E-04 0.0% [04] 3.67E-05 1.61E-04 3.67E-05 1.61E-04SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Naphthalene 6.10E-04 lb/MMscf [04] 8.61E-05 3.77E-04 0.0% [04] 8.61E-05 3.77E-04 8.61E-05 3.77E-04SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Nickel 2.10E-03 lb/MMscf [04] 2.96E-04 1.30E-03 0.0% [04] 2.96E-04 1.30E-03 2.96E-04 1.30E-03SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Phenanthrene 1.70E-05 lb/MMscf [04] 2.40E-06 1.05E-05 0.0% [04] 2.40E-06 1.05E-05 2.40E-06 1.05E-05SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Pyrene 5.00E-06 lb/MMscf [04] 7.06E-07 3.09E-06 0.0% [04] 7.06E-07 3.09E-06 7.06E-07 3.09E-06SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Selenium 2.40E-05 lb/MMscf [04] 3.39E-06 1.48E-05 0.0% [04] 3.39E-06 1.48E-05 3.39E-06 1.48E-05SV 003 SV 002 SV 144 SV 003 Natural Gas, Startup 0.14 MMscf/hr Toluene 3.40E-03 lb/MMscf [04] 4.80E-04 2.10E-03 0.0% [04] 4.80E-04 2.10E-03 4.80E-04 2.10E-03SV 003 EU 002 CO 25.85 113.23 0.0% 25.85 113.23 25.85 113.23Worst Case

Coal = 51.1 tph (900 MMBtu/hr)



SV EU


(MMBtu/hr)Data







Lead 0.31 1.36 0.0% 0.31 1.36 0.31 1.36


NOx 620.45 2,717.59 70.7% 182.00 797.16 182.00 797.16


PM 3,634.83 15,920.55 99.6% 13.65 59.79 13.65 59.79


PM10 837.56 3,668.52 95.9% 34.13 149.47 34.13 149.47


PM2.5 219.64 962.03 84.5% 34.13 149.47 34.13 149.47


SO2 1,085.80 4,755.78 41.3% 637.00 2,790.06 637.00 2,790.06




VOC 3.10 13.59 0.0% 3.10 13.59 3.10 13.59


CO2 191,099 837,014 0.0% 191,099 837,014 191,099 837,014


CH4 21.63 94.75 0.0% 21.63 94.75 21.63 94.75


N2O 3.15 13.78 0.0% 3.15 13.78 3.15 13.78


CO2-e 192,578 843,490 0.0% 192,578 843,490 192,578 843,490




Benzene 6.72E-02 2.94E-01 unknown 6.72E-02 2.94E-01 6.72E-02 2.94E-01












Hexane 0.00E+00 0.00E+00 0.0% 0.00E+00 0.00E+00 0.00E+00 0.00E+00




Mercury 4.29E-03 1.88E-02 unknown 4.29E-03 1.88E-02 4.29E-03 1.88E-02






Selenium 6.72E-02 2.94E-01 unknown 6.72E-02 2.94E-01 6.72E-02 2.94E-01



























SV EU


(MMBtu/hr)Data

















































POM 1.89E-03 8.29E-03 Unknown 1.89E-03 8.29E-03




























Cyanide Compounds (Cyanide) 1.29E-01 5.66E-01 unknown 1.29E-01 5.66E-01 1.29E-01 5.66E-01







SV EU


(MMBtu/hr)Data























Hydrogen Fluoride 7.76E+00 3.40E+01 unknown 7.76E+00 3.40E+01 7.76E+00 3.40E+01




















































Chrysene 2.54E-07 1.11E-06 0.0% 2.54E-07 1.11E-06 2.54E-07 1.11E-06









SV EU


(MMBtu/hr)Data







Fluorene 3.95E-07 1.73E-06 0.0% 3.95E-07 1.73E-06 3.95E-07 1.73E-06






Pyrene 7.06E-07 3.09E-06 0.0% 7.06E-07 3.09E-06 7.06E-07 3.09E-06




SV EU


(MMBtu/hr)Data


Efficiency Source lb/hr tons/year Source lb/hr tons/yearSV 003 EU 003 4425 [05] Coal 251.4 Tons/hour CO 1.50E-01 lb/mmbtu [05] 663.75 2,907.23 0.0% [05] 663.75 2,907.23 663.75 2,907.23SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Fluorides 5.14E-03 lb/mmbtu [05] 22.76 99.68 65.0% [05] 7.97 34.89 0.0018 lb/mmbtu 7.97 34.89SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Lead 6.00E-03 lb/ton [05] 1.51 6.61 88.3% [05] 0.18 0.78 ####### lb/mmbtu [05] 0.18 0.78SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour NOx 7.20E+00 lb/ton [05] 1,810.23 7,928.80 85.3% [05] 265.50 1,162.89 0.060 lb/mmbtu [27] 265.50 1,162.89SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour PM 7.03E+01 lb/ton [05] 17,674.86 77,415.88 99.6% [05] 61.95 271.34 0.014 lb/mmbtu 61.95 271.34SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour PM10 1.62E+01 lb/ton [05] 4,072.76 17,838.69 96.2% [05] 154.88 678.35 0.035 lb/mmbtu 154.88 678.35SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour PM2.5 4.25E+00 lb/ton [05] 1,068.03 4,677.99 85.5% [05] 154.88 678.35 0.035 lb/mmbtu 154.88 678.35SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour SO2 2.10E+01 lb/ton [05] 5,279.83 23,125.65 97.5% [05] 132.75 581.45 0.030 lb/mmbtu [27] 132.75 581.45SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Sulfuric Acid Mist 2.31E-01 lb/ton [05] 57.98 253.94 98.5% [05] 0.88 3.84 ####### lb/ton 0.88 3.84SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour VOC 6.00E-02 lb/ton [05] 15.09 66.07 0.0% [05] 15.09 66.07 15.09 66.07SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour CO2 3.70E+03 lb/ton [05] 929,246 4,070,096 0.0% [05] 929,246 4,070,096 929,246 4,070,096SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour CH4 4.18E-01 lb/ton [05] 105.19 460.75 0.0% [05] 105.19 460.75 105.19 460.75SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour N2O 6.09E-02 lb/ton [05] 15.30 67.02 0.0% [05] 15.30 67.02 15.30 67.02SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour CO2-e 3.72E+03 lb/ton [05] 936,435 4,101,586 0.0% [05] 936,435 4,101,586 936,435 4,101,586SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Acetaldehyde 5.70E-04 lb/ton [05] 0.14 0.63 unknown [05] 0.14 0.63 0.14 0.63SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Acetophenone 1.50E-05 lb/ton [05] 0.00 0.02 unknown [05] 0.00 0.02 0.00 0.02SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Acrolein 2.90E-04 lb/ton [05] 0.07 0.32 unknown [05] 0.07 0.32 0.07 0.32SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Antimony 1.80E-05 lb/ton [05] 0.00 0.02 unknown [05] 0.00 0.02 0.00 0.02SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Arsenic 4.10E-04 lb/ton [05] 0.10 0.45 unknown [05] 0.10 0.45 0.10 0.45SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Benzene 1.30E-03 lb/ton [05] 0.33 1.43 unknown [05] 0.33 1.43 0.33 1.43SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Benzyl chloride 7.00E-04 lb/ton [05] 0.18 0.77 unknown [05] 0.18 0.77 0.18 0.77SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Beryllium 2.10E-05 lb/ton [05] 0.01 0.02 unknown [05] 0.01 0.02 0.01 0.02SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Biphenyl 1.70E-06 lb/ton [05] 0.00 0.00 unknown [05] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour bis(2-Ethylhexyl)phthala 7.30E-05 lb/ton [05] 0.02 0.08 unknown [05] 0.02 0.08 0.02 0.08SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Bromoform 3.90E-05 lb/ton [05] 0.01 0.04 unknown [05] 0.01 0.04 0.01 0.04SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Cadmium 5.10E-05 lb/ton [05] 0.01 0.06 unknown [05] 0.01 0.06 0.01 0.06SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Carbon disulfide 1.30E-04 lb/ton [05] 0.03 0.14 unknown [05] 0.03 0.14 0.03 0.14SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour 2-Chloroacetophenone 7.00E-06 lb/ton [05] 0.00 0.01 unknown [05] 0.00 0.01 0.00 0.01SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Chlorobenzene 2.20E-05 lb/ton [05] 0.01 0.02 unknown [05] 0.01 0.02 0.01 0.02SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Chloroform 5.90E-05 lb/ton [05] 0.01 0.06 unknown [05] 0.01 0.06 0.01 0.06SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Chromium 2.60E-04 lb/ton [05] 0.07 0.29 unknown [05] 0.07 0.29 0.07 0.29SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Cobalt 1.00E-04 lb/ton [05] 0.03 0.11 unknown [05] 0.03 0.11 0.03 0.11SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Cumene 5.30E-06 lb/ton [05] 0.00 0.01 unknown [05] 0.00 0.01 0.00 0.01SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Cyanide Compounds (Cy 2.50E-03 lb/ton [05] 0.63 2.75 unknown [05] 0.63 2.75 0.63 2.75SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour 2,4-Dinitrotoluene 2.80E-07 lb/ton [05] 0.00 0.00 unknown [05] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Dimethyl sulfate 4.80E-05 lb/ton [05] 0.01 0.05 unknown [05] 0.01 0.05 0.01 0.05SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Ethylbenzene 9.40E-05 lb/ton [05] 0.02 0.10 unknown [05] 0.02 0.10 0.02 0.10SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Ethyl chloride 4.20E-05 lb/ton [05] 0.01 0.05 unknown [05] 0.01 0.05 0.01 0.05SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Ethylene dibromide 1.20E-06 lb/ton [05] 0.00 0.00 unknown [05] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Ethylene dichloride 4.00E-05 lb/ton [05] 0.01 0.04 unknown [05] 0.01 0.04 0.01 0.04SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Formaldehyde 2.40E-04 lb/ton [05] 0.06 0.26 unknown [05] 0.06 0.26 0.06 0.26SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Hexane 6.70E-05 lb/ton [05] 0.02 0.07 unknown [05] 0.02 0.07 0.02 0.07SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Isophorone 5.80E-04 lb/ton [05] 0.15 0.64 unknown [05] 0.15 0.64 0.15 0.64

SV 251 Tons/hour Hydrogen Fluoride 1.50E-01 lb/ton [05] 37.71 165.18 65.0% [05] 13.20 57.81 13.20 57.81SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Hydrogen Chloride 1.20E+00 lb/ton [05] 301.70 1,321.47 97.1% [05] 8.85 38.76 2.0E-03 lb/mmbtu [05] 8.85 38.76SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Manganese 4.90E-04 lb/ton [05] 0.12 0.54 unknown [05] 0.12 0.54 0.12 0.54SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Mercury 8.30E-05 lb/ton [05] 2.09E-02 9.14E-02 90% [05] 2.09E-03 9.14E-03 10.00 lb/yr [05] 2.09E-03 5.00E-03SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Methyl bromide 1.60E-04 lb/ton [05] 0.04 0.18 unknown [05] 0.04 0.18 0.04 0.18SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Methyl chloride 5.30E-04 lb/ton [05] 0.13 0.58 unknown [05] 0.13 0.58 0.13 0.58SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Methyl ethyl ketone 3.90E-04 lb/ton [05] 0.10 0.43 unknown [05] 0.10 0.43 0.10 0.43SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Methyl hydrazine 1.70E-04 lb/ton [05] 0.04 0.19 unknown [05] 0.04 0.19 0.04 0.19SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Methyl methacrylate 2.00E-05 lb/ton [05] 0.01 0.02 unknown [05] 0.01 0.02 0.01 0.02SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Methyl tert butyl ether 3.50E-05 lb/ton [05] 0.01 0.04 unknown [05] 0.01 0.04 0.01 0.04SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Methylene chloride 2.90E-04 lb/ton [05] 0.07 0.32 unknown [05] 0.07 0.32 0.07 0.32SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Naphthalene 1.30E-05 lb/ton [05] 0.00 0.01 unknown [05] 0.00 0.01 0.00 0.01SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Nickel 2.80E-04 lb/ton [05] 0.07 0.31 unknown [05] 0.07 0.31 0.07 0.31SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Phenol 1.60E-05 lb/ton [05] 0.00 0.02 unknown [05] 0.00 0.02 0.00 0.02SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Propionaldehyde 3.80E-04 lb/ton [05] 0.10 0.42 unknown [05] 0.10 0.42 0.10 0.42SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Selenium 1.30E-03 lb/ton [05] 0.33 1.43 unknown [05] 0.33 1.43 0.33 1.43SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Styrene 2.50E-05 lb/ton [05] 0.01 0.03 unknown [05] 0.01 0.03 0.01 0.03SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Tetrachloroethylene 4.30E-05 lb/ton [05] 0.01 0.05 unknown [05] 0.01 0.05 0.01 0.05SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour 1,1,1 - trichloroethane 2.00E-05 lb/ton [05] 0.01 0.02 unknown [05] 0.01 0.02 0.01 0.02SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Toluene 2.40E-04 lb/ton [05] 0.06 0.26 unknown [05] 0.06 0.26 0.06 0.26SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Xylenes 3.70E-05 lb/ton [05] 0.01 0.04 unknown [05] 0.01 0.04 0.01 0.04SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Vinyl acetate 7.60E-06 lb/ton [05] 0.00 0.01 unknown [05] 0.00 0.01 0.00 0.01

7/5/2017






SV EU


(MMBtu/hr)Data






SV 003 EU 003 4425 [05] Coal 251.4 Tons/hour Total PCDD/PCDF 1.76E-09 lbs/ton [28] 4.43E-07 1.94E-06 Unknown [28] 4.43E-07 1.94E-06SV 003 EU 003 4425 SV 005 Coal 251.42 Tons/hour 2,3,7,8-TCDD 1.43E-11 lbs/ton [28] 3.60E-09 1.57E-08 Unknown [28] 3.60E-09 1.57E-08SV 003 EU 003 4425 SV 005 Coal 251.42 Tons/hour Total TCDD 9.28E-11 lbs/ton [28] 2.33E-08 1.02E-07 Unknown [28] 2.33E-08 1.02E-07SV 003 EU 003 4425 SV 005 Coal 251.42 Tons/hour Total PeCDD 4.47E-11 lbs/ton [28] 1.12E-08 4.92E-08 Unknown [28] 1.12E-08 4.92E-08SV 003 EU 003 4425 SV 005 Coal 251.42 Tons/hour Total HxCDD 2.87E-11 lbs/ton [28] 7.22E-09 3.16E-08 Unknown [28] 7.22E-09 3.16E-08SV 003 EU 003 4425 SV 005 Coal 251.42 Tons/hour Total HpCDD 8.34E-11 lbs/ton [28] 2.10E-08 9.18E-08 Unknown [28] 2.10E-08 9.18E-08SV 003 EU 003 4425 SV 005 Coal 251.42 Tons/hour Total OCDD 4.16E-10 lbs/ton [28] 1.05E-07 4.58E-07 Unknown [28] 1.05E-07 4.58E-07SV 003 EU 003 4425 SV 005 Coal 251.42 Tons/hour Total PCDD 6.66E-10 lbs/ton [28] 1.67E-07 7.33E-07 Unknown [28] 1.67E-07 7.33E-07SV 003 EU 003 4425 SV 005 Coal 251.42 Tons/hour 2,3,7,8-TCDF 5.10E-11 lbs/ton [28] 1.28E-08 5.62E-08 Unknown [28] 1.28E-08 5.62E-08SV 003 EU 003 4425 SV 005 Coal 251.42 Tons/hour Total TCDF 4.04E-10 lbs/ton [28] 1.02E-07 4.45E-07 Unknown [28] 1.02E-07 4.45E-07SV 003 EU 003 4425 SV 005 Coal 251.42 Tons/hour Total PeCDF 3.53E-10 lbs/ton [28] 8.88E-08 3.89E-07 Unknown [28] 8.88E-08 3.89E-07SV 003 EU 003 4425 SV 005 Coal 251.42 Tons/hour Total HxCDF 1.92E-10 lbs/ton [28] 4.83E-08 2.11E-07 Unknown [28] 4.83E-08 2.11E-07SV 003 EU 003 4425 SV 005 Coal 251.42 Tons/hour Total HpCDF 7.68E-11 lbs/ton [28] 1.93E-08 8.46E-08 Unknown [28] 1.93E-08 8.46E-08SV 003 EU 003 4425 SV 005 Coal 251.42 Tons/hour Total OCDF 6.63E-11 lbs/ton [28] 1.67E-08 7.30E-08 Unknown [28] 1.67E-08 7.30E-08SV 003 EU 003 4425 SV 005 Coal 251.42 Tons/hour Total PCDF 1.09E-09 lbs/ton [28] 2.74E-07 1.20E-06 Unknown [28] 2.74E-07 1.20E-06SV 003 EU 003 4425 [05] Coal 251.4 Tons/hour Total PAH 2.08E-05 lbs/ton [29] 5.22E-03 2.29E-02 Unknown [29] 5.22E-03 2.29E-02SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Biphenyl 1.70E-06 lbs/ton [29] 4.27E-04 1.87E-03 Unknown [29] 4.27E-04 1.87E-03SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Acenaphthene 5.10E-07 lbs/ton [29] 1.28E-04 5.62E-04 Unknown [29] 1.28E-04 5.62E-04SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Acenaphthylene 2.50E-07 lbs/ton [29] 6.29E-05 2.75E-04 Unknown [29] 6.29E-05 2.75E-04SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Anthracene 2.10E-07 lbs/ton [29] 5.28E-05 2.31E-04 Unknown [29] 5.28E-05 2.31E-04SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Benzo(a)anthracene 8.00E-08 lbs/ton [29] 2.01E-05 8.81E-05 Unknown [29] 2.01E-05 8.81E-05SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Benzo(a)pyrene 3.80E-08 lbs/ton [29] 9.55E-06 4.18E-05 Unknown [29] 9.55E-06 4.18E-05SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Benzo(b,j,k)fluoranthen 1.10E-07 lbs/ton [29] 2.77E-05 1.21E-04 Unknown [29] 2.77E-05 1.21E-04SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Benzo(g,h,i)perylene 2.70E-08 lbs/ton [29] 6.79E-06 2.97E-05 Unknown [29] 6.79E-06 2.97E-05SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Chrysene 1.00E-07 lbs/ton [29] 2.51E-05 1.10E-04 Unknown [29] 2.51E-05 1.10E-04SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Fluoranthene 7.10E-07 lbs/ton [29] 1.79E-04 7.82E-04 Unknown [29] 1.79E-04 7.82E-04SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Fluorene 9.10E-07 lbs/ton [29] 2.29E-04 1.00E-03 Unknown [29] 2.29E-04 1.00E-03SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Indeno(1,2,3-cd)pyrene 6.10E-08 lbs/ton [29] 1.53E-05 6.72E-05 Unknown [29] 1.53E-05 6.72E-05SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Naphthalene 1.30E-05 lbs/ton [29] 3.27E-03 1.43E-02 Unknown [29] 3.27E-03 1.43E-02SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Phenanthrene 2.70E-06 lbs/ton [29] 6.79E-04 2.97E-03 Unknown [29] 6.79E-04 2.97E-03SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour Pyrene 3.30E-07 lbs/ton [29] 8.30E-05 3.63E-04 Unknown [29] 8.30E-05 3.63E-04SV 003 SV 003 SV 4425 SV 005 Coal SV 251 Tons/hour 5-Methyl chrysene 2.20E-08 lbs/ton [29] 5.53E-06 2.42E-05 Unknown [29] 5.53E-06 2.42E-05SV 003 EU 003 4425 [05] Coal 251.4 Tons/hour POM 2.40 lb/1012 Btu [30] 1.06E-02 4.65E-02 Unknown [30] 1.06E-02 4.65E-02SV 003 EU 003 0 [05] Natural Gas 0.0 MMscf/hr CO 8.40E+01 lb/MMscf [05] 0.00 0.00 0.0% [05] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr 0.00E+00 lb/MMscf [05] 0.00 0.00 0.0% [05] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Lead 5.0E-04 lb/MMscf [05] 0.00 0.00 0.0% [05] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr NOx 1.8E+02 lb/MMscf [05] 0.00 0.00 92.4% [05] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr PM 2.0E-01 lb/MMscf [05] 0.00 0.00 99.0% [05] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr PM10 5.2E-01 lb/MMscf [05] 0.00 0.00 #DIV/0! [05] #DIV/0! #DIV/0! #DIV/0! #DIV/0!SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr PM2.5 5.2E-01 lb/MMscf [05] 0.00 0.00 #DIV/0! [05] #DIV/0! #DIV/0! #DIV/0! #DIV/0!SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr SO2 6.0E-01 lb/MMscf [05] 0 0 97.5% [05] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Sulfuric Acid Mist 0.00E+00 lb/MMscf [05] 0.00 0.00 0.0% [05] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr VOC 5.50E+00 lb/MMscf [05] 0.00 0.00 0.0% [05] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr CO2 1.20E+05 lb/MMscf [05] 0 0 0.0% [05] 0.00 0 0 0SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr CH4 2.26E+00 lb/MMscf [05] 0.00 0.00 0.0% [05] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr N2O 2.26E-01 lb/MMscf [05] 0.00 0.00 0.0% [05] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr CO2-e 1.20E+05 lb/MMscf [05] 0 0 0.0% [05] 0.00 0 0 0SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr 2-Methylnaphthalene 2.40E-05 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr 3-Methylchloranthrene 1.80E-06 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr 7,12-Dimethylbenz(a)an 1.60E-05 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Acenaphthene 1.80E-06 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Acenaphthylene 1.80E-06 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Anthracene 2.40E-06 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Arsenic 2.00E-04 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Benzo(a)anthracene 1.80E-06 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Benzene 2.10E-03 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Benzo(a)pyrene 1.20E-06 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Benzo(b)fluoranthene 1.80E-06 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Benzo(g,h,i)perylene 1.20E-06 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Benzo(k)fluoranthene 1.80E-06 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Beryllium 1.20E-05 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Cadmium 1.10E-03 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Chromium 1.40E-03 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Chrysene 1.80E-06 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Cobalt 8.40E-05 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Dibenz(a,h)anthracene 1.20E-06 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Dichlorobenzene 1.20E-03 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Fluoranthene 3.00E-06 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Fluorene 2.80E-06 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Formaldehyde 7.50E-02 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Hexane 1.80E+00 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00



SV EU


(MMBtu/hr)Data






SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Indeno(1,2,3-cd)pyrene 1.80E-06 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Manganese 3.80E-04 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Mercury 2.60E-04 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Naphthalene 6.10E-04 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Nickel 2.10E-03 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Phenanthrene 1.70E-05 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Pyrene 5.00E-06 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Selenium 2.40E-05 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 000 SV 005 Natural Gas SV 000 MMscf/hr Toluene 3.40E-03 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 EU 003 480 [05] Natural Gas, Startup 0.471 MMscf/hr CO 8.40E+01 lb/MMscf [06] 39.53 173.14 0.0% [06] 39.53 173.14 39.53 173.14SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr 0.00E+00 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Lead 5.00E-04 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr NOx 1.78E+02 lb/MMscf [06] 83.53 365.86 0.0% [06] 83.53 365.86 83.53 365.86SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr PM 2.00E-01 lb/MMscf [06] 0.09 0.41 0.0% [06] 0.09 0.41 0.09 0.41SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr PM10 5.20E-01 lb/MMscf [06] 0.24 1.07 0.0% [06] 0.24 1.07 0.24 1.07SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr PM2.5 5.20E-01 lb/MMscf [06] 0.24 1.07 0.0% [06] 0.24 1.07 0.24 1.07SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr SO2 6.00E-01 lb/MMscf [06] 0.28 1.24 0.0% [06] 0.28 1.24 0.28 1.24SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr 0.00E+00 lb/MMscf [06] 0.00 0.00 0.0% [06] 0.00 0.00 0.00 0.00SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr VOC 5.50E+00 lb/MMscf [06] 2.59 11.34 0.0% [06] 2.59 11.34 2.59 11.34SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr CO2 1.20E+05 lb/MMscf [05] 56,489 247,422 0.0% [05] 56,489 247,422 56,489 247,422SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr CH4 2.26E+00 lb/MMscf [05] 1.06 4.66 0.0% [05] 1.06 4.66 1.06 4.66SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr N2O 2.26E-01 lb/MMscf [05] 0.11 0.47 0.0% [05] 0.11 0.47 0.11 0.47SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr CO2-e 1.20E+05 lb/MMscf [05] 56,547 247,678 0.0% [05] 56,547 247,678 56,547 247,678SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr 2-Methylnaphthalene 2.40E-05 lb/MMscf [06] 1.13E-05 4.95E-05 0.0% [06] 1.13E-05 4.95E-05 1.13E-05 4.95E-05SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr 3-Methylchloranthrene 1.80E-06 lb/MMscf [06] 8.47E-07 3.71E-06 0.0% [06] 8.47E-07 3.71E-06 8.47E-07 3.71E-06SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr 7,12-Dimethylbenz(a)an 1.60E-05 lb/MMscf [06] 7.53E-06 3.30E-05 0.0% [06] 7.53E-06 3.30E-05 7.53E-06 3.30E-05SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Acenaphthene 1.80E-06 lb/MMscf [06] 8.47E-07 3.71E-06 0.0% [06] 8.47E-07 3.71E-06 8.47E-07 3.71E-06SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Acenaphthylene 1.80E-06 lb/MMscf [06] 8.47E-07 3.71E-06 0.0% [06] 8.47E-07 3.71E-06 8.47E-07 3.71E-06SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Anthracene 2.40E-06 lb/MMscf [06] 1.13E-06 4.95E-06 0.0% [06] 1.13E-06 4.95E-06 1.13E-06 4.95E-06SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Arsenic 2.00E-04 lb/MMscf [06] 9.41E-05 4.12E-04 0.0% [06] 9.41E-05 4.12E-04 9.41E-05 4.12E-04SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Benzo(a)anthracene 1.80E-06 lb/MMscf [06] 8.47E-07 3.71E-06 0.0% [06] 8.47E-07 3.71E-06 8.47E-07 3.71E-06SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Benzene 2.10E-03 lb/MMscf [06] 9.88E-04 4.33E-03 0.0% [06] 9.88E-04 4.33E-03 9.88E-04 4.33E-03SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Benzo(a)pyrene 1.20E-06 lb/MMscf [06] 5.65E-07 2.47E-06 0.0% [06] 5.65E-07 2.47E-06 5.65E-07 2.47E-06SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Benzo(b)fluoranthene 1.80E-06 lb/MMscf [06] 8.47E-07 3.71E-06 0.0% [06] 8.47E-07 3.71E-06 8.47E-07 3.71E-06SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Benzo(g,h,i)perylene 1.20E-06 lb/MMscf [06] 5.65E-07 2.47E-06 0.0% [06] 5.65E-07 2.47E-06 5.65E-07 2.47E-06SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Benzo(k)fluoranthene 1.80E-06 lb/MMscf [06] 8.47E-07 3.71E-06 0.0% [06] 8.47E-07 3.71E-06 8.47E-07 3.71E-06SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Beryllium 1.20E-05 lb/MMscf [06] 5.65E-06 2.47E-05 0.0% [06] 5.65E-06 2.47E-05 5.65E-06 2.47E-05SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Cadmium 1.10E-03 lb/MMscf [06] 5.18E-04 2.27E-03 0.0% [06] 5.18E-04 2.27E-03 5.18E-04 2.27E-03SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Chromium 1.40E-03 lb/MMscf [06] 6.59E-04 2.89E-03 0.0% [06] 6.59E-04 2.89E-03 6.59E-04 2.89E-03SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Chrysene 1.80E-06 lb/MMscf [06] 8.47E-07 3.71E-06 0.0% [06] 8.47E-07 3.71E-06 8.47E-07 3.71E-06SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Cobalt 8.40E-05 lb/MMscf [06] 3.95E-05 1.73E-04 0.0% [06] 3.95E-05 1.73E-04 3.95E-05 1.73E-04SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Dibenz(a,h)anthracene 1.20E-06 lb/MMscf [06] 5.65E-07 2.47E-06 0.0% [06] 5.65E-07 2.47E-06 5.65E-07 2.47E-06SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Dichlorobenzene 1.20E-03 lb/MMscf [06] 5.65E-04 2.47E-03 0.0% [06] 5.65E-04 2.47E-03 5.65E-04 2.47E-03SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Fluoranthene 3.00E-06 lb/MMscf [06] 1.41E-06 6.18E-06 0.0% [06] 1.41E-06 6.18E-06 1.41E-06 6.18E-06SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Fluorene 2.80E-06 lb/MMscf [06] 1.32E-06 5.77E-06 0.0% [06] 1.32E-06 5.77E-06 1.32E-06 5.77E-06SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Formaldehyde 7.50E-02 lb/MMscf [06] 3.53E-02 1.55E-01 0.0% [06] 3.53E-02 1.55E-01 3.53E-02 1.55E-01SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Hexane 1.80E+00 lb/MMscf [06] 8.47E-01 3.71E+00 0.0% [06] 8.47E-01 3.71E+00 8.47E-01 3.71E+00SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Indeno(1,2,3-cd)pyrene 1.80E-06 lb/MMscf [06] 8.47E-07 3.71E-06 0.0% [06] 8.47E-07 3.71E-06 8.47E-07 3.71E-06SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Manganese 3.80E-04 lb/MMscf [06] 1.79E-04 7.83E-04 0.0% [06] 1.79E-04 7.83E-04 1.79E-04 7.83E-04SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Mercury 2.60E-04 lb/MMscf [06] 1.22E-04 5.36E-04 0.0% [06] 1.22E-04 5.36E-04 1.22E-04 5.36E-04SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Naphthalene 6.10E-04 lb/MMscf [06] 2.87E-04 1.26E-03 0.0% [06] 2.87E-04 1.26E-03 2.87E-04 1.26E-03SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Nickel 2.10E-03 lb/MMscf [06] 9.88E-04 4.33E-03 0.0% [06] 9.88E-04 4.33E-03 9.88E-04 4.33E-03SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Phenanthrene 1.70E-05 lb/MMscf [06] 8.00E-06 3.50E-05 0.0% [06] 8.00E-06 3.50E-05 8.00E-06 3.50E-05SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Pyrene 5.00E-06 lb/MMscf [06] 2.35E-06 1.03E-05 0.0% [06] 2.35E-06 1.03E-05 2.35E-06 1.03E-05SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Selenium 2.40E-05 lb/MMscf [06] 1.13E-05 4.95E-05 0.0% [06] 1.13E-05 4.95E-05 1.13E-05 4.95E-05SV 003 SV 003 SV 480 SV 005 Natural Gas, Startup SV 000 MMscf/hr Toluene 3.40E-03 lb/MMscf [06] 1.60E-03 7.01E-03 0.0% [06] 1.60E-03 7.01E-03 1.60E-03 7.01E-03SV 003 EU 003 CO 663.75 2,907.23 0.0% 663.75 2,907.23 663.75 2,907.23


Fluorides 22.76 99.68 65.0% 7.97 34.89 7.97 34.89


Lead 1.51 6.61 88.3% 0.18 0.78 0.18 0.78


NOx 1,810.23 7,928.80 85.3% 265.50 1,162.89 265.50 1,162.89


PM 17,674.86 77,415.88 99.6% 61.95 271.34 61.95 271.34


PM10 4,072.76 17,838.69 96.2% 154.88 678.35 154.88 678.35


PM2.5 1,068.03 4,677.99 85.5% 154.88 678.35 154.88 678.35




SV EU


(MMBtu/hr)Data







SO2 5,279.83 23,125.65 97.5% 132.75 581.45 132.75 581.45




VOC 15.09 66.07 0.0% 15.09 66.07 15.09 66.07


CO2 929,246 4,070,096 0.0% 929,246 4,070,096 929,246 4,070,096


CH4 105.19 460.75 0.0% 105.19 460.75 105.19 460.75


N2O 15.30 67.02 0.0% 15.30 67.02 15.30 67.02


CO2-e 936,435 4,101,586 0.0% 936,435 4,101,586 936,435 4,101,586




Benzene 3.27E-01 1.43E+00 unknown 3.27E-01 1.43E+00 3.27E-01 1.43E+00












Hexane 0.00E+00 0.00E+00 0.0% 0.00E+00 0.00E+00 0.00E+00 0.00E+00




Mercury 2.09E-02 9.14E-02 90.0% 2.09E-03 9.14E-03 2.09E-03 9.14E-03






Selenium 3.27E-01 1.43E+00 unknown 3.27E-01 1.43E+00 3.27E-01 1.43E+00

































SV EU


(MMBtu/hr)Data











































POM 1.06E-02 4.65E-02 Unknown 1.06E-02 4.65E-02




























Cyanide Compounds (Cyanide) 6.29E-01 2.75E+00 unknown 6.29E-01 2.75E+00 6.29E-01 2.75E+00









SV EU


(MMBtu/hr)Data





















Hydrogen Fluoride 3.77E+01 1.65E+02 65.0% 1.32E+01 5.78E+01 1.32E+01 5.78E+01




















































Chrysene 8.47E-07 3.71E-06 0.0% 8.47E-07 3.71E-06 8.47E-07 3.71E-06







SV EU


(MMBtu/hr)Data









Fluorene 1.32E-06 5.77E-06 0.0% 1.32E-06 5.77E-06 1.32E-06 5.77E-06






Pyrene 2.35E-06 1.03E-05 0.0% 2.35E-06 1.03E-05 2.35E-06 1.03E-05




SV EU


(MMBtu/hr)Data


Efficiency Source lb/hr tons/year Source lb/hr tons/yearSV 004 EU 004 6800 [07] Coal 386.4 Tons/hour CO 1.50E-01 lb/mmbtu [07] 1,020.00 4,467.60 0.0% [07] 1,020.00 4,467.60 0.15 lb/mmbtu [07] 1,020.00 4,467.60SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Fluorides 8.40E-02 lb/mmbtu [07] 571.20 2,501.86 90.0% [07] 57.12 250.19 0.0084 lb/mmbtu 57.12 250.19SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Lead 6.00E-03 lb/mmbtu [07] 40.80 178.70 99.9% [07] 0.03 0.12 0.03 0.12SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour NOx 7.20E+00 lb/ton [07] 2,781.82 12,184.36 70.7% [07] 816.00 3,574.08 0.120 lb/mmbtu [27] 816.00 3,574.08SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour PM 7.03E+01 lb/ton [07] 27,161.36 118,966.77 99.7% [07] 81.60 357.41 0.012 lb/mmbtu [27] 81.60 357.41SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour PM10 1.62E+01 lb/ton [07] 6,258.70 27,413.13 97.8% [07] 136.00 595.68 0.020 lb/mmbtu [07] 136.00 595.68SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour PM2.5 4.25E+00 lb/ton [07] 1,641.27 7,188.77 91.7% [07] 136.00 595.68 0.020 lb/mmbtu [07] 136.00 595.68SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour SO2 2.10E+01 lb/ton [07] 8,113.64 35,537.73 97.5% [07] 204.00 893.52 0.030 lb/mmbtu [27] 2,600.00 893.52SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Sulfuric Acid Mist 6.11E-02 lb/ton [07] 23.61 103.41 96.4% [07] 0.85 3.72 2.20E-03 lb/ton 0.85 3.72SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour VOC 6.00E-02 lb/ton [07] 23.18 101.54 0.0% [07] 23.18 101.54 23.18 101.54SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour CO2 3.70E+03 lb/ton [07] 1,427,993 6,254,610 0.0% [07] 1,427,993 6,254,610 1,427,993 6,254,610SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour CH4 4.18E-01 lb/ton [07] 161.65 708.04 0.0% [07] 161.65 708.04 161.65 708.04SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour N2O 6.09E-02 lb/ton [07] 23.51 102.99 0.0% [07] 23.51 102.99 23.51 102.99SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour CO2-e 3.72E+03 lb/ton [07] 1,439,042 6,303,002 0.0% [07] 1,439,042 6,303,002 1,439,042 6,303,002SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Acetaldehyde 5.70E-04 lb/ton [07] 0.22 0.96 unknown [07] 0.22 0.96 0.22 0.96SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Acetophenone 1.50E-05 lb/ton [07] 0.01 0.03 unknown [07] 0.01 0.03 0.01 0.03SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Acrolein 2.90E-04 lb/ton [07] 0.11 0.49 unknown [07] 0.11 0.49 0.11 0.49SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Antimony 1.80E-05 lb/ton [07] 0.01 0.03 unknown [07] 0.01 0.03 0.01 0.03SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Arsenic 4.10E-04 lb/ton [07] 0.16 0.69 unknown [07] 0.16 0.69 0.16 0.69SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Benzene 1.30E-03 lb/ton [07] 0.50 2.20 unknown [07] 0.50 2.20 0.50 2.20SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Benzyl chloride 7.00E-04 lb/ton [07] 0.27 1.18 unknown [07] 0.27 1.18 0.27 1.18SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Beryllium 2.10E-05 lb/ton [07] 0.01 0.04 unknown [07] 0.01 0.04 0.01 0.04SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Biphenyl 1.70E-06 lb/ton [07] 0.00 0.00 unknown [07] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour bis(2-Ethylhexyl)phthala 7.30E-05 lb/ton [07] 0.03 0.12 unknown [07] 0.03 0.12 0.03 0.12SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Bromoform 3.90E-05 lb/ton [07] 0.02 0.07 unknown [07] 0.02 0.07 0.02 0.07SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Cadmium 5.10E-05 lb/ton [07] 0.02 0.09 unknown [07] 0.02 0.09 0.02 0.09SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Carbon disulfide 1.30E-04 lb/ton [07] 0.05 0.22 unknown [07] 0.05 0.22 0.05 0.22SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour 2-Chloroacetophenone 7.00E-06 lb/ton [07] 0.00 0.01 unknown [07] 0.00 0.01 0.00 0.01SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Chlorobenzene 2.20E-05 lb/ton [07] 0.01 0.04 unknown [07] 0.01 0.04 0.01 0.04SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Chloroform 5.90E-05 lb/ton [07] 0.02 0.10 unknown [07] 0.02 0.10 0.02 0.10SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Chromium 2.60E-04 lb/ton [07] 0.10 0.44 unknown [07] 0.10 0.44 0.10 0.44SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Cobalt 1.00E-04 lb/ton [07] 0.04 0.17 unknown [07] 0.04 0.17 0.04 0.17SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Cumene 5.30E-06 lb/ton [07] 0.00 0.01 unknown [07] 0.00 0.01 0.00 0.01SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Cyanide Compounds (Cy 2.50E-03 lb/ton [07] 0.97 4.23 unknown [07] 0.97 4.23 0.97 4.23SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour 2,4-Dinitrotoluene 2.80E-07 lb/ton [07] 0.00 0.00 unknown [07] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Dimethyl sulfate 4.80E-05 lb/ton [07] 0.02 0.08 unknown [07] 0.02 0.08 0.02 0.08SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Ethylbenzene 9.40E-05 lb/ton [07] 0.04 0.16 unknown [07] 0.04 0.16 0.04 0.16SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Ethyl chloride 4.20E-05 lb/ton [07] 0.02 0.07 unknown [07] 0.02 0.07 0.02 0.07SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Ethylene dibromide 1.20E-06 lb/ton [07] 0.00 0.00 unknown [07] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Ethylene dichloride 4.00E-05 lb/ton [07] 0.02 0.07 unknown [07] 0.02 0.07 0.02 0.07SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Formaldehyde 2.40E-04 lb/ton [07] 0.09 0.41 unknown [07] 0.09 0.41 0.09 0.41SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Hexane 6.70E-05 lb/ton [07] 0.03 0.11 unknown [07] 0.03 0.11 0.03 0.11SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Isophorone 5.80E-04 lb/ton [07] 0.22 0.98 unknown [07] 0.22 0.98 0.22 0.98

SV 386 Tons/hour Hydrogen Fluoride 1.50E-01 lb/ton [07] 57.95 253.84 90% [07] 5.80 25.38 5.80 25.38SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Hydrogen Chloride 1.20E+00 lb/ton [07] 463.64 2,030.73 97.1% [07] 13.60 59.57 2.0E-03 lb/mmbtu [07] 13.60 59.57SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Manganese 4.90E-04 lb/ton [07] 0.19 0.83 unknown [07] 0.19 0.83 0.19 0.83SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Mercury 8.30E-05 lb/ton [07] 3.21E-02 1.40E-01 90% [07] 3.21E-03 1.40E-02 26.00 lb/yr [07] 3.21E-03 1.30E-02SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Methyl bromide 1.60E-04 lb/ton [07] 0.06 0.27 unknown [07] 0.06 0.27 0.06 0.27SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Methyl chloride 5.30E-04 lb/ton [07] 0.20 0.90 unknown [07] 0.20 0.90 0.20 0.90SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Methyl ethyl ketone 3.90E-04 lb/ton [07] 0.15 0.66 unknown [07] 0.15 0.66 0.15 0.66SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Methyl hydrazine 1.70E-04 lb/ton [07] 0.07 0.29 unknown [07] 0.07 0.29 0.07 0.29SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Methyl methacrylate 2.00E-05 lb/ton [07] 0.01 0.03 unknown [07] 0.01 0.03 0.01 0.03SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Methyl tert butyl ether 3.50E-05 lb/ton [07] 0.01 0.06 unknown [07] 0.01 0.06 0.01 0.06SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Methylene chloride 2.90E-04 lb/ton [07] 0.11 0.49 unknown [07] 0.11 0.49 0.11 0.49SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Naphthalene 1.30E-05 lb/ton [07] 0.01 0.02 unknown [07] 0.01 0.02 0.01 0.02SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Nickel 2.80E-04 lb/ton [07] 0.11 0.47 unknown [07] 0.11 0.47 0.11 0.47SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Phenol 1.60E-05 lb/ton [07] 0.01 0.03 unknown [07] 0.01 0.03 0.01 0.03SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Propionaldehyde 3.80E-04 lb/ton [07] 0.15 0.64 unknown [07] 0.15 0.64 0.15 0.64SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Selenium 1.30E-03 lb/ton [07] 0.50 2.20 unknown [07] 0.50 2.20 0.50 2.20SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Styrene 2.50E-05 lb/ton [07] 0.01 0.04 unknown [07] 0.01 0.04 0.01 0.04SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Tetrachloroethylene 4.30E-05 lb/ton [07] 0.02 0.07 unknown [07] 0.02 0.07 0.02 0.07SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour 1,1,1 - trichloroethane 2.00E-05 lb/ton [07] 0.01 0.03 unknown [07] 0.01 0.03 0.01 0.03SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Toluene 2.40E-04 lb/ton [07] 0.09 0.41 unknown [07] 0.09 0.41 0.09 0.41SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Xylenes 3.70E-05 lb/ton [07] 0.01 0.06 unknown [07] 0.01 0.06 0.01 0.06SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Vinyl acetate 7.60E-06 lb/ton [07] 0.00 0.01 unknown [07] 0.00 0.01 0.00 0.01

Limited Emissions



7/18/2017

Fuel Information Emission Factor Uncontrolled Emissions Controls



SV EU


(MMBtu/hr)Data



Limited Emissions


Controlled EmissionsFuel Information Emission Factor Uncontrolled Emissions Controls

SV 004 EU 004 6800 [07] Coal 386.4 Tons/hour Total PCDD/PCDF 2.44E-07 lbs/ton [28] 9.43E-05 4.13E-04 Unknown [28] 9.43E-05 4.13E-04SV 004 EU 004 6800 SV 007 Coal 386.36 Tons/hour 2,3,7,8-TCDD 1.43E-11 lbs/ton [28] 5.53E-09 2.42E-08 Unknown [28] 5.53E-09 2.42E-08SV 004 EU 004 6800 SV 007 Coal 386.36 Tons/hour Total TCDD 3.93E-10 lbs/ton [28] 1.52E-07 6.65E-07 Unknown [28] 1.52E-07 6.65E-07SV 004 EU 004 6800 SV 007 Coal 386.36 Tons/hour Total PeCDD 7.06E-10 lbs/ton [28] 2.73E-07 1.19E-06 Unknown [28] 2.73E-07 1.19E-06SV 004 EU 004 6800 SV 007 Coal 386.36 Tons/hour Total HxCDD 3.00E-09 lbs/ton [28] 1.16E-06 5.08E-06 Unknown [28] 1.16E-06 5.08E-06SV 004 EU 004 6800 SV 007 Coal 386.36 Tons/hour Total HpCDD 1.00E-08 lbs/ton [28] 3.86E-06 1.69E-05 Unknown [28] 3.86E-06 1.69E-05SV 004 EU 004 6800 SV 007 Coal 386.36 Tons/hour Total OCDD 2.87E-08 lbs/ton [28] 1.11E-05 4.86E-05 Unknown [28] 1.11E-05 4.86E-05SV 004 EU 004 6800 SV 007 Coal 386.36 Tons/hour Total PCDD 4.28E-08 lbs/ton [28] 1.65E-05 7.24E-05 Unknown [28] 1.65E-05 7.24E-05SV 004 EU 004 6800 SV 007 Coal 386.36 Tons/hour 2,3,7,8-TCDF ND lbs/ton [28] 0.00E+00 0.00E+00 Unknown [28] 0.00E+00 0.00E+00SV 004 EU 004 6800 SV 007 Coal 386.36 Tons/hour Total TCDF 2.49E-09 lbs/ton [28] 9.62E-07 4.21E-06 Unknown [28] 9.62E-07 4.21E-06SV 004 EU 004 6800 SV 007 Coal 386.36 Tons/hour Total PeCDF 4.84E-09 lbs/ton [28] 1.87E-06 8.19E-06 Unknown [28] 1.87E-06 8.19E-06SV 004 EU 004 6800 SV 007 Coal 386.36 Tons/hour Total HxCDF 1.27E-08 lbs/ton [28] 4.91E-06 2.15E-05 Unknown [28] 4.91E-06 2.15E-05SV 004 EU 004 6800 SV 007 Coal 386.36 Tons/hour Total HpCDF 4.39E-08 lbs/ton [28] 1.70E-05 7.43E-05 Unknown [28] 1.70E-05 7.43E-05SV 004 EU 004 6800 SV 007 Coal 386.36 Tons/hour Total OCDF 1.37E-07 lbs/ton [28] 5.29E-05 2.32E-04 Unknown [28] 5.29E-05 2.32E-04SV 004 EU 004 6800 SV 007 Coal 386.36 Tons/hour Total PCDF 2.01E-07 lbs/ton [28] 7.77E-05 3.40E-04 Unknown [28] 7.77E-05 3.40E-04SV 004 EU 004 6800 [07] Coal 386.4 Tons/hour Total PAH 2.08E-05 lbs/ton [29] 8.02E-03 3.51E-02 Unknown [29] 8.02E-03 3.51E-02SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Biphenyl 1.70E-06 lbs/ton [29] 6.57E-04 2.88E-03 Unknown [29] 6.57E-04 2.88E-03SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Acenaphthene 5.10E-07 lbs/ton [29] 1.97E-04 8.63E-04 Unknown [29] 1.97E-04 8.63E-04SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Acenaphthylene 2.50E-07 lbs/ton [29] 9.66E-05 4.23E-04 Unknown [29] 9.66E-05 4.23E-04SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Anthracene 2.10E-07 lbs/ton [29] 8.11E-05 3.55E-04 Unknown [29] 8.11E-05 3.55E-04SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Benzo(a)anthracene 8.00E-08 lbs/ton [29] 3.09E-05 1.35E-04 Unknown [29] 3.09E-05 1.35E-04SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Benzo(a)pyrene 3.800E-08 lbs/ton [29] 1.47E-05 6.43E-05 Unknown [29] 1.47E-05 6.43E-05SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Benzo(b,j,k)fluoranthen 1.10E-07 lbs/ton [29] 4.25E-05 1.86E-04 Unknown [29] 4.25E-05 1.86E-04SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Benzo(g,h,i)perylene 2.70E-08 lbs/ton [29] 1.04E-05 4.57E-05 Unknown [29] 1.04E-05 4.57E-05SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Chrysene 1.00E-07 lbs/ton [29] 3.86E-05 1.69E-04 Unknown [29] 3.86E-05 1.69E-04SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Fluoranthene 7.10E-07 lbs/ton [29] 2.74E-04 1.20E-03 Unknown [29] 2.74E-04 1.20E-03SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Fluorene 9.10E-07 lbs/ton [29] 3.52E-04 1.54E-03 Unknown [29] 3.52E-04 1.54E-03SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Indeno(1,2,3-cd)pyrene 6.10E-08 lbs/ton [29] 2.36E-05 1.03E-04 Unknown [29] 2.36E-05 1.03E-04SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Naphthalene 1.30E-05 lbs/ton [29] 5.02E-03 2.20E-02 Unknown [29] 5.02E-03 2.20E-02SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Phenanthrene 2.70E-06 lbs/ton [29] 1.04E-03 4.57E-03 Unknown [29] 1.04E-03 4.57E-03SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour Pyrene 3.30E-07 lbs/ton [29] 1.28E-04 5.58E-04 Unknown [29] 1.28E-04 5.58E-04SV 004 SV 004 SV 6800 SV 007 Coal SV 386 Tons/hour 5-Methyl chrysene 2.20E-08 lbs/ton [29] 8.50E-06 3.72E-05 Unknown [29] 8.50E-06 3.72E-05SV 004 EU 004 6800 [07] Coal 386.4 Tons/hour POM 2.40 lb/1012 Btu [30] 1.63E-02 7.15E-02 Unknown [30] 1.63E-02 7.15E-02SV 004 EU 004 776 [07] Natural Gas, Startup 0.761 MMscf/hr CO 8.40E+01 lb/MMscf [08] 63.91 279.91 0.0% [08] 63.91 279.91 63.91 279.91SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Lead 5.000E-04 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr NOx 1.13E+02 lb/MMscf [08] 86.12 377.21 0.0% [08] 86.12 377.21 86.12 377.21SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr PM 2.00E-01 lb/MMscf [08] 0.15 0.67 0.0% [08] 0.15 0.67 0.15 0.67SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr PM10 5.20E-01 lb/MMscf [08] 0.40 1.73 0.0% [08] 0.40 1.73 0.40 1.73SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr PM2.5 5.20E-01 lb/MMscf [08] 0.40 1.73 0.0% [08] 0.40 1.73 0.40 1.73SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr SO2 6.00E-01 lb/MMscf [08] 0.46 2.00 0.0% [08] 0.46 2.00 0.46 2.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr VOC 5.50E+00 lb/MMscf [08] 4.18 18.33 0.0% [08] 4.18 18.33 4.18 18.33SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr CO2 1.20E+05 lb/MMscf [08] 91,324 399,999 0.0% [08] 91,324 399,999 91,324 399,999SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr CH4 2.26E+00 lb/MMscf [08] 1.72 7.54 0.0% [08] 1.72 7.54 1.72 7.54SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr N2O 2.26E-01 lb/MMscf [08] 0.17 0.75 0.0% [08] 0.17 0.75 0.17 0.75SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr CO2-e 1.20E+05 lb/MMscf [08] 91,418 400,412 0.0% [08] 91,418 400,412 91,418 400,412SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr 2-Methylnaphthalene 2.40E-05 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr 3-Methylchloranthrene 1.80E-06 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr 7,12-Dimethylbenz(a)an 1.60E-05 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Acenaphthene 1.80E-06 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Acenaphthylene 1.80E-06 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Anthracene 2.40E-06 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Arsenic 2.00E-04 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Benzo(a)anthracene 1.80E-06 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Benzene 2.10E-03 lb/MMscf [08] 0.00 0.01 0.0% [08] 0.00 0.01 0.00 0.01SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Benzo(a)pyrene 1.20E-06 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Benzo(b)fluoranthene 1.80E-06 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Benzo(g,h,i)perylene 1.20E-06 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Benzo(k)fluoranthene 1.80E-06 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Beryllium 1.20E-05 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Cadmium 1.10E-03 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Chromium 1.40E-03 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Chrysene 1.80E-06 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Cobalt 8.40E-05 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Dibenz(a,h)anthracene 1.20E-06 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Dichlorobenzene 1.20E-03 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Fluoranthene 3.00E-06 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Fluorene 2.80E-06 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Formaldehyde 7.50E-02 lb/MMscf [08] 0.06 0.25 0.0% [08] 0.06 0.25 0.06 0.25SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Hexane 1.80E+00 lb/MMscf [08] 1.37 6.00 0.0% [08] 1.37 6.00 1.37 6.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Indeno(1,2,3-cd)pyrene 1.80E-06 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Manganese 3.80E-04 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00



SV EU


(MMBtu/hr)Data



Limited Emissions



SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Mercury 2.60E-04 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Naphthalene 6.10E-04 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Nickel 2.10E-03 lb/MMscf [08] 0.00 0.01 0.0% [08] 0.00 0.01 0.00 0.01SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Phenanthrene 1.70E-05 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Pyrene 5.00E-06 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Selenium 2.40E-05 lb/MMscf [08] 0.00 0.00 0.0% [08] 0.00 0.00 0.00 0.00SV 004 SV 004 SV 776 SV 007 Natural Gas, Startup SV 001 MMscf/hr Toluene 3.40E-03 lb/MMscf [08] 0.00 0.01 0.0% [08] 0.00 0.01 0.00 0.01SV 004 EU 004 CO 1,020.00 4,467.60 0.0% 1,020.00 4,467.60 1,020.00 4,467.60


Fluorides 571.20 2,501.86 90.0% 57.12 250.19 57.12 250.19


Lead 40.80 178.70 99.9% 0.03 0.12 0.03 0.12


NOx 2,781.82 12,184.36 70.7% 816.00 3,574.08 816.00 3,574.08


PM 27,161.36 118,966.77 99.7% 81.60 357.41 81.60 357.41


PM10 6,258.70 27,413.13 97.8% 136.00 595.68 136.00 595.68


PM2.5 1,641.27 7,188.77 91.7% 136.00 595.68 136.00 595.68


SO2 8,113.64 35,537.73 97.5% 204.00 893.52 2,600.00 893.52




VOC 23.18 101.54 0.0% 23.18 101.54 23.18 101.54


CO2 1,427,993 6,254,610 0.0% 1,427,993 6,254,610 1,427,993 6,254,610


CH4 161.65 708.04 0.0% 161.65 708.04 161.65 708.04


N2O 23.51 102.99 0.0% 23.51 102.99 23.51 102.99


CO2-e 1,439,042 6,303,002 0.0% 1,439,042 6,303,002 1,439,042 6,303,002




Benzene 5.02E-01 2.20E+00 unknown 5.02E-01 2.20E+00 5.02E-01 2.20E+00












Hexane 0.00E+00 0.00E+00 0.0% 0.00E+00 0.00E+00 0.00E+00 0.00E+00




Mercury 3.21E-02 1.40E-01 90.0% 3.21E-03 1.40E-02 3.21E-03 1.40E-02






Selenium 5.02E-01 2.20E+00 unknown 5.02E-01 2.20E+00 5.02E-01 2.20E+00














SV EU


(MMBtu/hr)Data



Limited Emissions












2,3,7,8-TCDF 0.00E+00 0.00E+00 Unknown 0.00E+00 0.00E+00
















































POM 1.63E-02 7.15E-02 Unknown 1.63E-02 7.15E-02










Benzyl chloride 2.70E-01 1.18E+00 unknown 2.70E-01 1.18E+00 2.70E-01 1.18E+00







SV EU


(MMBtu/hr)Data



Limited Emissions
















Cyanide Compounds (Cyanide) 9.66E-01 4.23E+00 unknown 9.66E-01 4.23E+00 9.66E-01 4.23E+00






















Hydrogen Fluoride 5.80E+01 2.54E+02 90.0% 5.80E+00 2.54E+01 5.80E+00 2.54E+01







































SV EU


(MMBtu/hr)Data



Limited Emissions


















Chrysene 1.37E-06 6.00E-06 0.0% 1.37E-06 6.00E-06 1.37E-06 6.00E-06








Fluorene 2.13E-06 9.33E-06 0.0% 2.13E-06 9.33E-06 2.13E-06 9.33E-06






Pyrene 3.80E-06 1.67E-05 0.0% 3.80E-06 1.67E-05 3.80E-06 1.67E-05

H:\MP BEC\draft documents\Public Notice Documents w_App & Attach\TSD Attachments Public Notice\TSD Att 1 - MPCA Calculations.xlsxCooling Towers


Minnesota PowerBoswell Permit Renewal ApplicationPotential to Emit Calculations - Cooling TowersUpdate:

SV EU

Maximum Rated Capacity(gal/min)

Data Source Unit Name Pollutant Source lb/hr tons/year

Control Efficiency Source lb/hr tons/year Source lb/hr tons/year

SV 005 EU 005 160000 [09] Unit 4 Cooling Tower PM 3.00E-06 lb/gal [09] 28.84 126.33 0.0% [09] 28.84 126.33 28.84 126.33SV 005 SV 005 SV 160000 SV 009 Unit 4 Cooling Tower PM10 2.02E-06 lb/gal [09] 19.42 85.04 0.0% [09] 19.42 85.04 19.42 85.04SV 005 SV 005 SV 160000 SV 009 Unit 4 Cooling Tower PM2.5 6.50E-09 lb/gal [09] 0.06 0.27 0.0% [09] 0.06 0.27 0.06 0.27SV 006 EU 006 103000 [10] Unit 3 Cooling Tower PM 3.00E-06 lb/gal [09] 18.57 81.32 0.0% [10] 18.57 81.32 18.57 81.32SV 006 SV 006 SV 103000 SV 010 Unit 3 Cooling Tower PM10 2.02E-06 lb/gal [09] 12.50 54.75 0.0% [10] 12.50 54.75 12.50 54.75SV 006 SV 006 SV 103000 SV 010 Unit 3 Cooling Tower PM2.5 6.50E-09 lb/gal [09] 0.04 0.18 0.0% [10] 0.04 0.18 0.04 0.18

Limited Emissions

Emission Factor Emission Limit

6/20/2016

Emission Factor Uncontrolled Emissions Controls Controlled Emissions

H:\MP BEC\draft documents\Public Notice Documents w_App & Attach\TSD Attachments Public Notice\TSD Att 1 - MPCA Calculations.xlsxGenerators


Minnesota PowerBoswell Permit Renewal ApplicationPotential to Emit Calculations - GeneratorsUpdate:

SV EU


(MMBtu/hr)Data

Source Fuel Unit Name Pollutant Source lb/hr tons/yearControl

Efficiency Source lb/hr tons/year Source lb/hr tons/yearSV 022 EU 023 3.2 [12] Diesel Fuel Emergency Generator 3-APCE 358 kw PM 0.2 g/kwhr [12] 1.58E-01 3.95E-02 0.0% 1.58E-01 3.95E-02 1.58E-01 3.95E-02SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 kw PM10 0.2 g/kwhr [12] 1.58E-01 3.95E-02 0.0% 1.58E-01 3.95E-02 1.58E-01 3.95E-02SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 kw PM2.5 0.2 g/kwhr [12] 1.58E-01 3.95E-02 0.0% 1.58E-01 3.95E-02 1.58E-01 3.95E-02SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Lead 9.00E-06 lb/mmbtu [12] 2.88E-05 7.20E-06 0.0% 2.88E-05 7.20E-06 2.88E-05 7.20E-06SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 SO2 1.52E-03 lb/mmbtu [12] 4.85E-03 1.21E-03 0.0% 4.85E-03 1.21E-03 4.85E-03 1.21E-03SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 H2SO4 3.48E-05 lb/mmbtu [12] 1.11E-04 2.78E-05 0.0% 1.11E-04 2.78E-05 1.11E-04 2.78E-05SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 NOx 4 g/kwhr [12] 3.16E+00 7.89E-01 0.0% 3.16E+00 7.89E-01 3.16E+00 7.89E-01SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 VOC 4 g/kwhr [12] 3.16E+00 7.89E-01 0.0% 3.16E+00 7.89E-01 3.16E+00 7.89E-01SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 kw CO 3 g/kwhr [12] 2.37E+00 5.92E-01 0.0% 2.37 0.59 2.37 0.59SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 CO2 165.60 lb/mmbtu [12] 529.91 132.48 0.0% 529.91 132.48 529.91 132.48SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 CH4 0.007 lb/mmbtu [12] 0.02 0.01 0.0% 0.02 0.01 0.02 0.01SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 N2O 0.001 lb/mmbtu [12] 0.00 0.00 0.0% 0.00 0.00 0.00 0.00SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 CO2-e 1.66E+02 lb/mmbtu [12] 531.70 132.92 0.0% 531.70 132.92 531.70 132.92SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Benzene 9.33E-04 lb/mmbtu [12] 2.99E-03 7.46E-04 0.0% 2.99E-03 7.46E-04 2.99E-03 7.46E-04SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Toluene 4.09E-04 lb/mmbtu [12] 1.31E-03 3.27E-04 0.0% 1.31E-03 3.27E-04 1.31E-03 3.27E-04SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Xylenes 2.85E-04 lb/mmbtu [12] 9.12E-04 2.28E-04 0.0% 9.12E-04 2.28E-04 9.12E-04 2.28E-04SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 1,3-Butadiene 3.91E-05 lb/mmbtu [12] 1.25E-04 3.13E-05 0.0% 1.25E-04 3.13E-05 1.25E-04 3.13E-05SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Formaldehyde 1.18E-03 lb/mmbtu [12] 3.78E-03 9.44E-04 0.0% 3.78E-03 9.44E-04 3.78E-03 9.44E-04SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Acetaldehyde 7.67E-04 lb/mmbtu [12] 2.45E-03 6.14E-04 0.0% 2.45E-03 6.14E-04 2.45E-03 6.14E-04SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Acrolein 9.25E-05 lb/mmbtu [12] 2.96E-04 7.40E-05 0.0% 2.96E-04 7.40E-05 2.96E-04 7.40E-05SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Naphthalene 8.48E-05 lb/mmbtu [12] 2.71E-04 6.78E-05 0.0% 2.71E-04 6.78E-05 2.71E-04 6.78E-05SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Acenaphthylene 5.06E-06 lb/mmbtu [12] 1.62E-05 4.05E-06 0.0% 1.62E-05 4.05E-06 1.62E-05 4.05E-06SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Acenaphthene 1.42E-06 lb/mmbtu [12] 4.54E-06 1.14E-06 0.0% 4.54E-06 1.14E-06 4.54E-06 1.14E-06SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Fluorene 2.92E-05 lb/mmbtu [12] 9.34E-05 2.34E-05 0.0% 9.34E-05 2.34E-05 9.34E-05 2.34E-05SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Phenanthrene 2.94E-05 lb/mmbtu [12] 9.41E-05 2.35E-05 0.0% 9.41E-05 2.35E-05 9.41E-05 2.35E-05SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Anthracene 0.00000187 lb/mmbtu [12] 5.98E-06 1.50E-06 0.0% 5.98E-06 1.50E-06 5.98E-06 1.50E-06SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Fluoranthene 0.00000761 lb/mmbtu [12] 2.44E-05 6.09E-06 0.0% 2.44E-05 6.09E-06 2.44E-05 6.09E-06SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Pyrene 0.00000478 lb/mmbtu [12] 1.53E-05 3.82E-06 0.0% 1.53E-05 3.82E-06 1.53E-05 3.82E-06SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Benzo(a)anthracene 0.00000168 lb/mmbtu [12] 5.38E-06 1.34E-06 0.0% 5.38E-06 1.34E-06 5.38E-06 1.34E-06SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Chrysene 3.53E-07 lb/mmbtu [12] 1.13E-06 2.82E-07 0.0% 1.13E-06 2.82E-07 1.13E-06 2.82E-07SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Benzo(b)fluoranthene 9.91E-08 lb/mmbtu [12] 3.17E-07 7.93E-08 0.0% 3.17E-07 7.93E-08 3.17E-07 7.93E-08SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Benzo(k)fluoranthene 1.55E-07 lb/mmbtu [12] 4.96E-07 1.24E-07 0.0% 4.96E-07 1.24E-07 4.96E-07 1.24E-07SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Benzo(a)pyrene 1.88E-07 lb/mmbtu [12] 6.02E-07 1.50E-07 0.0% 6.02E-07 1.50E-07 6.02E-07 1.50E-07SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Indeno(1,2,3-cd)pyrene 3.75E-07 lb/mmbtu [12] 1.20E-06 3.00E-07 0.0% 1.20E-06 3.00E-07 1.20E-06 3.00E-07SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Dibenz(a,h)anthracene 5.83E-07 lb/mmbtu [12] 1.87E-06 4.66E-07 0.0% 1.87E-06 4.66E-07 1.87E-06 4.66E-07SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Benzo(g,h,i)perylene 4.89E-07 lb/mmbtu [12] 1.56E-06 3.91E-07 0.0% 1.56E-06 3.91E-07 1.56E-06 3.91E-07SV 022 SV 023 SV 003 SV 012 Diesel Fuel Emergency Generator 3-APCE 358 Total HAP 3.88E-03 lb/mmbtu [12] 1.24E-02 3.11E-03 0.0% 1.24E-02 3.11E-03 1.24E-02 3.11E-03SV 033 EU 033 2.79 [12] Diesel Fuel Emergency Generator 3-250kw 297 kw PM 0.2 g/kwhr [12] 1.31E-01 3.27E-02 0.0% 1.31E-01 3.27E-02 1.31E-01 3.27E-02SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 kw PM10 0.2 g/kwhr [12] 1.31E-01 3.27E-02 0.0% 1.31E-01 3.27E-02 1.31E-01 3.27E-02SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 kw PM2.5 0.2 g/kwhr [12] 1.31E-01 3.27E-02 0.0% 1.31E-01 3.27E-02 1.31E-01 3.27E-02SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Lead 9.00E-06 lb/mmbtu [12] 2.51E-05 6.27E-06 0.0% 2.51E-05 6.27E-06 2.51E-05 6.27E-06SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 SO2 1.52E-03 lb/mmbtu [12] 4.22E-03 1.06E-03 0.0% 4.22E-03 1.06E-03 4.22E-03 1.06E-03SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 H2SO4 3.48E-05 lb/mmbtu [12] 9.70E-05 2.42E-05 0.0% 9.70E-05 2.42E-05 9.70E-05 2.42E-05SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 NOx 4 g/kwhr [12] 2.62E+00 6.55E-01 0.0% 2.62E+00 6.55E-01 2.62E+00 6.55E-01SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 VOC 4 g/kwhr [12] 2.62E+00 6.55E-01 0.0% 2.62E+00 6.55E-01 2.62E+00 6.55E-01SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 CO 3 g/kwhr [12] 1.96E+00 4.91E-01 0.0% 1.96E+00 4.91E-01 1.96E+00 4.91E-01SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 CO2 165.60 lb/mmbtu [12] 461.55 115.39 0.0% 461.55 115.39 461.55 115.39SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 CH4 0.007 lb/mmbtu [12] 0.02 0.00 0.0% 0.02 0.00 0.02 0.00SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 N2O 0.001 lb/mmbtu [12] 0.00 0.00 0.0% 0.00 0.00 0.00 0.00SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 CO2-e 1.66E+02 lb/mmbtu [12] 463.11 115.78 0.0% 463.11 115.78 463.11 115.78SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Benzene 9.33E-04 lb/mmbtu [12] 2.60E-03 6.50E-04 0.0% 2.60E-03 6.50E-04 2.60E-03 6.50E-04SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Toluene 4.09E-04 lb/mmbtu [12] 1.14E-03 2.85E-04 0.0% 1.14E-03 2.85E-04 1.14E-03 2.85E-04SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Xylenes 2.85E-04 lb/mmbtu [12] 7.94E-04 1.99E-04 0.0% 7.94E-04 1.99E-04 7.94E-04 1.99E-04SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 1,3-Butadiene 3.91E-05 lb/mmbtu [12] 1.09E-04 2.72E-05 0.0% 1.09E-04 2.72E-05 1.09E-04 2.72E-05SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Formaldehyde 1.18E-03 lb/mmbtu [12] 3.29E-03 8.22E-04 0.0% 3.29E-03 8.22E-04 3.29E-03 8.22E-04SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Acetaldehyde 7.67E-04 lb/mmbtu [12] 2.14E-03 5.34E-04 0.0% 2.14E-03 5.34E-04 2.14E-03 5.34E-04SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Acrolein 9.25E-05 lb/mmbtu [12] 2.58E-04 6.45E-05 0.0% 2.58E-04 6.45E-05 2.58E-04 6.45E-05SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Naphthalene 8.48E-05 lb/mmbtu [12] 2.36E-04 5.91E-05 0.0% 2.36E-04 5.91E-05 2.36E-04 5.91E-05SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Acenaphthylene 5.06E-06 lb/mmbtu [12] 1.41E-05 3.53E-06 0.0% 1.41E-05 3.53E-06 1.41E-05 3.53E-06SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Acenaphthene 1.42E-06 lb/mmbtu [12] 3.96E-06 9.89E-07 0.0% 3.96E-06 9.89E-07 3.96E-06 9.89E-07SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Fluorene 2.92E-05 lb/mmbtu [12] 8.14E-05 2.03E-05 0.0% 8.14E-05 2.03E-05 8.14E-05 2.03E-05SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Phenanthrene 2.94E-05 lb/mmbtu [12] 8.19E-05 2.05E-05 0.0% 8.19E-05 2.05E-05 8.19E-05 2.05E-05SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Anthracene 0.00000187 lb/mmbtu [12] 5.21E-06 1.30E-06 0.0% 5.21E-06 1.30E-06 5.21E-06 1.30E-06

Limited Emissions

Rated Mechanical Output Emission Factor Emission Limit

1/31/2017




SV EU


(MMBtu/hr)Data



Limited Emissions



SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Fluoranthene 0.00000761 lb/mmbtu [12] 2.12E-05 5.30E-06 0.0% 2.12E-05 5.30E-06 2.12E-05 5.30E-06SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Pyrene 0.00000478 lb/mmbtu [12] 1.33E-05 3.33E-06 0.0% 1.33E-05 3.33E-06 1.33E-05 3.33E-06SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Benzo(a)anthracene 0.00000168 lb/mmbtu [12] 4.68E-06 1.17E-06 0.0% 4.68E-06 1.17E-06 4.68E-06 1.17E-06SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Chrysene 3.53E-07 lb/mmbtu [12] 9.84E-07 2.46E-07 0.0% 9.84E-07 2.46E-07 9.84E-07 2.46E-07SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Benzo(b)fluoranthene 9.91E-08 lb/mmbtu [12] 2.76E-07 6.91E-08 0.0% 2.76E-07 6.91E-08 2.76E-07 6.91E-08SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Benzo(k)fluoranthene 1.55E-07 lb/mmbtu [12] 4.32E-07 1.08E-07 0.0% 4.32E-07 1.08E-07 4.32E-07 1.08E-07SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Benzo(a)pyrene 1.88E-07 lb/mmbtu [12] 5.24E-07 1.31E-07 0.0% 5.24E-07 1.31E-07 5.24E-07 1.31E-07SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Indeno(1,2,3-cd)pyrene 3.75E-07 lb/mmbtu [12] 1.05E-06 2.61E-07 0.0% 1.05E-06 2.61E-07 1.05E-06 2.61E-07SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Dibenz(a,h)anthracene 5.83E-07 lb/mmbtu [12] 1.62E-06 4.06E-07 0.0% 1.62E-06 4.06E-07 1.62E-06 4.06E-07SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Benzo(g,h,i)perylene 4.89E-07 lb/mmbtu [12] 1.36E-06 3.41E-07 0.0% 1.36E-06 3.41E-07 1.36E-06 3.41E-07SV 033 SV 033 SV 003 SV 012 Diesel Fuel Emergency Generator 3-250kw 297 Total HAP 0.004 lb/mmbtu [12] 1.08E-02 2.71E-03 0.0% 1.08E-02 2.71E-03 1.08E-02 2.71E-03SV 034 EU 034 14.64 [13] Diesel Fuel Unit 4 Emergency Generator 2,206 hp PM 0.030 g/hphr [13] 1.46E-01 3.65E-02 0.0% 1.46E-01 3.65E-02 1.46E-01 3.65E-02SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp PM10 0.025 g/hphr [13] 1.20E-01 3.00E-02 0.0% 1.20E-01 3.00E-02 1.20E-01 3.00E-02SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp PM2.5 0.024 g/hphr [13] 1.16E-01 2.91E-02 0.0% 1.16E-01 2.91E-02 1.16E-01 2.91E-02SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp Lead 0.000009 lb/mmbtu [13] 1.32E-04 3.29E-05 0.0% 1.32E-04 3.29E-05 1.32E-04 3.29E-05SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp SO2 0.001515 lb/mmbtu [13] 2.22E-02 5.55E-03 0.0% 2.22E-02 5.55E-03 2.22E-02 5.55E-03SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp H2SO4 3.48E-05 lb/mmbtu [13] 5.09E-04 1.27E-04 0.0% 5.09E-04 1.27E-04 5.09E-04 1.27E-04SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp NOx 5.08 g/hphr [13] 2.47E+01 6.18E+00 0.0% 2.47E+01 6.18E+00 2.47E+01 6.18E+00SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp VOC 0.11 g/hphr [13] 5.35E-01 1.34E-01 0.0% 5.35E-01 1.34E-01 5.35E-01 1.34E-01SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp CO 0.44 g/hphr [13] 2.14E+00 5.35E-01 0.0% 2.14E+00 5.35E-01 2.14E+00 5.35E-01SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp CO2 165.60 lb/mmbtu [13] 2,424.98 606.25 0.0% 2,424.98 606.25 2,424.98 606.25SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp CH4 0.007 lb/mmbtu [13] 0.10 0.02 0.0% 0.10 0.02 0.10 0.02SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp N2O 0.001 lb/mmbtu [13] 0.02 0.00 0.0% 0.02 0.00 0.02 0.00SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp CO2-e 1.66E+02 lb/mmbtu [13] 2,433.18 608.29 0.0% 2,433.18 608.29 2,433.18 608.29SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp Benzene 7.76E-04 lb/mmbtu [13] 1.14E-02 2.84E-03 0.0% 1.14E-02 2.84E-03 1.14E-02 2.84E-03SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp Toluene 2.81E-04 lb/mmbtu [13] 4.11E-03 1.03E-03 0.0% 4.11E-03 1.03E-03 4.11E-03 1.03E-03SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp Xylenes 1.93E-04 lb/mmbtu [13] 2.83E-03 7.07E-04 0.0% 2.83E-03 7.07E-04 2.83E-03 7.07E-04SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp Formaldehyde 7.89E-05 lb/mmbtu [13] 1.16E-03 2.89E-04 0.0% 1.16E-03 2.89E-04 1.16E-03 2.89E-04SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp Acetaldehyde 2.52E-05 lb/mmbtu [13] 3.69E-04 9.23E-05 0.0% 3.69E-04 9.23E-05 3.69E-04 9.23E-05SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 hp Acrolein 7.88E-06 lb/mmbtu [13] 1.15E-04 2.88E-05 0.0% 1.15E-04 2.88E-05 1.15E-04 2.88E-05SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Naphthalene 1.30E-04 lb/mmbtu [13] 1.90E-03 4.76E-04 0.0% 1.90E-03 4.76E-04 1.90E-03 4.76E-04SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Acenaphthylene 9.23E-06 lb/mmbtu [13] 1.35E-04 3.38E-05 0.0% 1.35E-04 3.38E-05 1.35E-04 3.38E-05SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Acenaphthene 4.68E-06 lb/mmbtu [13] 6.85E-05 1.71E-05 0.0% 6.85E-05 1.71E-05 6.85E-05 1.71E-05SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Fluorene 1.28E-05 lb/mmbtu [13] 1.87E-04 4.69E-05 0.0% 1.87E-04 4.69E-05 1.87E-04 4.69E-05SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Phenanthrene 4.08E-05 lb/mmbtu [13] 5.97E-04 1.49E-04 0.0% 5.97E-04 1.49E-04 5.97E-04 1.49E-04SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Anthracene 1.23E-06 lb/mmbtu [13] 1.80E-05 4.50E-06 0.0% 1.80E-05 4.50E-06 1.80E-05 4.50E-06SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Fluoranthene 4.03E-06 lb/mmbtu [13] 5.90E-05 1.48E-05 0.0% 5.90E-05 1.48E-05 5.90E-05 1.48E-05SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Pyrene 3.71E-06 lb/mmbtu [13] 5.43E-05 1.36E-05 0.0% 5.43E-05 1.36E-05 5.43E-05 1.36E-05SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Benzo(a)anthracene 6.22E-07 lb/mmbtu [13] 9.11E-06 2.28E-06 0.0% 9.11E-06 2.28E-06 9.11E-06 2.28E-06SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Chrysene 1.53E-06 lb/mmbtu [13] 2.24E-05 5.60E-06 0.0% 2.24E-05 5.60E-06 2.24E-05 5.60E-06SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Benzo(b)fluoranthene 1.11E-06 lb/mmbtu [13] 1.63E-05 4.06E-06 0.0% 1.63E-05 4.06E-06 1.63E-05 4.06E-06SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Benzo(k)fluoranthene 2.18E-07 lb/mmbtu [13] 3.19E-06 7.98E-07 0.0% 3.19E-06 7.98E-07 3.19E-06 7.98E-07SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Benzo(a)pyrene 2.57E-07 lb/mmbtu [13] 3.76E-06 9.41E-07 0.0% 3.76E-06 9.41E-07 3.76E-06 9.41E-07SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Indeno(1,2,3-cd)pyrene 4.14E-07 lb/mmbtu [13] 6.06E-06 1.52E-06 0.0% 6.06E-06 1.52E-06 6.06E-06 1.52E-06SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Dibenz(a,h)anthracene 3.46E-07 lb/mmbtu [13] 5.07E-06 1.27E-06 0.0% 5.07E-06 1.27E-06 5.07E-06 1.27E-06SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Benzo(g,h,i)perylene 5.56E-07 lb/mmbtu [13] 8.14E-06 2.04E-06 0.0% 8.14E-06 2.04E-06 8.14E-06 2.04E-06SV 034 SV 034 SV 015 SV 013 Diesel Fuel Unit 4 Emergency Generator 2,206 Total HAP 0.002 lb/mmbtu [13] 2.32E-02 5.79E-03 0.0% 2.32E-02 5.79E-03 2.32E-02 5.79E-03Totals PM 4.35E-01 1.09E-01 4.35E-01 1.09E-01 4.35E-01 1.09E-01Totals SV 000 PM10 4.09E-01 1.02E-01 4.09E-01 1.02E-01 4.09E-01 1.02E-01Totals SV 000 PM2.5 4.05E-01 1.01E-01 4.05E-01 1.01E-01 4.05E-01 1.01E-01

Lead 1.86E-04 4.64E-05 1.86E-04 4.64E-05 1.86E-04 4.64E-05Totals SV 000 SO2 3.13E-02 7.81E-03 3.13E-02 7.81E-03 3.13E-02 7.81E-03

H2SO4 7.18E-04 1.79E-04 7.18E-04 1.79E-04 7.18E-04 1.79E-04SV 000 SV 000 NOx 3.05E+01 7.62E+00 3.05E+01 7.62E+00 3.05E+01 7.62E+00Totals SV 000 VOC 6.31E+00 1.58E+00 6.31E+00 1.58E+00 6.31E+00 1.58E+00SV 000 SV 000 CO 6.47E+00 1.62E+00 6.47E+00 1.62E+00 6.47E+00 1.62E+00Totals SV 000 CO2 3,416.43 854.11 3,416.43 854.11 3,416.43 854.11SV 000 SV 000 CH4 0.14 0.03 0.14 0.03 0.14 0.03Totals SV 000 N2O 0.03 0.01 0.03 0.01 0.03 0.01SV 000 SV 000 CO2-e 3,427.98 856.99 3,427.98 856.99 3,427.98 856.99Totals SV 000 Benzene 1.69E-02 4.24E-03 1.69E-02 4.24E-03 1.69E-02 4.24E-03SV 000 SV 000 Toluene 6.56E-03 1.64E-03 6.56E-03 1.64E-03 6.56E-03 1.64E-03Totals SV 000 Xylenes 4.53E-03 1.13E-03 4.53E-03 1.13E-03 4.53E-03 1.13E-03SV 000 SV 000 1,3-Butadiene 2.34E-04 5.85E-05 2.34E-04 5.85E-05 2.34E-04 5.85E-05Totals SV 000 Formaldehyde 8.22E-03 2.06E-03 8.22E-03 2.06E-03 8.22E-03 2.06E-03SV 000 SV 000 Acetaldehyde 4.96E-03 1.24E-03 4.96E-03 1.24E-03 4.96E-03 1.24E-03Totals SV 000 Acrolein 6.69E-04 1.67E-04 6.69E-04 1.67E-04 6.69E-04 1.67E-04SV 000 SV 000 Naphthalene 2.41E-03 6.03E-04 2.41E-03 6.03E-04 2.41E-03 6.03E-04Totals SV 000 Acenaphthylene 1.65E-04 4.14E-05 1.65E-04 4.14E-05 1.65E-04 4.14E-05SV 000 SV 000 Acenaphthene 7.70E-05 1.93E-05 7.70E-05 1.93E-05 7.70E-05 1.93E-05



SV EU


(MMBtu/hr)Data



Limited Emissions



Totals SV 000 Fluorene 3.62E-04 9.06E-05 3.62E-04 9.06E-05 3.62E-04 9.06E-05SV 000 SV 000 Phenanthrene 7.73E-04 1.93E-04 7.73E-04 1.93E-04 7.73E-04 1.93E-04Totals SV 000 Anthracene 2.92E-05 7.30E-06 2.92E-05 7.30E-06 2.92E-05 7.30E-06SV 000 SV 000 Fluoranthene 1.05E-04 2.61E-05 1.05E-04 2.61E-05 1.05E-04 2.61E-05Totals SV 000 Pyrene 8.29E-05 2.07E-05 8.29E-05 2.07E-05 8.29E-05 2.07E-05SV 000 SV 000 Benzo(a)anthracene 1.92E-05 4.79E-06 1.92E-05 4.79E-06 1.92E-05 4.79E-06Totals SV 000 Chrysene 2.45E-05 6.13E-06 2.45E-05 6.13E-06 2.45E-05 6.13E-06SV 000 SV 000 Benzo(b)fluoranthene 1.68E-05 4.21E-06 1.68E-05 4.21E-06 1.68E-05 4.21E-06Totals SV 000 Benzo(k)fluoranthene 4.12E-06 1.03E-06 4.12E-06 1.03E-06 4.12E-06 1.03E-06SV 000 SV 000 Benzo(a)pyrene 4.89E-06 1.22E-06 4.89E-06 1.22E-06 4.89E-06 1.22E-06Totals SV 000 Indeno(1,2,3-cd)pyrene 8.31E-06 2.08E-06 8.31E-06 2.08E-06 8.31E-06 2.08E-06SV 000 SV 000 Dibenz(a,h)anthracene 8.56E-06 2.14E-06 8.56E-06 2.14E-06 8.56E-06 2.14E-06Totals SV 000 Benzo(g,h,i)perylene 1.11E-05 2.77E-06 1.11E-05 2.77E-06 1.11E-05 2.77E-06SV 000 SV 000 Total HAP 4.64E-02 1.16E-02 4.64E-02 1.16E-02 4.64E-02 1.16E-02

H:\MP BEC\draft documents\Public Notice Documents w_App & Attach\TSD Attachments Public Notice\TSD Att 1 - MPCA Calculations.xlsxMaterial Handling


Minnesota PowerBoswell Permit Renewal ApplicationPotential to Emit Calculations - Material Handling SourcesUpdate:

SV EU CE


UnitsData

Source Unit Name Pollutant Source lb/hr tons/yearControl

Efficiency Source lb/hr tons/year Source lb/hr tons/yearSV 011 EU 011 CE 007 800 ton/hr [14] PM 2.00E-02 lb/ton [14] 16.00 70.08 99.0% [14] 0.16 0.70 6,574,977 ton/yr [23] 0.16 0.66SV 011 EU 011 SV 800 ton/hr SV 014 PM10 6.00E-03 lb/ton [14] 4.80 21.02 93.0% [14] 0.34 1.47 6,574,977 ton/yr [23] 0.34 1.38SV 011 EU 011 SV 800 ton/hr SV 014 DC-8 PM2.5 6.00E-03 lb/ton [14] 4.80 21.02 93.0% [14] 0.34 1.47 6,574,977 ton/yr [23] 0.34 1.38SV 011 EU 011 SV 800 ton/hr SV 014 Lead 1.16E-07 lb/ton [14] 9.28E-05 4.06E-04 99.0% [14] 9.28E-07 4.06E-06 6,574,977 ton/yr [23] 9.28E-07 3.81E-06SV 012 EU 012 CE 008 1000 ton/hr [14] PM 2.00E-02 lb/ton [14] 20.00 87.60 99.0% [14] 0.20 0.88 6,574,977 ton/yr [23] 0.20 0.66SV 012 EU 012 SV 1000 ton/hr SV 014 PM10 6.00E-03 lb/ton [14] 6.00 26.28 93.0% [14] 0.42 1.84 6,574,977 ton/yr [23] 0.42 1.38SV 012 EU 012 SV 1000 ton/hr SV 014 DC-14 PM2.5 6.00E-03 lb/ton [14] 6.00 26.28 93.0% [14] 0.42 1.84 6,574,977 ton/yr [23] 0.42 1.38SV 012 EU 012 SV 1000 ton/hr SV 014 Lead 1.16E-07 lb/ton [14] 1.16E-04 5.08E-04 99.0% [14] 1.16E-06 5.08E-06 6,574,977 ton/yr [23] 1.16E-06 3.81E-06SV 013 EU 013 CE 009 6.34 ton/hr [15] Fly Ash Silo PM 7.30E-01 lb/ton [15] 4.63 20.28 99.0% [15] 0.05 0.20 0.05 0.20SV 013 EU 013 CE 009 SV 006 ton/hr SV 015 Fly Ash Silo PM10 4.70E-01 lb/ton [15] 2.98 13.06 93.0% [15] 0.21 0.91 0.21 0.91SV 013 EU 013 CE 009 SV 006 ton/hr SV 015 Fly Ash Silo PM2.5 4.70E-01 lb/ton [15] 2.98 13.06 93.0% [15] 0.21 0.91 0.21 0.91SV 013 EU 013 CE 009 SV 006 ton/hr SV 015 Fly Ash Silo Lead 4.47E-06 lb/ton [15] 2.83E-05 1.24E-04 99.0% [15] 2.83E-07 1.24E-06 2.83E-07 1.24E-06SV 014 EU 014 CE 010 6.34 ton/hr [15] Fly Ash Hoppers #1/#2 PM 7.30E-01 lb/ton [15] 4.63 20.28 99.0% [15] 0.05 0.20 0.05 0.20SV 014 EU 014 SV 006 ton/hr SV 015 Fly Ash Hoppers #1/#2 PM10 4.70E-01 lb/ton [15] 2.98 13.06 93.0% [15] 0.21 0.91 0.21 0.91SV 014 EU 014 SV 006 ton/hr SV 015 Fly Ash Hoppers #1/#2 PM2.5 4.70E-01 lb/ton [15] 2.98 13.06 93.0% [15] 0.21 0.91 0.21 0.91SV 014 EU 014 SV 006 ton/hr SV 015 Fly Ash Hoppers #1/#2 Lead 4.47E-06 lb/ton [15] 2.83E-05 1.24E-04 99.0% [15] 2.83E-07 1.24E-06 2.83E-07 1.24E-06SV 015 EU 015 CE 013 2500 dscfm [16] Unit 3 Activated Carbon Silo PM 1.00E+00 gr/dscf [16] 21.43 93.86 99.0% [16] 0.21 0.94 0.21 0.94SV 015 EU 015 SV 2500 dscfm SV 016 Unit 3 Activated Carbon Silo PM10 1.00E+00 gr/dscf [16] 21.43 93.86 99.0% [16] 0.21 0.94 0.21 0.94SV 015 EU 015 SV 2500 dscfm SV 016 Unit 3 Activated Carbon Silo PM2.5 1.00E+00 gr/dscf [16] 21.43 93.86 93.0% [16] 1.50 6.57 1.50 6.57

SV 017 EU 017 CE 015 16.574 ton/hr [14] Fly Ash Silo A PM 7.30E-01 lb/ton [14] 12.10 52.99 99.0% [14] 0.12 0.53 0.12 0.53SV 017 EU 017 SV 017 ton/hr SV 014 Fly Ash Silo A PM10 4.70E-01 lb/ton [14] 7.79 34.12 93.0% [14] 0.55 2.39 0.55 2.39SV 017 EU 017 SV 017 ton/hr SV 014 Fly Ash Silo A PM2.5 4.70E-01 lb/ton [14] 7.79 34.12 54.0% [14] 3.58 15.69 3.58 15.69SV 017 EU 017 SV 017 ton/hr SV 014 Fly Ash Silo A Lead 4.47E-06 lb/ton [14] 7.40E-05 3.24E-04 99.0% [14] 7.40E-07 3.24E-06 7.40E-07 3.24E-06SV 017 EU 042 CE 015 69.801 ton/hr [17] Fly Ash Silo A - Loadout PM 3.92E-01 lb/ton [17] 27.33 28.43 79.0% [17] 5.74 5.97 5.74 5.97SV 017 EU 042 145,186.3 ton/yr SV 017 Fly Ash Silo A - Loadout PM10 1.85E-01 lb/ton [17] 12.93 13.44 74.0% [17] 3.36 3.50 3.36 3.50SV 017 EU 042 SV 017 Fly Ash Silo A - Loadout PM2.5 2.80E-02 lb/ton [17] 1.96 2.04 43.0% [17] 1.12 1.16 1.12 1.16SV 017 EU 042 SV 017 Fly Ash Silo A - Loadout Lead 2.40E-06 lb/ton [17] 1.67E-04 1.74E-04 79.0% [17] 3.51E-05 3.65E-05 3.51E-05 3.65E-05SV 018 EU 018 CE 044 69.801 ton/hr [17] Fly Ash Loadout Building PM 7.83E-02 lb/ton [17] 5.47 5.69 79.0% [17] 1.15 1.19 1.15 1.19SV 018 EU 018 145,186.3 ton/yr SV 017 Fly Ash Loadout Building PM10 3.70E-02 lb/ton [17] 2.59 2.69 74.0% [17] 0.67 0.70 0.67 0.70SV 018 EU 018 SV 145186 ton/yr SV 017 Fly Ash Loadout Building PM2.5 5.61E-03 lb/ton [17] 0.39 0.41 43.0% [17] 0.22 0.23 0.22 0.23SV 018 EU 018 SV 145186 ton/yr SV 017 Fly Ash Loadout Building Lead 4.79E-07 lb/ton [17] 3.35E-05 3.48E-05 79.0% [17] 7.03E-06 7.31E-06 7.03E-06 7.31E-06SV 019 EU 019 CE 016 2000 dscfm [18] Limestone Silo PM 5.00E-01 gr/dscf [18] 8.57 37.54 99.0% [18] 0.09 0.38 0.09 0.38SV 019 EU 019 SV 2000 dscfm SV 018 Limestone Silo PM10 5.00E-01 gr/dscf [18] 8.57 37.54 99.0% [18] 0.09 0.38 0.09 0.38SV 019 EU 019 SV 2000 dscfm SV 018 Limestone Silo PM2.5 5.00E-01 gr/dscf [18] 8.57 37.54 93.0% [18] 0.60 2.63 0.60 2.63

SV 020 EU 020 CE 017 3300 dscfm [18] Limestone Day Silo #1 PM 5.00E-01 gr/dscf [18] 14.14 61.95 99.0% [18] 0.14 0.62 0.14 0.62SV 020 EU 020 SV 3300 dscfm SV 018 Limestone Day Silo #1 PM10 5.00E-01 gr/dscf [18] 14.14 61.95 99.0% [18] 0.14 0.62 0.14 0.62SV 020 EU 020 SV 3300 dscfm SV 018 Limestone Day Silo #1 PM2.5 5.00E-01 gr/dscf [18] 14.14 61.95 93.0% [18] 0.99 4.34 0.99 4.34

SV 021 EU 021 CE 018 3300 dscfm [18] Limestone Day Silo #2 PM 5.00E-01 gr/dscf [18] 14.14 61.95 99.0% [18] 0.14 0.62 0.14 0.62SV 021 EU 021 SV 3300 dscfm SV 018 Limestone Day Silo #2 PM10 5.00E-01 gr/dscf [18] 14.14 61.95 99.0% [18] 0.14 0.62 0.14 0.62SV 021 EU 021 SV 3300 dscfm SV 018 Limestone Day Silo #2 PM2.5 5.00E-01 gr/dscf [18] 14.14 61.95 93.0% [18] 0.99 4.34 0.99 4.34

SV 024 EU 024 CE 032 2.43 ton/hr [19] Lime Storage Bin Vent PM 7.30E-01 lb/ton [19] 1.77 7.76 99.5% [19] 0.09 0.38 0.09 0.38SV 024 EU 024 0.005 gr/dscf SV 019 Lime Storage Bin Vent PM10 4.70E-01 lb/ton [19] 1.14 5.00 99.5% [19] 0.09 0.38 0.09 0.38SV 024 EU 024 2,000 cfm SV 019 Lime Storage Bin Vent PM2.5 4.70E-01 lb/ton [19] 1.14 5.00 99.5% [19] 0.09 0.38 0.09 0.38

SV 025 EU 025 CE 033 0.49 ton/hr [19] Lime Day Bin A Bin Vent PM 7.30E-01 lb/ton [19] 0.35 1.55 99.5% [19] 0.06 0.28 0.06 0.28SV 025 EU 025 0.005 gr/dscf SV 019 Lime Day Bin A Bin Vent PM10 4.70E-01 lb/ton [19] 0.23 1.00 99.5% [19] 0.06 0.28 0.06 0.28SV 025 EU 025 1,500 cfm SV 019 Lime Day Bin A Bin Vent PM2.5 4.70E-01 lb/ton [19] 0.23 1.00 99.5% [19] 0.06 0.28 0.06 0.28

SV 026 EU 026 CE 034 0.49 ton/hr [19] Lime Day Bin B Bin Vent PM 7.30E-01 lb/ton [19] 0.35 1.55 99.5% [19] 0.06 0.28 0.06 0.28SV 026 EU 026 0.005 gr/dscf SV 019 Lime Day Bin B Bin Vent PM10 4.70E-01 lb/ton [19] 0.23 1.00 99.5% [19] 0.06 0.28 0.06 0.28SV 026 EU 026 1,500 cfm SV 019 Lime Day Bin B Bin Vent PM2.5 4.70E-01 lb/ton [19] 0.23 1.00 99.5% [19] 0.06 0.28 0.06 0.28

SV 027 EU 027 CE 035 0.49 ton/hr [19] Lime Day Bin C Bin Vent PM 7.30E-01 lb/ton [19] 0.35 1.55 99.5% [19] 0.06 0.28 0.06 0.28SV 027 EU 027 0.005 gr/dscf SV 019 Lime Day Bin C Bin Vent PM10 4.70E-01 lb/ton [19] 0.23 1.00 99.5% [19] 0.06 0.28 0.06 0.28SV 027 EU 027 1,500 cfm SV 019 Lime Day Bin C Bin Vent PM2.5 4.70E-01 lb/ton [19] 0.23 1.00 99.5% [19] 0.06 0.28 0.06 0.28

SV 028 EU 028 CE 036 0.49 ton/hr [19] Lime Day Bin D Bin Vent PM 7.30E-01 lb/ton [19] 0.35 1.55 99.5% [19] 0.06 0.28 0.06 0.28

Coal Handling - Crusher Building

Coal Handling - Crusher and Sampling House


5/18/2017

Emission Factor Uncontrolled Emissions Controls Controlled Emissions Limited Emissions

H:\MP BEC\draft documents\Public Notice Documents w_App & Attach\TSD Attachments Public Notice\TSD Att 1 - MPCA Calculations.xlsxMaterial Handling


SV EU CE


UnitsData

Source Unit Name Pollutant Source lb/hr tons/yearControl



Emission Factor Uncontrolled Emissions Controls Controlled Emissions Limited Emissions

SV 028 EU 028 0.005 gr/dscf SV 019 Lime Day Bin D Bin Vent PM10 4.70E-01 lb/ton [19] 0.23 1.00 99.5% [19] 0.06 0.28 0.06 0.28SV 028 EU 028 1,500 cfm SV 019 Lime Day Bin D Bin Vent PM2.5 4.70E-01 lb/ton [19] 0.23 1.00 99.5% [19] 0.06 0.28 0.06 0.28

SV 029 EU 029 CE 037 0.49 ton/hr [19] Lime Day Bin E Bin Vent PM 7.30E-01 lb/ton [19] 0.35 1.55 99.5% [19] 0.06 0.28 0.06 0.28SV 029 EU 029 0.005 gr/dscf SV 019 Lime Day Bin E Bin Vent PM10 4.70E-01 lb/ton [19] 0.23 1.00 99.5% [19] 0.06 0.28 0.06 0.28SV 029 EU 029 1,500 cfm SV 019 Lime Day Bin E Bin Vent PM2.5 4.70E-01 lb/ton [19] 0.23 1.00 99.5% [19] 0.06 0.28 0.06 0.28

SV 030 EU 030 CE 038 0.04 ton/hr [19] Unit 4 Activated Carbon Silo PM 7.30E-01 lb/ton [19] 0.03 0.14 99.5% [19] 0.04 0.19 0.04 0.19SV 030 EU 030 0.005 gr/dscf SV 019 Unit 4 Activated Carbon Silo PM10 4.70E-01 lb/ton [19] 0.02 0.09 99.5% [19] 0.04 0.19 0.04 0.19SV 030 EU 030 1,000 cfm SV 019 Unit 4 Activated Carbon Silo PM2.5 4.70E-01 lb/ton [19] 0.02 0.09 99.5% [19] 0.04 0.19 0.04 0.19

SV 031 EU 031 CE 039 30.54 ton/hr [19] Waste Ash Silo PM 7.30E-01 lb/ton [19] 22.30 97.66 99.75% [19] 0.33 1.45 0.33 1.45SV 031 EU 031 0.0025 gr/dscf SV 019 Waste Ash Silo PM10 4.70E-01 lb/ton [19] 14.36 62.88 99.75% [19] 0.33 1.45 0.33 1.45SV 031 EU 031 15,500 cfm SV 019 Waste Ash Silo PM2.5 4.70E-01 lb/ton [19] 14.36 62.88 99.75% [19] 0.33 1.45 0.33 1.45

Lead 4.47E-06 lb/ton [19] 1.36E-04 5.98E-04 99.75% [19] 3.41E-07 1.49E-06 3.41E-07 1.49E-06SV 032 EU 032 CE 040 30.54 ton/hr [19] Waste Ash Silo Truck Bay PM 7.30E-01 lb/ton [19] 22.30 97.66 99.7% [19] 0.50 2.20 0.50 2.20SV 032 EU 032 0.0025 gr/dscf SV 019 Waste Ash Silo Truck Bay PM10 4.70E-01 lb/ton [19] 14.36 62.88 99.7% [19] 0.50 2.20 0.50 2.20SV 032 EU 032 23,400 cfm SV 019 Waste Ash Silo Truck Bay PM2.5 4.70E-01 lb/ton [19] 14.36 62.88 99.7% [19] 0.50 2.20 0.50 2.20

Lead 4.47E-06 lb/ton [19] 1.36E-04 5.98E-04 99.7% [19] 4.09E-07 1.79E-06 4.09E-07 1.79E-06SV 036 EU 036 CE 046 3,500 ton/hr, loading [23] Lowering Well PM 2.39E-04 lb/ton [23] 1.08 1.57 99.0% [23] 0.01 0.02 0.01 0.02SV 036 EU 036 1,000 ton/hr, unloading DC-4 PM10 1.13E-04 lb/ton [23] 0.51 0.74 93.0% [23] 0.04 0.05 0.04 0.05SV 036 EU 036 6,574,977 ton/yr, loading PM2.5 1.71E-05 lb/ton [23] 0.08 0.11 93.0% [23] 0.01 0.01 0.01 0.01SV 036 EU 036 6,574,977 ton/yr, unloading Lead 1.39E-09 lb/ton [23] 6.24E-06 9.11E-06 99.0% [23] 6.24E-08 9.11E-08 6.24E-08 9.11E-08SV 041 EU 041 CE 051 1,800 ton/hr [23] Unit 4 Bunkers PM 2.39E-04 lb/ton [23] 0.43 0.40 99.0% [23] 0.00 0.00 0.00 0.00SV 041 EU 041 3,384,545 ton/yr DC-5 PM10 1.13E-04 lb/ton [23] 0.20 0.19 93.0% [23] 0.01 0.01 0.01 0.01SV 041 EU 041 PM2.5 1.71E-05 lb/ton [23] 0.03 0.03 93.0% [23] 0.00 0.00 0.00 0.00SV 041 EU 041 Lead 1.39E-09 lb/ton [23] 2.50E-06 2.35E-06 99.0% [23] 2.50E-08 2.35E-08 2.50E-08 2.35E-08SV 035 EU 035 CE 045 3,500 ton/hr [23] Rail Unloading PM 2.39E-04 lb/ton [23] 0.84 0.79 99.0% [23] 0.01 0.01 0.01 0.01SV 035 EU 035 6,574,977 ton/yr DC-7 PM10 1.13E-04 lb/ton [23] 0.40 0.37 93.0% [23] 0.03 0.03 0.03 0.03SV 035 EU 035 PM2.5 1.71E-05 lb/ton [23] 0.06 0.06 93.0% [23] 0.00 0.00 0.00 0.00SV 035 EU 035 Lead 1.39E-09 lb/ton [23] 4.85E-06 4.56E-06 99.0% [23] 4.85E-08 4.56E-08 4.85E-08 4.56E-08SV 038 EU 038 CE 048 800 ton/hr [23] C-9/C-10 Transfer House PM 2.39E-04 lb/ton [23] 0.19 0.79 99.0% [23] 0.00 0.01 0.00 0.01SV 038 EU 038 6,574,977 ton/yr DC-10 PM10 1.13E-04 lb/ton [23] 0.09 0.37 93.0% [23] 0.01 0.03 0.01 0.03SV 038 EU 038 PM2.5 1.71E-05 lb/ton [23] 0.01 0.06 93.0% [23] 0.00 0.00 0.00 0.00SV 038 EU 038 Lead 1.39E-09 lb/ton [23] 1.11E-06 4.56E-06 99.0% [23] 1.11E-08 4.56E-08 1.11E-08 4.56E-08SV 040 EU 040 CE 050 2,200 ton/hr [23] Units 1, 2, 3 Bunkers PM 2.39E-04 lb/ton [23] 0.53 0.38 99.0% [23] 0.01 0.00 0.01 0.00SV 040 EU 040 3,190,432 ton/yr DC-12 PM10 1.13E-04 lb/ton [23] 0.25 0.18 93.0% [23] 0.02 0.01 0.02 0.01SV 040 EU 040 PM2.5 1.71E-05 lb/ton [23] 0.04 0.03 93.0% [23] 0.00 0.00 0.00 0.00SV 040 EU 040 Lead 1.39E-09 lb/ton [23] 3.05E-06 2.21E-06 99.0% [23] 3.05E-08 2.21E-08 3.05E-08 2.21E-08SV 037 EU 037 CE 047 1,000 ton/hr [23] C-16/C-18 Transfer House PM 2.39E-04 lb/ton [23] 0.24 0.79 99.0% [23] 0.00 0.01 0.00 0.01SV 037 EU 037 6,574,977 ton/yr DC-16 PM10 1.13E-04 lb/ton [23] 0.11 0.37 93.0% [23] 0.01 0.03 0.01 0.03SV 037 EU 037 PM2.5 1.71E-05 lb/ton [23] 0.02 0.06 93.0% [23] 0.00 0.00 0.00 0.00SV 037 EU 037 Lead 1.39E-09 lb/ton [23] 1.39E-06 4.56E-06 99.0% [23] 1.39E-08 4.56E-08 1.39E-08 4.56E-08SV 039 EU 039 CE 049 3.50 ton/hr [15] Dust Tank PM 7.30E-01 lb/ton [15] 2.56 11.19 99.0% [15] 0.03 0.11 0.03 0.11SV 039 EU 039 30,660 ton/yr PM10 4.70E-01 lb/ton [15] 1.65 7.21 93.0% [15] 0.12 0.50 0.12 0.50SV 039 EU 039 PM2.5 4.70E-01 lb/ton [15] 1.65 7.21 93.0% [15] 0.12 0.50 0.12 0.50SV 039 EU 039 Lead 4.47E-06 lb/ton [15] 1.56E-05 6.85E-05 99.0% [15] 1.56E-07 6.85E-07 1.56E-07 6.85E-07SV 036 EU 047 CE 046 0 ton/hr, loading* [23] Storage Silos PM 2.39E-04 lb/ton [23] 0.19 0.79 99.0% [23] 0.00 0.01 0.00 0.01SV 036 EU 047 800 ton/hr, unloading DC-4 PM10 1.13E-04 lb/ton [23] 0.09 0.37 93.0% [23] 0.01 0.03 0.01 0.03SV 036 EU 047 0 ton/yr, loading* PM2.5 1.71E-05 lb/ton [23] 0.01 0.06 93.0% [23] 0.00 0.00 0.00 0.00SV 036 EU 047 6,574,977 ton/yr, unloading Lead 1.39E-09 lb/ton [23] 1.11E-06 4.56E-06 99.0% [23] 1.11E-08 4.56E-08 1.11E-08 4.56E-08

Totals PM 202.66 768.32 9.39 18.02 9.39 17.76PM10 132.66 524.61 7.85 20.58 7.85 20.03PM2.5 118.10 508.72 11.59 46.25 11.59 45.70Lead 8.49E-04 2.99E-03 4.67E-05 6.30E-05 4.67E-05 6.15E-05

*Loading of the Lowering Well (EU 036) and loading of the Storage Silos (EU 047) is not able to occur concurrently; therefore, loading emissions for EU 047 are included under EU 036.

Minnesota PowerBoswell Permit Renewal ApplicationPotential to Emit Calculations - Fugitive SourcesUpdate:

ID Description Pollutant Source lb/hr tons/year Control lb/hr tons/yearFS 001 Coal Stockpile - Wind Erosion 20.0 acre PM 0.80 ton/acre/yr [20] 3.66 16.02 0% 3.66 16.02 11.21FS 001 Active Coal Pile 20.0 PM10 0.40 ton/acre/yr 1.83 8.01 0% 1.83 8.01 5.61FS 001 20.0 PM2.5 0.06 ton/acre/yr 0.27 1.20 0% 0.27 1.20 0.84FS 001 20.0 Lead 4.65E-06 ton/acre/yr [31] 2.12E-05 9.29E-05 0% 2.12E-05 9.29E-05 6.50E-05FS 001 Coal Stockpile - Wind Erosion 6.58E-02 acre PM 0.80 ton/acre/yr [20] 0.01 0.05 0% 0.01 0.05FS 001 Crusted outer storage pile 0.1 PM10 0.40 ton/acre/yr 0.01 0.03 0% 0.01 0.03FS 001 0.1 PM2.5 0.06 ton/acre/yr 0.00 0.00 0% 0.00 0.00FS 001 0.1 Lead 4.65E-06 ton/acre/yr [31] 6.97E-08 3.05E-07 0% 6.97E-08 3.05E-07FS 001 Coal Stockpile - Wind Erosion 1.32E-01 acre PM 0.80 ton/acre/yr [20] 0.02 0.11 0% 0.02 0.11FS 001 Crusted long-term storage pile 0.1 PM10 0.40 ton/acre/yr 0.01 0.05 0% 0.01 0.05FS 001 0.1 PM2.5 0.06 ton/acre/yr 0.00 0.01 0% 0.00 0.01FS 001 0.1 Lead 4.65E-06 ton/acre/yr [31] 1.39E-07 6.11E-07 0% 1.39E-07 6.11E-07FS 002 Bottom Ash Pond - Wind Erosion 0.4 acre PM 0.00E+00 ton/acre/yr [20] 0.00 0.00 0% 0.00 0.00FS 002 Excavation Area 0.4 PM10 0.00E+00 ton/acre/yr 0.00 0.00 0% 0.00 0.00FS 002 0.4 PM2.5 0.00E+00 ton/acre/yr 0.00 0.00 0% 0.00 0.00FS 002 0.4 Lead 0.00E+00 ton/acre/yr [31] 0.00E+00 0.00E+00 0% 0.00E+00 0.00E+00FS 002 Bottom Ash Pond - Wind Erosion 38.0 acre PM 0.00 ton/acre/yr [20] 0.00 0.00 0% 0.00 0.00FS 002 Pond Area 38.0 PM10 0.00 ton/acre/yr 0.00 0.00 0% 0.00 0.00FS 002 38.0 PM2.5 0.00 ton/acre/yr 0.00 0.00 0% 0.00 0.00FS 002 Lead 0.00E+00 ton/acre/yr [31] 0.00E+00 0.00E+00 0% 0.00E+00 0.00E+00FS 002 Bottom Ash Pond - Wind Erosion 98.0 acre PM 0.00 ton/acre/yr [20] 0.00 0.00 0% 0.00 0.00FS 002 Unit 4 Ash Pond 98.0 PM10 0.00 ton/acre/yr 0.00 0.00 0% 0.00 0.00FS 002 98.0 PM2.5 0.00 ton/acre/yr 0.00 0.00 0% 0.00 0.00FS 002 Lead 0.00E+00 ton/acre/yr [31] 0.00E+00 0.00E+00 0% 0.00E+00 0.00E+00FS 003 Fly Ash Pond - Wind Erosion 18.0 acre PM 0.90 ton/acre/yr [20] 3.68 16.13 0% 3.68 16.13FS 003 Unit 3 FGD Pond 18.0 PM10 0.45 ton/acre/yr 1.84 8.06 0% 1.84 8.06FS 003 18.0 PM2.5 0.07 ton/acre/yr 0.28 1.21 0% 0.28 1.21FS 003 18.0 Lead 5.48E-06 ton/acre/yr [31] 2.25E-05 9.87E-05 0% 2.25E-05 9.87E-05FS 004 Fugitive Unpaved Road Dust - 3.2 VMT/hr PM 1.3 lb/VMT [21] 4.09 5.97 90% 0.41 0.60FS 004 Light Vehicles Fly Ash Pond Berm 9,399 VMT/yr PM10 0.30 lb/VMT 0.98 1.43 90% 0.10 0.14FS 004 PM2.5 0.03 lb/VMT 0.10 0.14 90% 0.01 0.01FS 004 Fugitive Unpaved Road Dust - 3.5 VMT/hr PM 2.6 lb/VMT [21] 9.31 13.59 90% 0.93 1.36FS 004 Light Vehicles Main Site 10,265 VMT/yr PM10 0.78 lb/VMT 2.75 4.01 90% 0.27 0.40FS 004 PM2.5 0.08 lb/VMT 0.27 0.40 90% 0.03 0.04FS 004 Fugitive Unpaved Road Dust - Loader 3.1 VMT/hr PM 3.4 lb/VMT [21] 10.51 2.73 90% 1.05 0.27FS 004 1,625 VMT/yr PM10 0.86 lb/VMT 2.68 0.70 90% 0.27 0.07FS 004 PM2.5 0.09 lb/VMT 0.27 0.07 90% 0.03 0.01FS 004 Fugitive Unpaved Road Dust - 7.9 VMT/hr PM 3.4 lb/VMT [21] 26.51 116.11 90% 2.65 11.61FS 004 Coal Bulldozer 69,037 VMT/yr PM10 0.86 lb/VMT 6.76 29.59 90% 0.68 2.96FS 004 PM2.5 0.09 lb/VMT 0.68 2.96 90% 0.07 0.30FS 004 Lead 1.95E-05 lb/VMT [31] 1.54E-04 6.73E-04 90% 1.54E-05 6.73E-05FS 004 Fugitive Unpaved Road Dust - 2.1 VMT/hr PM 28.2 lb/VMT [21] 58.84 22.95 83% 9.71 3.79FS 004 Fly Ash Bulldozer 1,625 VMT/yr PM10 12.30 lb/VMT 25.63 9.99 69% 8.01 3.12FS 004 PM2.5 1.23 lb/VMT 2.56 1.00 40% 1.54 0.60FS 004 Lead 1.73E-04 lb/VMT [31] 3.60E-04 1.40E-04 83% 5.94E-05 2.32E-05FS 004 Fugitive Unpaved Road Dust - 1.1 VMT/hr PM 34.3 lb/VMT [21] 36.31 83.78 90% 3.63 8.38FS 004 Heavy Vehicles 4,891 VMT/yr PM10 14.92 lb/VMT 15.82 36.49 90% 1.58 3.65FS 004 PM2.5 1.49 lb/VMT 1.58 3.65 90% 0.16 0.36

5/3/2017


Throughput Emission Factor

Emission Factor Uncontrolled Emissions

ID Description Pollutant Source lb/hr tons/year Control lb/hr tons/year




FS 004 Fugitive Unpaved Road Dust - 0.5 VMT/hr PM 6.69 lb/VMT [21] 3.55 0.74 90% 0.35 0.07FS 004 J-duct Material 220 VMT/yr PM10 1.98 lb/VMT 1.05 0.22 90% 0.10 0.02FS 004 PM2.5 0.20 lb/VMT 0.10 0.02 90% 0.01 0.00FS 005 Coal stockpile maintenance 8,760 hr/yr PM 10.5 lb/hr [24] 10.48 45.91 0% 10.48 45.91FS 005 (bulldozer) 8,760.0 PM10 2.21 lb/hr 2.21 9.69 0% 2.21 9.69FS 005 8,760.0 PM2.5 0.23 lb/hr 0.23 1.01 0% 0.23 1.01FS 005 Lead 6.08E-05 lb/hr [31] 6.08E-05 2.66E-04 0% 6.08E-05 2.66E-04FS 005 Fly ash landfill maintenance 8,760 hr/yr PM 62.5 lb/hr [24] 62.51 273.81 0% 62.51 273.81FS 005 (bulldozer) 8,760.0 PM10 23.90 lb/hr 23.90 104.68 0% 23.90 104.68FS 005 8,760.0 PM2.5 6.56 lb/hr 6.56 28.75 0% 6.56 28.75FS 005 Lead 3.83E-04 lb/hr [31] 3.83E-04 1.68E-03 0% 3.83E-04 1.68E-03FS 006 Coal Stockpile Material Handling 751 ton/hr PM 0.00057 lb/ton [25] 0.43 1.88 0% 0.43 1.88FS 006 Coal Drop Onto Pile 6,574,977.3 ton/yr PM10 0.00027 lb/ton 0.20 0.89 0% 0.20 0.89FS 006 6,574,977.3 PM2.5 0.00004 lb/ton 0.03 0.13 0% 0.03 0.13FS 006 Lead 3.32E-09 lb/ton [31] 2.49E-06 1.09E-05 0% 2.49E-06 1.09E-05FS 006 Coal Stockpile Material Handling 450 ton/hr PM 0.00629 lb/ton [25] 2.83 12.39 0% 2.83 12.39FS 006 Temporary Portable Conveyors 3,942,000 ton/yr PM10 0.00297 lb/ton 1.34 5.86 0% 1.34 5.86FS 006 3,942,000.0 PM2.5 0.00045 lb/ton 0.20 0.89 0% 0.20 0.89FS 006 Lead 3.65E-08 lb/ton [31] 1.64E-05 7.19E-05 0% 1.64E-05 7.19E-05FS 007 Paved Roads-Light Vehicles 20.8 VMT/hr PM 0.20 lb/VMT [22] 4.26 6.22 75% 1.07 1.56FS 007 60,874.0 VMT/yr PM10 0.04 lb/VMT 0.85 1.24 75% 0.21 0.31FS 007 PM2.5 0.01 lb/VMT 0.21 0.31 75% 0.05 0.08FS 007 Paved Roads-Other Vehicles 10.8 VMT/hr PM 0.20 lb/VMT [22] 2.21 3.23 75% 0.55 0.81FS 007 31,625.0 VMT/yr PM10 0.04 lb/VMT 0.44 0.65 75% 0.11 0.16FS 007 PM2.5 0.01 lb/VMT 0.11 0.16 75% 0.03 0.04FS 007 Paved Roads-Ammonia Trucks 6.0 VMT/hr PM 1.73 lb/VMT [22] 10.39 1.90 75% 2.60 0.47FS 007 2,190.0 VMT/yr PM10 0.35 lb/VMT 2.08 0.38 75% 0.52 0.09FS 007 PM2.5 0.08 lb/VMT 0.51 0.09 75% 0.13 0.02FS 007 Paved Roads-Lime/Limestone Trucks 3.2 VMT/hr PM 2.48 lb/VMT [22] 7.94 12.36 75% 1.98 3.09FS 007 9,962 VMT/yr PM10 0.50 lb/VMT 1.59 2.47 75% 0.40 0.62FS 007 PM2.5 0.12 lb/VMT 0.39 0.61 75% 0.10 0.15FS 007 Paved Roads-PAC Trucks 3.2 VMT/hr PM 2.38 lb/VMT [22] 7.63 0.39 75% 1.91 0.10FS 007 330 VMT/yr PM10 0.48 lb/VMT 1.53 0.08 75% 0.38 0.02FS 007 PM2.5 0.12 lb/VMT 0.37 0.02 75% 0.09 0.00FS 007 Paved Roads-Fly Ash Trucks 7.8 VMT/hr PM 3.09 lb/VMT [22] 24.11 55.63 75% 6.03 13.91FS 007 35,993 VMT/yr PM10 0.62 lb/VMT 4.82 11.13 75% 1.21 2.78FS 007 PM2.5 0.15 lb/VMT 1.18 2.73 75% 0.30 0.68FS 007 Paved Roads - 4.0 VMT/hr PM 2.83 lb/VMT [22] 11.34 24.76 75% 2.83 6.19FS 007 Coal to Rapids Energy Center 17,472.0 VMT/yr PM10 0.57 lb/VMT 2.27 4.95 75% 0.57 1.24FS 007 PM2.5 0.14 lb/VMT 0.56 1.22 75% 0.14 0.30FS 007 Paved Roads - J-duct Material 3.5 VMT/hr PM 1.67 lb/VMT [22] 5.85 1.22 75% 1.46 0.30FS 007 1,456.0 VMT/yr PM10 0.33 lb/VMT 1.17 0.24 75% 0.29 0.06FS 007 PM2.5 0.08 lb/VMT 0.29 0.06 75% 0.07 0.01FS 008 Fly Ash Handling - 198.4 ton/hr PM 0.00206 lb/ton [25] 0.41 0.43 0% 0.41 0.43FS 008 Unloading to Disposal Cell 412,751.5 ton/yr PM10 0.00098 lb/ton 0.41 0.20 0% 0.41 0.20FS 008 PM2.5 0.00015 lb/ton 0.41 0.03 0% 0.41 0.03FS 008 Lead 1.26E-08 lb/ton [31] 2.50E-06 2.60E-06 0% 2.50E-06 2.60E-06FS 008 Fly Ash Handling - 69.801 ton/hr PM 1.57E-02 lb/ton [25] 1.09 1.14 0% 1.09 1.14FS 008 145,186.3 tons/yr PM10 7.41E-03 lb/ton 0.52 0.54 0% 0.52 0.54FS 008 145,186.3 PM2.5 1.12E-03 lb/ton 0.08 0.08 0% 0.08 0.08FS 008 Lead 9.59E-08 lb/ton [31] 6.69E-06 6.96E-06 0% 6.69E-06 6.96E-06FS 009 Fly Ash Disposal Cell - Wind Erosion 0.5 acre PM 0.90 ton/acre/yr [20] 0.11 0.49 0% 0.11 0.49FS 009 Fly Ash Landfill Active 0.5 PM10 0.45 ton/acre/yr 0.06 0.25 0% 0.06 0.25FS 009 0.5 PM2.5 0.07 ton/acre/yr 0.01 0.04 0% 0.01 0.04

Fly Ash Silo A Loadout Truck Bay Fugitives

ID Description Pollutant Source lb/hr tons/year Control lb/hr tons/year




FS 009 0.5 Lead 5.48E-06 ton/acre/yr [31] 6.86E-07 3.00E-06 0% 6.86E-07 3.00E-06FS 009 Fly Ash Disposal Cell - Wind Erosion 38.0 acre PM 0.90 ton/acre/yr [20] 7.77 34.05 0% 7.77 34.05FS 009 Fly Ash Landfill Dormant 38.0 PM10 0.45 ton/acre/yr 3.89 17.02 0% 3.89 17.02FS 009 38.0 PM2.5 0.07 ton/acre/yr 0.58 2.55 0% 0.58 2.55FS 009 38.0 Lead 5.48E-06 ton/acre/yr [31] 4.76E-05 2.08E-04 0% 4.76E-05 2.08E-04FS 009 Fly Ash Disposal Cell - Wind Erosion 20.0 acre PM 0.00 ton/acre/yr [20] 0.00 0.00 0% 0.00 0.00FS 009 Bottom Ash Base (dormant) 20.0 PM10 0.00 ton/acre/yr 0.00 0.00 0% 0.00 0.00FS 009 20.0 PM2.5 0.00 ton/acre/yr 0.00 0.00 0% 0.00 0.00FS 009 20.0 Lead 0.00E+00 ton/acre/yr [31] 0.00E+00 0.00E+00 0% 0.00E+00 0.00E+00Totals PM 315.86 753.96 130.19 454.90Totals PM10 106.61 258.85 50.91 170.93Totals PM2.5 17.84 49.34 11.40 38.53Totals Lead 1.08E-03 3.25E-03 6.38E-04 2.53E-03

H:\MP BEC\draft documents\Public Notice Documents w_App & Attach\TSD Attachments Public Notice\TSD Att 1 - MPCA Calculations.xlsxReferences


Minnesota PowerBoswell Permit Renewal ApplicationPotential to Emit Calculations - References and FootnotesUpdate

[01] 2011 Title V ApplicationUnit EU001 Boiler 1 CoalUnit Capacity 1075 mmbtu/hr (1020 btu/scf)

61.1 ton coal/hr (8800 btu/lb coal - see Reference 26)144.0 mmbtu/hr startup (16 mmbtu/hr for 9 units, see 5/26/16 email from Eric Sutherland)

Factors from AP-42 Chapter 1.1, 9/98, unless noted below https://www3.epa.gov/ttn/chief/ap42/ch01/final/c01s01.pdf

CO 0.5 lb/ton AP-42 Table1.1-3 (PC, dry bottom, wall fired, sub-bituminous)Lead 6.00E-03 lb/ton Based on burning 100% coal with maximum Pb content - Seam Wyodak-AndersonNOx 1.20E+01 lb/ton AP-42 Table1.1-3 (PC, Dry Bottom, Wall Fired, sub-bituminous), controlled factor based on 2014 Consent DecreePM 7.03E+01 lb/ton AP-42 Table1.1-4 (PC, Dry Bottom, Wall Fired, sub-bituminous), controlled factor based on 2014 Consent Decree

PM10 1.62E+01 lb/ton AP-42 Table1.1-4 (PC, Dry Bottom, Wall Fired, sub-bituminous) & AP-42 Table 1.1-5 (PC fired boilers, total condendsables CPM), controlled factor based on Boiler 3 Permitted PM/PM10 ratioPM2.5 4.25E+00 lb/ton AP-42 Table1.1-9 (Uncontrolled particle size mass % PM2.5 = PM10/23*6) & AP-42 Table 1.1-5 (PC fired boilers, total condensables, CPM), controlled factor based on assuming PM2.5=PM10

SO2 2.10E+01 lb/ton AP-42 Table1.1-3 (PC, dry bottom, wall fired, sub-bituminous, NSPS), controlled factor based on 2014 Consent DecreeVOC 6.00E-02 lb/ton AP-42 Table 1.1-19 (TNMOC for PC, dry bottom, wall fired)

HF 1.50E-01 lb/ton AP-42 Table 1.1-15 (for controlled and uncontrolled sources)Sulfuric Acid Mist 6.11E-02 lb/ton EPRI March 2012 (Estimating Total Sulufir Acid Emissions from Stationairy Po Sulfuric Acid Mist Controlled = 2.20E-03 lb/ton EM comb (EQ 4-1) =

Mercury 1.20E-06 lb/mmbtu (30-day average) MATS limit (40 CFR 63 Subpart UUUUU, Table 2)HAP emission factors for coal combustion are from AP-42 Chapter 1.1 Tables 1.1-13, 1.1-14, 1.1-15, and 1.1-18. Emission factor provided in Tables 13, 14, and 18 are for controlled

combustion; therefore, the control factor is already included in the emission factor. Ammonia Sli HCl emission factors for coal combustion are from the MATS Limit of 0.002 lb/mmbtu (40 CFR 63, Subpart UUUUU, Table 3, Controlled) and AP-42, Table 1.1-15, 1.2 lb/ton, uncontrolled) Total Releas GHG emission factors for coal combustion and natural gas combustion are from 40 CFR 98 Subpart C Tables 3-1 and 3-2. Global warming potentials from Table A-1. Total Release (p

Emission factor units converted using 2.205 lb/kg.Controlled efficiency is based upon controlled versus uncontrolled emissions for pollutants with permitted emission rates.

[02] 2011 Title V ApplicationUnit EU001 Boiler 1 Natural GasFactors from AP-42 Chapter 1.4, 9/98, unless noted below https://www3.epa.gov/ttn/chief/ap42/ch01/final/c01s04.pdf

CO 8.40E+01 lb/mmscf AP-42 Table 1.4-1 (Large Wall-Fired Boilers - Uncontrolled - Pre-NSPS)Lead 5.000E-04 lb/mmscf AP-42 Table 1.4-2 (natural gas combustion)NOx 1.75E+02 lb/mmscf 2014 Annual Emission Inventory Continuous Monitor ValuePM 2.00E-01 lb/mmscf 2014 Annual Emission Inventory USEPA EF CE

PM10 5.20E-01 lb/mmscf 2014 Annual Emission Inventory USEPA EF CE (PM-CON + PM10-FIL)PM2.5 5.20E-01 lb/mmscf 2014 Annual Emission Inventory USEPA EF CE (PM-CON + PM10-FIL)

SO2 6.00E-01 lb/mmscf AP-42, Table 1.4-2VOC 5.50E+00 lb/mmscf AP-42 Table 1.4-2 (natural gas combustion)

HAP emission factors for natural gas combustion are from AP-42 Chapter 1.4 Tables 1.4-3 and 1.4-4.GHG emission factors for coal combustion and natural gas combustion are from 40 CFR 98 Subpart C Tables 3-1 and 3-2. Global warming potentials from Table A-1. Emission factor units converted using 2.205 lb/kg.PM control efficiency (99%) based on MPCA control equipment rule, MN Rule 7011.0070 for fabric filterPM10 and PM2.5 control efficiency (61.9%) based on assuming no control for condensable fraction (i.e. ((0.2*0.01)+(0.32))/(0.2+0.32)=69.1%)

5/15/2018

https://www3.epa.gov/ttn/chief/ap42/ch01/final/c01s01.pdf



[03] 2011 Title V ApplicationUnit EU002 Boiler 2 CoalUnit Capacity 910 mmbtu/hr (1020 btu/scf)

51.7 ton coal/hr (8800 btu/lb coal - see Reference 26)144.0 mmbtu/hr startup (16 mmbtu/hr for 9 units, see 5/26/16 email from Eric Sutherland)


CO 5.00E-01 lb/ton AP-42 Table1.1-3 (PC, dry bottom, wall fired, sub-bituminous)Lead 6.00E-03 lb/mmbtu Based on burning 100% coal with maximum Pb content - Seam Wyodak-AndersonNOx 1.20E+01 lb/ton AP-42 Table1.1-3 (PC, Dry Bottom, Wall Fired, sub-bituminous), controlled factor based on 2014 Consent DecreePM 7.03E+01 lb/ton AP-42 Table1.1-4 (PC, Dry Bottom, Wall Fired, sub-bituminous), controlled factor based on 2014 Consent Decree

PM10 1.62E+01 lb/ton AP-42 Table1.1-4 (PC, Dry Bottom, Wall Fired, sub-bituminous) & AP-42 Table 1.1-5 (PC fired boilers, total condendsables CPM), controlled factor based on Boiler 3 Permitted PM/PM10 ratioPM2.5 4.25E+00 lb/ton AP-42 Table1.1-9 (Uncontrolled particle size mass % PM2.5 = PM10/23*6) & AP-42 Table 1.1-5 (PC fired boilers, total condensables, CPM), controlled factor based on assuming PM2.5=PM10

SO2 2.10E+01 lb/ton AP-42 Table1.1-3 (PC, dry bottom, wall fired, sub-bituminous, NSPS), controlled factor based on 2014 Consent DecreeVOC 6.00E-02 lb/ton AP-42 Table 1.1-19 (TNMOC for PC, dry bottom, wall fired)

HF 1.50E-01 lb/ton AP-42 Table 1.1-15 (for controlled and uncontrolled sources)Sulfuric Acid Mist 6.11E-02 lb/ton EPRI March 2012 (Estimating Total Sulufir Acid Emissions from Stationairy Po Sulfuric Acid Mist Controlled = 2.20E-03 lb/ton EM comb (EQ 4-1) =

Mercury 1.20E-06 lb/mmbtu (30-day average) MATS limit (40 CFR 63 Subpart UUUUU, Table 2)HAP emission factors for coal combustion are from AP-42 Chapter 1.1 Tables 1.1-13, 1.1-14, 1.1-15, and 1.1-18. Emission factor provided in Tables 13, 14, and 18 are for controlled

combustion; therefore, the control factor is already included in the emission factor. Ammonia Sli HCl emission factors for coal combustion are from the MATS Limit of 0.002 lb/mmbtu (40 CFR 63, Subpart UUUUU, Table 3, Controlled) and AP-42, Table 1.1-15, 1.2 lb/ton, uncontrolled) Total Releas GHG emission factors for coal combustion and natural gas combustion are from 40 CFR 98 Subpart C Tables 3-1 and 3-2. Global warming potentials from Table A-1. Total Release (p

Emission factor units converted using 2.205 lb/kg.Controlled efficiency is based upon controlled versus uncontrolled emissions for pollutants with permitted emission rates.





HAP emission factors for natural gas combustion are from AP-42 Chapter 1.4 Tables 1.4-3 and 1.4-4.GHG emission factors for coal combustion and natural gas combustion are from 40 CFR 98 Subpart C Tables 3-1 and 3-2. Global warming potentials from Table A-1.

Emission factor units converted using 2.205 lb/kg.PM control efficiency (99%) based on MPCA control equipment rule, MN Rule 7011.0070 for fabric filterPM10 and PM2.5 control efficiency (61.9%) based on assuming no control for condensable fraction (i.e. ((0.2*0.01)+(0.32))/(0.2+0.32)=69.1%)

[05] 2011 Title V ApplicationUnit EU003 Boiler 3 CoalUnit Capacity 4425 mmbtu/hr

251.4 ton coal/hr (8800 btu/lb coal - see Reference 26)480.0 mmbtu/hr startup (10 mmbtu/hr for 16 igniters, 80 mmbtu/hr for 4 warm up guns, see 5/26/16 email from Eric Sutherland)


CO 1.50E-01 lb/mmbtu Permit LimitLead 6.00E-03 lb/mmbtu Based on burning 100% coal with maximum Pb content - Seam Wyodak-AndersonLead 4.00E-05 lb/mmbtu Permit Limit





NOx 7.20 lb/ton AP-42 Table1.1-3 (tangentially fired, sub-bituminous, NSPS), controlled factor based on 2014 Consent DecreePM 7.03E+01 lb/ton AP-42 Table1.1-4 (PC, tangentially fired) PLUS AP-42 Table 1.1-5 (PC, tangentially fired), controlled factor based on 2014 Consent Decree

PM10 1.62E+01 lb/ton AP-42 Table1.1-4 (PC, tangentially fired) PLUS AP-42 Table 1.1-5 (PC, tangentially fired), controlled factor based on permit limitPM2.5 4.25E+00 lb/ton AP-42 Table1.1-9 (Uncontrolled particle size mass % PM2.5 = PM10 / 23 * 6) PLUS AP-42 Table 1.1-5 (PC, tangentially fired), controlled factor based on PM2.5=PM10

SO2 2.10E+01 lb/ton Maximum expected SO2 from Rosebud Coal, controlled factor based on 2014 Consent DecreeVOC 6.00E-02 lb/ton AP-42 Table 1.1-19 (TNMOC for PC, dry bottom, wall fired)

HF 1.50E-01 lb/ton AP-42 Table 1.1-15 (for controlled and uncontrolled sources)Fluorides 1.80E-03 lb/mmbtu Permit Limit which is listed as "HF" in permit 06100004-007 (Controlled Emissions = use control efficiency to back-calculation uncontrolled emissions) EM comb (EQ 4-1) =

Sulfuric Acid Mist 2.31E-01 lb/ton EPRI March 2012 (Estimating Total Sulufir Acid Emissions from Stationairy Po Sulfuric Acid Mist Controlled = 3.49E-03 lb/tonMercury 8.00E-07 lb/mmbtu Permit limit (First Stage Mercury Limit)

HAP emission factors for coal combustion are from AP-42 Chapter 1.1 Tables 1.1-13, 1.1-14, 1.1-15, and 1.1-18. Emission factor provided in Tables 13, 14, and 18 are for controlled Ammonia Sli combustion; therefore, the control factor is already included in the emission factor. Total Releas

HCl emission factors for coal combustion are from the MATS Limit of 0.002 lb/mmbtu (40 CFR 63, Subpart UUUUU, Table 3, Controlled) and AP-42, Table 1.1-15, 1.2 lb/ton, uncontrolled) Total Release (p Controlled efficiency is based upon controlled versus uncontrolled emissions for pollutants with permitted emission rates.


CO 8.40E+01 lb/mmscf AP-42 Table 1.4-1 (PC, tangentially fired)Lead 5.000E-04 lb/mmscf AP-42 Table 1.4-2 (natural gas combustion)NOx 1.78E+02 lb/mmscf 2014 Annual Emission Inventory Continuous Monitor ValuePM 2.00E-01 lb/mmscf 2014 Annual Emission Inventory USEPA EF CE



HAP emission factors for natural gas combustion are from AP-42 Chapter 1.4 Tables 1.4-3 and 1.4-4.PM control efficiency (99%) based on MPCA control equipment rule, MN Rule 7011.0070 for fabric filterPM10 and PM2.5 control efficiency (61.9%) based on assuming no control for condensable fraction (i.e. ((0.2*0.01)+(0.32))/(0.2+0.32)=69.1%)

[07] 2016 (2/27 Retrofit Calculations)Unit EU004 Boiler 4 CoalUnit Capacity 6800 mmbtu/hr

386.4 ton coal/hr (8800 btu/lb coal - see Reference 26)776.0 mmbtu/hr startup (10 mmbtu/hr for 24 igniters, 134 mmbtu/hr for 4 warm up guns, see 5/26/16 email from Eric Sutherland)

Controlled Factors from AP-42 Chapter 1.1, 9/98, unless noted below Un-Controlled Factors from AP-42 Chapter 1.1, 9/98, unless noted below https://www3.epa.gov/ttn/chief/ap42/ch01/final/c01s01.pdf

CO 1.26E-01 lb/mmbtu Actual rate from Dec 2010 to Nov 2012 1.50E-01 lb/mmbtu Permit limit (30-day rolling average)Lead 4.10E-06 lb/mmbtu EPRI 6.00E-03 lb/mmbtu Based on burning 100% coal with maximum Pb content - Sea NOx 1.200E-01 lb/mmbtu 9/29/14 Consent Decree 7.20E+00 lb/ton AP-42 Table1.1-3 (tangentially fired, sub-bituminous, NSPS), PM 1.20E-02 lb/mmbtu Permit Limit (effective 90 days after issuance of the MPCA NOC) 7.03E+01 lb/ton AP-42 Table1.1-4 (PC, tangentially fired) PLUS AP-42 Table 1

PM10 2.00E-02 lb/mmbtu Permit Limit 1.62E+01 lb/ton AP-42 Table1.1-4 (PC, tangentially fired) PLUS AP-42 Table 1 PM2.5 2.00E-02 lb/mmbtu Permit Limit 4.25E+00 lb/ton AP-42 Table1.1-9 (Uncontrolled particle size mass % PM2.5 =

SO2 3.00E-02 lb/mmbtu 9/29/14 Consent Decree 2.10E+01 lb/ton Maximum expected SO2 from Rosebud Coal, controlled fact VOC 6.00E-02 lb/ton AP-42/Fire 6.00E-02 lb/ton AP-42 Table 1.1-19 (TNMOC for PC, dry bottom, wall fired)

HF 1.50E-01 lb/ton AP-42 Table 1.1-15 (for controlled and uncontrolled sources)Mercury 1.20E-06 lb/MMBtu (365 day avg) Permit Limit

Fluorides 8.40E-03 lb/mmbtu Permit Limit (Controlled Emissions = use control efficiency to back-calculation 8.40E-03 lb/mmbtu Permit Limit (Controlled Emissions = use control efficiency to Sulfuric Acid Mist 6.11E-02 lb/ton EPRI March 2012 (Estimating Total Sulufir Acid Emissions from Stationairy Po Sulfuric Acid Mist Controlled = 2.20E-03 lb/ton

HAP emission factors for coal combustion are from AP-42 Chapter 1.1 Tables 1.1-13, 1.1-14, 1.1-15, and 1.1-18. Emission factor provided in Tables 13, 14, and 18 are for controlled combustion; therefore, the control factor is already included in the emission factor.

HCl emission factors for coal combustion are from the MATS Limit of 0.002 lb/mmbtu (40 CFR 63, Subpart UUUUU, Table 3, Controlled) and AP-42, Table 1.1-15, 1.2 lb/ton, uncontrolled)




Controlled efficiency is based upon controlled versus uncontrolled emissions for pollutants with permitted emission rates.[08] 2011 Title V Application

Unit EU004 Boiler 4 Natural GasFactors from AP-42 Chapter 1.4, 9/98, unless noted below https://www3.epa.gov/ttn/chief/ap42/ch01/final/c01s04.pdf




HAP emission factors for natural gas combustion are from AP-42 Chapter 1.4 Tables 1.4-3 and 1.4-4.PM control efficiency (99%) based on MPCA control equipment rule, MN Rule 7011.0070 for fabric filter EM comb (EQ 4-1) =PM10 and PM2.5 control efficiency (61.9%) based on assuming no control for condensable fraction (i.e. ((0.2*0.01)+(0.32))/(0.2+0.32)=69.1%)

Ammonia Sli [09] 2011 Title V Application Total Releas

Unit EU005 Unit 4 Cooling Tower Water Total Release (p Unit Capacity 160000 gal/minPM emission factor is from AP-42 Section 13.4 (01/95)https://www3.epa.gov/ttn/chief/ap42/ch13/final/c13s04.pdfA drift rate of 0.02%, total flow of 160,000 gal/min, and an average TDS of 1800 ppm were assumedEmission Factor = 1800 g /1,000,000 mL * 3,785.412 mL/gallon ̧453.59 g/lb * 0.02% = 3.00 E-06 lb/galTDS Drift Rate of 1800 and drift rate of 0.02% from 1995 permit application.

PM10 and PM2.5 are calculated as fraction of PM emissions using emission calculation procedure in "Calculating Realistic PM10 Emissions from Cooling Towers" by Reisman and Frisbie, Environmental Progress, Vol. 21, No.2.

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

Droplet Volume Mass Mass Particle Particle Mass in PM in PMDiameter (Solids) Volume Diameter Smaller Emissions Emissions

(µm) (µm3) (µg) (µg) (µm3) (µm) (%) (%) (%)10 524 0.00E+00 0.00E+00 0.43 0.935 0.00020 4189 0.00E+00 0.00E+00 3.43 1.871 0.19630 14137 0.00E+00 0.00E+00 11.57 2.806 0.226 0.21640 33510 0.00E+00 0.00E+00 27.42 3.741 0.51450 65450 0.00E+00 0.00E+00 53.55 4.676 1.81660 113097 0.00E+00 0.00E+00 92.53 5.612 5.70270 179594 0.00E+00 0.00E+00 146.94 6.547 21.34890 381704 0.00E+00 0.00E+00 312.30 8.418 49.812

110 696910 0.00E+00 0.00E+00 570.20 10.288 70.509 67.319130 1150347 0.00E+00 0.00E+00 941.19 12.159 82.023150 1767146 0.00E+00 0.00E+00 1445.85 14.029 88.012180 3053628 0.00E+00 0.00E+00 2498.42 16.835 91.032210 4849048 0.00E+00 0.00E+00 3967.40 19.641 92.468

assumptions: TDS: 1800 ppmwater density: 1 g/cm3

particle density: 2.2 g/cm3 Reisman, Frisbie article




[10] 2011 Title V ApplicationUnit EU006 Unit 3 Cooling TowerUnit Capacity 103000 gal/minPM emission factor is from AP-42 Section 13.4 (01/95) https://www3.epa.gov/ttn/chief/ap42/ch13/final/c13s04.pdfSee Ref [09] for PM10/PM2.5 emission factors

[11] Emission units have been removed from the facility

[12] 2011 Title V ApplicationUnit EU023 Diesel

Unit Capacity 480 HP (from engine spec sheet) 22.7 diesel gal/hr (from engine spec sheet)358 kW (output converted from HP) 3.2 MMBtu/hr (calculated at 140,000 Btu/gal)

Unit EU033 DieselUnit Capacity 398 HP (from engine spec sheet) 2.79 mmbtu/hr

297 kW (output converted from HP)Emission Factor from AP42, Table 3.3-1; 10/96 https://www3.epa.gov/ttn/chief/ap42/ch03/final/c03s03.pdfSOx = 1.01 * S, where S = %sulfur in fuel, AP-42, Table 3.4-1https://www3.epa.gov/ttn/chief/ap42/ch03/final/c03s04.pdfEmission Factor from NSPS Subpart IIIIhttp://www.ecfr.gov/cgi-bin/text-idx?node=sp40.7.60.iiiiCO value based on BACTNote that Subpart IIII (refer to 40 CFR 89.112) sets a limit on NOx+NMHC (VOC) of 4.0 g/kW-hr.

4 g/kW-hr has been used here as a potential worst case for each pollutant.Potential to emit based on 500 operating hours per year as per EPA policy on emergency generators.H2SO4 determined as 1.5% of SO2 (with conversion from SO2 to H2SO4 based upon Molecular Weight)AP-42 ICE section does not provide a lead emission rate. Assumed AP-42 lead emission factor for distillate fuel oil from Table 1.3-10HAP emission factors from AP42 Table 3.3-2.GHG emission factors for fuel oil combustion are from 40 CFR 98 Subpart C Tables 3-1 and 3-2. Global warming potentials from Table A-1. Emission factor units converted using 2.205 lb/kg.

[13] MP Power Boswell Genset ApplicationUnit EU034 Diesel Manufacturer Emission Factors from CaterpillarUnit Capacity 2,206 hp 14.64 mmbtu/hrEmission factors for PM, CO, HC and NOx in g/hp-hr are from the manufacturer (Caterpillar). PM10 and PM2.5 fractions of PM are proportioned the same as AP-42 Table 3.4-2.

From Table 3.4-2 lb/MMBtu % vs. Total PMTotal PM (filt + cond): 0.0697 100.0%

Total PM10 (filt + cond): 0.0573 82.2%Total PM2.5 (filt + cond): 0.0556 79.8% (pased on <3um per Table 3.4-2)

SO2 EF (lbs/MMBtu) is from AP-42 Table 3.4.1 assuming 15 PPM sulfur fuel compliant with 40 CFR 80.510(b).Potential to emit based on 500 operating hours per year as per EPA policy on emergency generators.AP-42 ICE section does not provide a lead emission rate. Assumed AP-42 lead emission factor for distillate fuel oil from Table 1.3-10HAP emission factors from AP42 Table 3.4-3 and 3.3-4.GHG emission factors for fuel oil combustion are from 40 CFR 98 Subpart C Tables 3-1 and 3-2. Global warming potentials from Table A-1. Emission factor units converted using 2.205 lb/kg.

[14] 2011 Title V ApplicationUnit EU011 Coal Handling-CrusherUnit Capacity 800 ton/hr 6,574,977 ton/yrUnit EU012 Coal Handling-CrusherUnit Capacity 1,000 ton/hr 6,574,977 ton/yrUnit EU017 Fly Ash Silo A Unit Capacity (see footnote [32] 16.574 ton/hr (average) 145,186 ton/yrCoal Handling emission factors (EU 011 and EU 012) are based on Fire Data base SCC 30501010 0 Uncontrolled

PM2.5 assumed to equal PM10Fly Ash uncontrolled emission factors (EU 017) are from AP-42 11.12 (Cement Unloading to elevated storage silo (pneumatic) (3-05-011-07))

Uncontrolled Emission Factor

PM 0.73 lb/tonPM10 0.47 lb/tonPM2.5 0.47 lb/ton Assumes PM2.5 = PM10

Lead emissions based on uncontrolled lead emissions from Unit 3 as a worst case in ppm (6.12 ppm).Control efficiencies for PM and PM10 are permit limits, when available. If no permit limits are established (e.g. CE 7-10 / SV 11-14), the PM10 and PM2.5 control efficiencies have been revised to 93% in accordance with the control equipment rule. Assume PM2.5 control equals PM10 control, although that is not intended to be a permit limit.




http://www.ecfr.gov/cgi-bin/text-idx?node=sp40.7.60.iiii



EU 017 control efficiencies for fly ash transfer to ash silo are based on 100% capture:Collection Efficiency

(100% Capture)PM 99%PM10 93%PM2.5 54%



[15] 2011 Title V Application updated with emissions factors from AP-42 Table 11.12-2 in 2016 Title V ApplicationUnit EU013 Fly Ash Silo

Unit Capacity 6.34 ton/hr (see footnote [32])Unit EU014 Fly Ash Silos 1&2

Unit Capacity 6.34 ton/hr (see footnote [32])Unit EU039 Dust Tank

Unit Capacity 3.50 ton/hrUncontrolled emission factors from AP-42 11.12 (Cement Unloading to elevated storage silo (pneumatic) (3-05-011-07))

Uncontrolled Emission Factor

PM 0.73 lb/tonPM10 0.47 lb/ton

PM2.5 0.47 lb/ton Assumes PM2.5 = PM10Lead emissions based on uncontrolled lead emissions from Unit 3 as a worst case in ppm (6.12 ppm).Control efficiencies for PM and PM10 are permit limits, when available. If no permit limits are established (e.g. CE 7-10 / SV 11-14), the PM10 and PM2.5 control efficiencies have been revised to 93% in

accordance with the control equipment rule. Assume PM2.5 control equals PM10 control, although that is not intended to be a permit limit.

[16] 2011 Title V ApplicationUnit EU015 Unit 3 Activated Carbon Silo

Unit Capacity 2,500 dscfmPM Emission Factors based on vendor data: 1 gr/dscfControl efficiencies for PM and PM10 are permit limits, when available. If no permit limits are established (e.g. CE 7-10 / SV 11-14), the PM10 and PM2.5 control efficiencies have been revised to 93% in


[17] Fly Ash Silo A LoadoutThese calculations cover two emission units and one fugitive source:

EU 042 Fly Ash Silo A - LoadoutEU 018 Fly Ash Silo A Loadout Truck BayFS 008 Fly Ash Handling - Fly Ash Silo A Loadout Truck Bay Fugitives

Description of Silo A Emission Units, Control Devices and Stacks

Annual ash loadout (see footnote [32]):Annual Ash loadout: 69.801 tons/hour Annual throughput for 2080 hours/year

145,186.290 tons/year See Footnote [32]

Emission factors 0.199053585EU 042 Fly Ash Silo A - Loadout 0.199053585

From: AP-42, Section 13.2.4, Equation 1E = k * (0.0032) * (U/5)^1.3 / (M/2)^1.4

where:E = Emission factor (lb/ton material handled) from AP-42, Section 13.2.4, Equation 1, (1/95).k = Particle size multiplier (dimensionless) from AP-42, pg. 13.2.4-3.U = Mean wind speed, (mph) is from AP-42, pg. 13.2.4-3. https://www3.epa.gov/ttn/chief/ap42/ch13/final/c13s0204.pdfM = Mean moisture content (%) is based on predicted site-specific value.

Uncontrolled Emission Factor and Control Efficiency Calculations:Pollutant Particle Size Mean Wind Moisture EU 042 - Uncontrolled Capture Collection Control

Multiplier, k Speed, U Content, M Emission Factor, E Efficiency Efficiency Efficiency(mph)* (%) (lb/ton) (%) (%) (%)

PM 0.74 1.3 0.0149 3.92E-01 80% 99% 79%PM10 0.35 1.3 0.0149 1.85E-01 80% 93% 74%PM2.5 0.053 1.3 0.0149 2.80E-02 80% 54% 43%* Estimated average annual wind speed inside the loadout truck bay with the door open

1. Fly ash is pneumatically conveyed to EU 017 (Fly Ash Silo A) from the boilers; the conveyance air is exhasted through fabric filter CE 015 and stack SV 017; this activity is EU 017 Fly Ash Silo A - Ash Transfer (see footnote 14). 2. Ash is dropped from the silo into trailers through a telescoping spout fitted with a ventilated annular hood (VAH) that collects fugitive dust, returns it to the silo and exhausts through CE 015 and SV 017; this activity is EU 042 Fly Ash Silo A - Loadout (see emission factors below). 3. Dust emission not captured by the VAH are captured by a certified canopy hood located over the trailer in a partially enclosed truck bay; the hood vents through fabric fileter CE 044 and stack 031; this activity is EU 018 Fly Ash Silo A Loadout Truck Bay (see emission factors below).4. Dust not captured by the canopy hood is emitted as fugitive dust (FS 008 Fly Ash Handling - Fly Ash Silo A Loadout Truck Bay Fugitives) from the partially enclosed truck bay (see emisison factors below)

EU 042 / CE 015




EU 018 Fly Ash Silo A Loadout Truck BayUncontrolled Emission Factor and Control Efficiency Calculations:Uncontrolled emission factor is un-captured emissions from EU 042

Pollutant EU 042 - Uncontrolled EU 018 - Uncontrolled Capture Collection ControlEmission Factor, E EU 018 Emission Factor, E Efficiency Efficiency Efficiency

(lb/ton) Capture Efficiency (lb/ton) (%) (%) (%)PM 3.92E-01 80% 7.83E-02 80% 99% 79%PM10 1.85E-01 80% 3.70E-02 80% 93% 74%PM2.5 2.80E-02 80% 5.61E-03 80% 54% 43%

FS 008 Fly Ash Handling - Fly Ash Handling - Emission factor is uncaptured emissions from EU 018

Pollutant EU 018 - Uncontrolled FS 008 - UncontrolledEmission Factor, E EU 018 Emission Factor, E

(lb/ton) Capture Efficiency (lb/ton)PM 7.83E-02 80% 1.57E-02PM10 3.70E-02 80% 7.41E-03PM2.5 5.61E-03 80% 1.12E-03

Lead emissions based on uncontrolled lead emissions from Unit 3 as a worst case in ppm (6.12 ppm).

[18] 2011 Title V ApplicationUnit EU019 Limestone SiloUnit Capacity 2,000 dscfmUnit EU020 Limestone Day Silo #1Unit Capacity 3,300 dscfmUnit EU021 Limestone Day Silo #2Unit Capacity 3,300 dscfmPM Emission Factors based on vendor data.

0.5 gr/dscfControl efficiencies for PM and PM10 are permit limits, when available. If no permit limits are established (e.g. CE 7-10 / SV 11-14), the PM10 and PM2.5 control efficiencies have been revised to 93% in


[19] 2/27/2012 Retrofit ApplicationUnit EU024 Lime Storage Bin VentUnit Capacity 2,000 dscfm 0.005 gr/dscf Vendor controlled emission factorUnit EU025 Lime Day Bin A Bin VentUnit Capacity 1,500 dscfm 0.005 gr/dscf Vendor controlled emission factorUnit EU026 Lime Day Bin B Bin VentUnit Capacity 1,500 dscfm 0.005 gr/dscf Vendor controlled emission factorUnit EU027 Lime Day Bin C Bin VentUnit Capacity 1,500 dscfm 0.005 gr/dscf Vendor controlled emission factorUnit EU028 Lime Day Bin D Bin VentUnit Capacity 1,500 dscfm 0.005 gr/dscf Vendor controlled emission factorUnit EU029 Lime Day Bin E Bin VentUnit Capacity 1,500 dscfm 0.005 gr/dscf Vendor controlled emission factorUnit EU030 PAC SiloUnit Capacity 1,000 dscfm 0.005 gr/dscf Vendor controlled emission factorUnit EU031 Waste Ash SiloUnit Capacity 15,500 dscfm 0.0025 gr/dscf Vendor controlled emission factorUnit EU032 Waste Ash Silo Truck BayUnit Capacity 23,400 dscfm 0.0025 gr/dscf Vendor controlled emission factor

Uncontrolled PM/PM10/PM2.5 emission factors from AP-42 Table 11.12-2 for concrete batching. https://www3.epa.gov/ttn/chief/ap42/ch11/final/c11s12.pdf

Control efficiencies for PM, PM10 and PM2.5 are permit limits.

Flyash (Units 1, 2 and 4) 267,565.22 0.73 97.66 0.47 62.88

MaterialThroughput

(see footnote [32])(tpy)

PM PM10/PM2.5

Uncontrolled Emission Factor (lb/ton)

Uncontrolled Emissions tpy

Uncontrolled Emission Factor (lb/ton)

Uncontrolled Emissions tpy

EU 018 / CE 044




Lime Silo (Unit 4) 21,273.77 0.73 7.76 0.47 5.00 Lime Day Bins (Unit 4)5 Day Bin Fabric Filters

4,254.75 0.73 1.55 0.47 1.00

PAC (Unit 4) 380.14 0.73 0.14 0.47 0.09

[20] Wind Erosion

Wind Erosion Emission Factors from AP-42 Section 13.2.5 Table 2 and Hibbing Airport Met Data (2009-2013)

Pile Name (Volume Source Represented Piles)

Approximate Shape

Threshold Friction Velocity (m/s)

PM Emission Factor (ton/acre/year)

PM10 Emission Factor (ton/acre/year)

PM2.5 Emission Factor (ton/acre/year)

Ground Coal Flat Oval 0.55 0.80 0.40 0.06Uncrusted Coal Pile Flat Oval 1.12 0.00 0.00 0.00Bottom Ash Flat Oval 1.33 0.00 0.00 0.00Fly Ash Flat Oval 0.54 0.90 0.45 0.07

4,047 m^2/acre43,560 ft^2/acre

Wind Erosion Surface Area* Emit Factor Days of Disturbance (N) Acreage**Acreage for Calculation

(N/365 * Acreage if applicable) Crust

Pile HeightIf Applicable

(ft)FS 001 Coal Stockpile - Wind Erosion

Active Coal Pile Ground CoalEvery Day

365 20 20 none 55

Crusted outer storage pile Ground Coal on "days of disturbance"

2 12 6.58E-02 chemical 85

Crusted long-term storage pile Ground Coal on "days of disturbance"

2 24 1.32E-01 chemical 44

FS 002 Bottom Ash Pond - Wind ErosionExcavation Area Bottom Ash on

"days of disturbance"

30 5 4.11E-01 none

Pond Area Bottom AshEvery Day

0 38 38 none

Unit 4 Ash Pond Bottom AshEvery Day

0 98 98 none

FS 003 Fly Ash Pond - Wind ErosionUnit 3 FGD Pond Fly Ash Flat Oval

Every Day0 18 18 none

FS 009 Fly Ash Disposal Cell - Wind ErosionFly Ash Landfill Active Fly Ash Flat Oval

on "days of disturbance"

200 1 5.48E-01 none

Fly Ash Landfill Dormant Fly Ash Flat Oval on Every Day

0 38 38 yes

Bottom Ash Base (dormant) Bottom AshEvery Day

0 20 20 none

NOTE: *The PTE calculations use conservatively high assumptions for the wind erosion. The emissions due to wind erosion and the erodible area for wind erosion sources are based on several factors which are not accounted for in these calculations, including: pile disturbances, control measures, precipitation, snow cover, reclamation (mulching and seeding), and moisture content of ash pond beaches.

** The listed "acreage" is a conservatively high estimate of the average wind erodible true surface area for each fugitive source and segment.



[21] AP-42, 5th Ed., Vol I (11/06), Section 13.2.2 'Unpaved Roads'. E (lb/vehicle mile traveled) =k * (s/12)^a*(W/3)^b*((365-P)/365)

Surface material Silt Content, s (%): 3.5 From testing of Fly Ash Haul Road70 Silt content of Fly ash used for trips on Fly ash pond, data from testing

4.8 Silt content of coal used for trips on coal pile, data from testing10 MPCA Default used for other roads: http://www.pca.state.mn.us/index.php/view-document.html?gid=385

P, Number of days per year with >0.254 mm (0.01 in) of precipitation: 110 Boswell Coal Stockpile Expansion Calculations May 2015Mean vehicle weight, W (tons): see table below

Empirical constant: k a b4.9 0.7 0.45 for PM1.5 0.9 0.45 for PM10

0.15 0.9 0.45 for PM2.5

Truck Type

Surface material Silt Content, s (%) Average Vehicle Weight (ton) VMT per Hour VMT per Year Control Efficiency

Light Vehicles - ash pond berm 3.5 2.25 3.2 9399 90%Light Vehicles - main site 10 2.25 3.5 10265 90%Loader 4.8 12 3.1 1625 90%Dozer - Coal 4.8 12 7.9 69037 90%Dozer - Fly Ash 70 21 2.1 1625 See Fugitives tabHeavy Vehicles - Ash Trucks 70 32.3 1.1 4891 90%J-duct Material 10 17.7 0.5 220 90%Most distance, usage rates, and vehicle weights used are from the Boswell Coal Stockpile Expansion Calculations May 2015.xls or else the 2011 Title V renewal PTE calculations. Dozer - Fly Ash information from Unit 4 Retrofit permit application which incorporates the residual moisture content of the ash for the control efficiency.

[22] AP-42, 5th Ed., Vol I (1/2011), Section 13.2.1 'Paved Roads'. E (lb/vehicle mile traveled) =k * (sL)^0.91*(W)^1.02Road Surface Silt Loading, sL (g/m2): 10 (MP Boswell Unit 4 Retrofit application calculations)

Particle Size Multiplier, k (lb/VMT): 0.011 for PM0.0022 for PM10

0.00054 for PM2.5Control Efficiency for water/sweeping: 75% (MP Boswell Unit 4 Retrofit application calculations)

Truck TypeRound Trip Distance

Max Hourly Usage Rate (lb/hr)

Vehicle Empty Weight (ton) Vehicle Loaded Weight (ton)

Average Vehicle Weight (ton) Max Trips per Hour Max Trips per Year

VMT per Hour VMT per Year

Light Vehicles -- -- -- -- 2.25 -- -- 20.8 60,874Other Vehicles -- -- -- -- 2.25 -- -- 10.8 31,625Ammonia Trucks -- -- 15 21.5 18.3 -- -- 6.0 2,190Lime/Limestone 3.2 15,633 15 37.0 26.0 1.0 3,113 3.2 9,962PAC 3.2 --- 15 35.0 25.0 1 103 3.2 330Fly Ash 3.9 51,619 20 44.5 32.3 2.0 9,229 7.8 35,993Coal to Rapids Energy Center 4 --- 18 41.3 29.6 1.0 4,368 4.0 17,472J-duct Material 3.5 --- 10.4 25.0 17.7 1.0 416 3.5 1,456Distance, usage rates, and vehicle weights used are from the MP Boswell Unit 4 Retrofit application calculations or the 2011 Title V renewal PTE calculations.



[23] Coal Handling ActivitiesE = k * (0.0032) * (U/5)^1.3 * (M/2)^-1.4 https://www3.epa.gov/ttn/chief/ap42/ch13/final/c13s0204.pdf

where:E = Emission factor (lb/ton material handled) from AP-42, Section 13.2.4, Equation 1, (1/95).k = Particle size multiplier (dimensionless) from AP-42, pg. 13.2.4-3.U = Mean wind speed, (mph) is from AP-42, pg. 13.2.4-3.M = Mean moisture content (%) is based on predicted site-specific value.

Emission Factor Calculations:Material Pollutant Particle Size Mean Wind Moisture Uncontrolled Control

Multiplier, k Speed, U Content, M Emission Factor, E Efficiency [1](mph) [2] (%) [3] (lb/ton) (%)

Coal PM 0.74 10.23 20.0 0.00024 99%Coal PM10 0.35 10.23 20.0 0.0001 93%Coal PM2.5 0.053 10.23 20.0 0.0000 93%

[2] Mean wind speed based on conveyor belt speed (900 ft/min) 10.23 mph[3] per MP Boswell coal analyses for 2016 and beyond. See Reference 26.

Max. Annual Coal Throughput:Boiler 1 = 61.1 tons/hour (design capacity)Boiler 2 = 51.7 tons/hour (design capacity)Boiler 3 = 251.4 tons/hour (design capacity)Boiler 4 = 386.4 tons/hour (design capacity)

Total hourly = 750.6 tons/hour (design capacity)Annual hours = 8,760 hours/yearTotal annual = 6,574,977 tons/year

Boilers 1-3 Annual = 3,190,432 tons/yearBoiler 4 Annual = 3,384,545 tons/year

Lead calculation assumes worst case lead in coal for all coal and applies that concentration to the PM emission rate (5.8 ppm).

[24] Coal bulldozerFrom AP-42 Section 11.9, Western Surface Coal Mining, Table 11.9-1 (10/98) Bulldozing coalhttps://www3.epa.gov/ttn/chief/ap42/ch11/final/c11s09.pdf

PM PM15 PM10TSP <= 30ug TSP <= 15ug Scaling factor = 0.75 * PM15

EF (lb/hr) = (78.4)(s)^1.2 (18.6)(s)^1.5 PM2.5(M)^1.3 (M)^1.4 Scaling factor = 0.022 * TSP

where: s, silt content = 4.8 Coal: AP-42 Table 13.2.4-1M, moisture content = 20 Coal: From Minnesota Power Boswell coal analyses for 2016 and beyond. See Reference 26.

Fly Ash BulldozerFrom AP-42 Section 11.9, Western Surface Coal Mining, Table 11.9-1 (10/98) Bulldozing overburdenhttps://www3.epa.gov/ttn/chief/ap42/ch11/final/c11s09.pdf

PM PM15 PM10TSP <= 30ug TSP <= 15ug Scaling factor = 0.75 * PM15

EF (lb/hr) = (5.7)(s)^1.2 (1.0)(s)^1.5 PM2.5(M)^1.3 (M)^1.4 Scaling factor = 0.105 * TSP

where: s, silt content = 70 Silt content of Fly ash used for trips on Fly ash pond, data from testingM, moisture content = 8 Fly Ash: from the 2011 Title V renewal PTE calculations

Annual hours of operation are from the 2011 Title V renewal PTE calculations.

NOTE: The total annual coal throughput is based upon the combined maximum design capacity of the boilers operating for 8760 hours/year. However, the coal receipts could vary from this value depending on if the facility is building or dropping i t

[1] Control efficiencies are from the control efficiency rule for a fabric filter: a control device in which the incoming gas stream passes through a porous fabric filter forming a dust cake. See MN Rules 7011. https://www.revisor.mn.gov/rules/?id=7011.0070. All of the MP Boswell dust collectors serve totally enclosed spaces except for the 2 on Fly Ash Silo A which has 2 certified hoods.






[25] Fugitive Material Handling Activities

E = k * (0.0032) * (U/5)^1.3 / (M/2)^1.4 https://www3.epa.gov/ttn/chief/ap42/ch13/final/c13s0204.pdfwhere:

E = Emission factor (lb/ton material handled) from AP-42, Section 13.2.4, Equation 1, (1/95).k = Particle size multiplier (dimensionless) from AP-42, pg. 13.2.4-4.U = Mean wind speed, (mph) confirmd by MPCA staff using 2012 - 2016 Hibbing met data for 24-hour averaging period.M = Mean moisture content (%) is based on predicted site-specific value.

Emission Factor Calculations:Material Pollutant Particle Size Mean Wind Moisture Uncontrolled Transfer Uncontrolled

Multiplier, k Speed, U Content, M* Emission Factor, E Points Emission Factor, E(mph) (%) (lb/ton/transfer point) (lb/ton)

Coal Drop Onto Pile PM 0.74 20 20 0.00057 1 0.00057Coal Drop Onto Pile PM10 0.35 20 20 0.0003 1 0.0003Coal Drop Onto Pile PM2.5 0.053 20 20 0.0000 1 0.0000Temporary Portable Conveyors PM 0.74 20 20 0.00057 11 0.00629Temporary Portable Conveyors PM10 0.35 20 20 0.0003 11 0.0030Temporary Portable Conveyors PM2.5 0.053 20 20 0.0000 11 0.0005Fly Ash PM 0.74 20 8.0 0.00206 1 0.00206Fly Ash PM10 0.35 20 8.0 0.0010 1 0.0010Fly Ash PM2.5 0.053 20 8.0 0.0001 1 0.0001*Moisture content of fly ash from the 2011 Title V renewal PTE calculations. Moisture content of coal from MP Boswell coal analyses for 2016 and beyond. See Reference 26.

Hourly throughputs Coal Drop Onto Pile 751 ton/hr Based on annual coal throughput (see Footnote [23])8760 hr/yr

Temporary Portable Conveyors 450 ton/hr As presented in the coal stockpile expansion calculations May 20158760 hr/yr

Fly Ash: 198 ton/hr Based on ash throughput (see Footnote [32]) and 2080 hr/yr 412,752 tons/year Based on ash throughput (see Footnote [32])

[26] Coal AnalysisCoal Ash % Dry Ash % Sulfur % Dry Sulfur % Lead (Pb) (ppm) Btu Content MoistureCoal 1 4.83 6.56 0.25 0.34 2.12 8971 26.37Coal 2 4.5 6 0.45 0.6 NA 9400 24.5Coal 3 5.2 7.03 0.24 0.35 2.3 8850 26Coal 4 4.5 6.2 0.21 0.29 3 8800 27.4Coal 5 4.2 5.6 0.37 0.49 1.3 9350 25Worst Case Coal Moisture 20

[27] Consent Decree Emission Limits (on date of application)

Boiler 1 0.200 lb/MMBtu (30-day average) 0.015 lb/MMBtu (3-hr average) 0.700 lb/MMBtu (30-day average)Boiler 2 0.200 lb/MMBtu (30-day average) 0.015 lb/MMBtu (3-hr average) 0.700 lb/MMBtu (30-day average)Boiler 3 0.060 lb/MMBtu (30-day average) 0.015 lb/MMBtu (3-hr average)** 0.030 lb/MMBtu (30-day average)***Boiler 4 0.120 lb/MMBtu (30-day average) 0.012 lb/MMBtu (3-hr average)**** 0.030 lb/MMBtu (30-day average)

NOTES: * Consent decree PM limit is "filterable particulate" only** Permit limit is 0.014 lb/MMBtu*** 2600 lb/hr is the 2014 SV004 modeled 1-hour SO2 emission rate **** Initial limit is 0.015 lb/MMBtu which becomes 0.012 lb/MMBtu 90 days after issuance of MPCA Noticie of Compliance Status

[28] AP-42 Table 1.1-12 Emission Factors for Polychlorinated Benzo-P-dioxins and Polyshlorinated Dibenzofurans from Controlled Bituminous and Subbituminous Coal CombustionThe emission factor accounts for controls and, therefore, the uncontrolled emission rate is not availableEmission factor selection:

Boiler ControlsBoiler 1 Fabric FilterBoiler 2 Fabric FilterBoiler 3 Fabric FilterBoiler 4 FGD-SDA with FF

[29] AP-42 Table 1.1-13 Emission Factors for Polynuclear Aromatic Hydrocarbons (PAH) From Controlled Coal Combustion

Note that AP-42 Table 1.1-12 lists "No Data" for 2,3,7,8-TCDD for FGD-SDA with FF and therefore the Fabric Filter emission factor was used for this pollutant.

NOX PM* SO2




The emission factor accounts for controls and, therefore, the uncontrolled emission rate is not available

[30] AP-42 Table 1.1-17. Emission factors for Trace Elements, POM and HCOH from Uncontrolled Bituminous and Subbituminous Coal CombustionPOM = Polycyclic Organic MatterThe emission factor is for uncontrolled emissions but the control efficiency for POM is unknownEmission factor selection:

Boiler Firing ConfigurationBoiler 1 Pulverized coal, dry bottomBoiler 2 Pulverized coal, dry bottomBoiler 3 Pulverized coal, dry bottom, tangentialBoiler 4 Pulverized coal, dry bottom, tangential

[31] Lead emissions from fugitive sources:Lead from Coal = PM emissions * 5.8 / 1,000,000 (see footnote 14)Lead from Ash = PM emissions * 6.12 / 1,000,000 (see footnote 15)

[32] Fly Ash Generation

ATTACHMENT 2 – COAL STOCKPILE EXPANSION EMISSION CALCULATIONS

TECHNICAL SUPPORT DOCUMENT


GI-07Facility Emissions Summary

Air Quality Permit ProgramDoc Type: Permit Application

1a) AQ Facility ID No.: '06100004 1b) Agency Interest ID No.: 73B2) Facility Name: Minnesota Power - Boswell

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

3a) Delta ID No.: EU 034 3b) Tempo SI ID No.: FUGI113c) 3d) 3e) Potential 3f)Pollutant Name CAS #

Lbs per Hr

Unctpy

Lim tpy

Actual tpy

PM - 2.83 14.59 12.39 12.39PM10 - 1.34 6.90 5.86 5.86PM2.5 - 0.2 1.04 0.89 0.89Lead 7439-92-1 1.64E-05 8.46E-05 7.19E-05 7.19E-05Total HAPs - 1.48E-04 6.50E-04 6.50E-04 6.50E-04Antimony 7440-36-0 4.81E-07 2.11E-06 2.11E-06 2.11E-06Arsenic 7440-38-2 9.90E-06 4.34E-05 4.34E-05 4.34E-05Beryllium 7440-41-7 1.02E-06 4.46E-06 4.46E-06 4.46E-06Cadmium 7440-43-9 6.22E-07 2.73E-06 2.73E-06 2.73E-06Chromium 7440-47-3 1.37E-05 6.02E-05 6.02E-05 6.02E-05Cobalt 7440-48-4 6.22E-06 2.73E-05 2.73E-05 2.73E-05Manganese 7439-96-5 9.05E-05 3.97E-04 3.97E-04 3.97E-04Mercury 7439-97-6 3.68E-07 1.61E-06 1.61E-06 1.61E-06Nickel 7440-02-0 1.70E-05 7.46E-05 7.46E-05 7.46E-05Selenium 7783-00-8 8.49E-06 3.72E-05 3.72E-05 3.72E-05

4a) 4c) Actual 4c) Actual 4a) 4c) ActualPollutant Name Unrestricted Limited tons/year Unrestricted Limited tons/year Pollutant Name Unrestricted Limited tons/year

PM 14.59 12.39 12.39 2.11E-06 2.11E-06 2.11E-06 Cobalt 2.73E-05 2.73E-05 2.73E-05

4a) 4c) Actual 4c) Actual 4a) 4c) ActualPollutant Name Unrestricted Limited tons/year Unrestricted Limited tons/year Pollutant Name Unrestricted Limited tons/year

PM10 6.90 5.86 5.86 4.34E-05 4.34E-05 4.34E-05 Manganese 3.97E-04 3.97E-04 3.97E-04

4a) 4c) Actual 4c) Actual 4a) b) Potential (tpy) 4c) ActualPollutant Name Unrestricted Limited tons/year Unrestricted Limited tons/year Pollutant Name Unrestricted Limited tons/year

PM2.5 1.04 0.89 0.89 4.46E-06 4.46E-06 4.46E-06 Mercury 1.61E-06 1.61E-06 1.61E-06

4a) 4c) Actual 4c) Actual 4a) 4b) Potential (tpy) 4c) ActualPollutant Name Unrestricted Limited tons/year Unrestricted Limited tons/year Pollutant Name Unrestricted Limited tons/year

Lead 8.46E-05 7.19E-05 7.19E-05 2.73E-06 2.73E-06 2.73E-06 Nickel 7.46E-05 7.46E-05 7.46E-05

4a) 4c) Actual 4a) 4b) Potential (tpy) 4c) Actual 4a) 4b) Potential (tpy) 4c) ActualPollutant Name Unrestricted Limited tons/year Unrestricted Limited tons/year Pollutant Name Unrestricted Limited tons/year

Total HAPs 6.50E-04 6.50E-04 6.50E-04 6.02E-05 6.02E-05 6.02E-05 Selenium 3.72E-05 3.72E-05 3.72E-05

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

4b) Potential (tpy)

Cadmium

4a)Pollutant Name

Antimony

4b) Potential (tpy)

4b) Potential (tpy)

4b) Potential (tpy)

4b) Potential (tpy)

4b) Potential (tpy)

4a)Pollutant Name

Arsenic

4a)

4b) Potential (tpy)

4b) Potential (tpy)

4b) Potential (tpy)

4b) Potential (tpy)

ChromiumPollutant Name

4a) 4b) Potential (tpy)Pollutant Name

Beryllium

Pollutant Name

MN Power Boswell Energy Center

Future Projected Actual to Baseline Actual

Future Projected Actuals to Baseline Actual Emission Summary

FPA BA Excludable FPA-BA-Ex FPA BA FPA - BA FPA BA FPA - BA FPA BA FPA - BA(tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy)

PM 1.66 1.35 0.57 0.00 53.43 43.34 10.09 0.58 0.21 0.37 10.29 8.34 1.94PM10 0.79 0.64 0.27 0.00 11.28 9.15 2.130 0.29 0.10 0.185 2.62 2.13 0.495PM2.5 0.12 0.10 0.04 0.00 1.18 0.95 0.22 0.04 0.02 0.03 0.26 0.21 0.05Lead 9.65E-06 7.83E-06 3.30E-06 0.00E+00 3.10E-04 2.51E-04 5.85E-05 3.35E-06 1.21E-06 2.15E-06 5.97E-05 4.84E-05 1.13E-05HAPs -- -- -- -- -- -- -- -- -- -- -- -- --

BA = Baseline ActualFPA = Future Projected ActualPTE = Potential to EmitEx = Excludable

Future Projected to Baseline Emission Summary

FP B FP - B FP B FP - B FP B FP - B FP B FP - B

(lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr)2.00 2.00 0.00 10.48 10.48 0.00 1.04 0.37 0.67 2.35 1.90 0.440.95 0.95 0.00 2.21 2.21 0.00 0.52 0.19 0.33 0.60 0.49 0.110.14 0.14 0.00 0.23 0.23 0.00 0.08 0.03 0.05 0.06 0.05 0.01

-- -- -- -- -- -- -- -- -- -- -- ---- -- -- -- -- -- -- -- -- -- -- --

B = Baseline PTEFP = Future Projected PTE

Coal Stockpile Handling (FS006/FUGI11)Coal Stockpile Maintenance (FS005/FUGI6)

PM10PM2.5

HAPsLead

Coal Stockpile Wind Erosion (FS001)Coal Stockpile Handling (FS006) Coal Stockpile Maintenance (FS005) Unpaved Roads (FS004)Pollutant

Pollutant

PM

Unpaved Roads (FS004)Coal Stockpile Wind Erosion (FS001)Coal Stockpile Maintenance (FS005)Coal Stockpile Handling (FS006)

Coal Stockpile Wind Erosion (FS001FUGI9)Unpaved Roads (FS004/FUGI3)Unloading Dust Collector (Insig. Act/EQUI111 & EQUI112)PROPOSED Coal Stockpile Handling (EU 034/FUGI11)

Emission SourceFugitive dust emissions from coal handling at the existing coal stockpileEmissions from Pile Maintenance and Dozer Activity across existing coal stockpileEmissions due to wind erosion at the existing coal stockpileEmissions from Dozer traffic on the existing coal stockpileEmissions from Dust Collectors associated with coal handling and storageFugitive dust emissions from coal handling at the new PROPOSED coal stockpile

Description


Future Projected Actual to Baseline Actual

FPA BA Excludable FPA-BA-Ex PTE BA PTE-BA(tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy)3.33 2.70 1.14 0.00 12.39 0.00 12.39 24.79 25 No1.57 1.28 0.54 0.00 5.86 0.00 5.86 8.67 15 No0.24 0.19 0.08 0.00 0.89 0.00 0.89 1.19 10 No

1.93E-05 1.57E-05 6.60E-06 0.00E+00 7.19E-05 0.00 7.19E-05 1.44E-04 0.6 No-- -- -- -- 6.50E-04 0.00 6.50E-04 6.50E-04 -- --

Exceed

FP B FP - B FP B FP - B Threshold?

(lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) FP - B (lb/hr) (lb/hr)6.26 6.26 0.00 2.83 0.00 2.83 3.942.96 2.96 0.00 1.34 0.00 1.34 1.78 3.42 No0.45 0.45 0.00 0.20 0.00 0.20 0.26

-- -- -- 1.64E-05 0.00 1.64E-05 1.64E-05 0.025 No-- -- -- 1.48E-04 0.00 1.48E-04 1.48E-04

1 State Threshold for PM10 is for Minor Amendment while the State Threshold for Lead is for Insignificant Amendment.

Exceed PSD Threshold?

TOTALState

Modification Threshold1

PROPOSED Coal Stockpile Handling (EU 034)Unloading Dust Collector (Insig. Act)

PSD Threshold

Projected Emission

Unloading Dust Collector (Insig. Act) PROPOSED Coal Stockpile Handling (EU 034)

This data was generated by the MPCA and used to populate "Table 3. Title I emissions summary – hybrid emissions test" in the TSD for the title V reissuance permit No. 06100004-008

PM PM10 PM2.5 PbATPA increase = 12.4 2.81 0.3 7.20E-05

PTE increase = 14.59 6.9 1.04 8.46E-05Total project increase = 26.99 9.71 1.34 1.57E-04

69.29 15.22 1.84 4.02E-0455.94 13.30 1.47 3.24E-0413.35 1.92 0.37 7.79E-05

Table 3 Excludable emissions = 1.71 0.81 0.12 9.90E-0612.4 2.81 0.30 7.20E-05

14.59 6.9 1.04 8.46E-0526.99 9.71 1.34 1.57E-04

Unlimited emissions increase for new portable conveyors. The unlimited tpy new portable conveyor emissions were calculated using the same inputs listed in the "Input Summary" worksheet except the 20% moisture content was replaced by the 17.8% geometric mean moisture content from AP-42 table 11.9-3 for coal loading, to calculate unlimited PTE.

PTE increase =FPA-BA-Exl (ATPA) =

Total project increase =

Table 3 FPA-BA emissions =

Table 3 FPA emissions =Table 3 BA emissions =

Month Tons24-Month

Rolling Total (Tons)

May-10 358,842.12 --Jun-10 324,119.23 --Jul-10 373,940.58 --Aug-10 222,122.06 --Sep-10 343,310.56 --Oct-10 385,242.45 --Nov-10 257,452.30 --Dec-10 251,930.40 --Jan-11 285,909.60 --Feb-11 340,045.50 --Mar-11 399,419.44 --Apr-11 483,002.70 --May-11 136,906.60 --Jun-11 320,084.13 --Jul-11 361,952.58 --Aug-11 441,367.05 --Sep-11 287,315.94 --Oct-11 377,942.24 --Nov-11 467,181.17 --Dec-11 424,618.99 --Jan-12 500,527.41 --Feb-12 401,254.02 --Mar-12 415,567.43 --Apr-12 69,682.85 8,229,737.31May-12 223,506.56 8,094,401.75Jun-12 349,777.39 8,120,059.90Jul-12 376,056.87 8,122,176.19Aug-12 403,717.51 8,303,771.64Sep-12 498,960.89 8,459,421.97Oct-12 307,043.99 8,381,223.51Nov-12 375,845.67 8,499,616.87Dec-12 330,555.75 8,578,242.23Jan-13 393,205.07 8,685,537.70Feb-13 340,160.51 8,685,652.71Mar-13 452,833.20 8,739,066.47Apr-13 484,689.98 8,740,753.75May-13 266,524.73 8,870,371.88Jun-13 332,893.64 8,883,181.38Jul-13 346,570.33 8,867,799.13Aug-13 277,068.26 8,703,500.33Sep-13 339,877.50 8,756,061.90Oct-13 343,672.48 8,721,792.13Nov-13 390,069.17 8,644,680.13Dec-13 317,748.09 8,537,809.23Jan-14 426,859.51 8,464,141.33Feb-14 447,545.81 8,510,433.12Mar-14 488,702.06 8,583,567.74Apr-14 471,997.55 8,985,882.44May-14 388,037.73 9,150,413.61Jun-14 263,721.08 9,064,357.30Jul-14 276,926.38 8,965,226.81Aug-14 305,356.18 8,866,865.48Sep-14 356,668.44 8,724,573.03Oct-14 400,152.93 8,817,681.97Nov-14 545,666.94 8,987,503.25Dec-14 516,140.64 9,173,088.14Jan-15 559,662.58 9,339,545.65Feb-15 448,208.00 9,447,593.14Mar-15 454,910.00 9,449,669.94 <-MaximumApr-15 321,518.00 9,286,497.96

Actual Coal Tonnages


Input Summary

Baseline ActualFuture Projected

ActualsAnnual Coal Throughput (Tons) 4,724,834.97 5,824,834.97 Additional Coal Throughput (Tons) 1,100,000Hours of Operation 2080 2080 Maximum Throughput for Excludable Emissions 6,715,951Hourly Coal Throughput (Tph) 2271.56 2800.40Stockpile size (acres) 18 50Dozer Activity (VMT/day) 55.56 68.50 Based on coal throughput.Dozer Activity (VMT/day) 55.56 154.3333333 Based on pile size.

Number of Conveyor drop points 11Moisture Content (%) 20 %Silt Content (%) 4.8 %Dozer VMT per ton coal 0.0105 VMT/ton coal 0.0105 mi/tonDozer speed 6 mph 6 mph

OR0.012 mi/ton

7.1 mph

MN Power Boswell Energy CenterExcludable Emissions

Coal HandlingFUGITIVE DUST EMISSIONS FROM PRODUCT HANDLING

E = k * (0.0032) * (U/5)^1.3 * (M/2)^-1.4

where:E = Emission factor (lb/ton material handled) from AP-42, Section 13.2.4, Equation 1, (11/06).k = Particle size multiplier (dimensionless) from AP-42, pg. 13.2.4-4.U = Mean wind speed, (mph) is based on MPCA default value of 20 mph for 24-hour averaging period.M = Mean moisture content (%) is based on data from Minnesota Power.

Emission Factor CalculationsMaterial Pollutant Particle Size Mean Wind Moisture Uncontrolled Control Controlled

Multiplier, k Speed, U Content, M mission Factor, Efficiency Factor, E(mph) (%) (lb/ton) (%) (lb/ton)

Coal PM 0.74 20 20.0 0.0006 0% 0.0006Coal PM10 0.35 20 20.0 0.0003 0% 0.0003Coal PM2.5 0.053 20 20.0 0.0000 0% 0.0000

Excludable Emissions - PM Annual EmissionsMPCA ID Model ID Description Controlled Maximum

PM Emission Maximum EmissionsFactor, E Throughput(lb/ton) (tons/year) (tpy)

FS006 BECFS101 Coal Stockpile: Material Han 0.0006 6,715,950.90 1.919

Excludable Emissions - PM10 Annual EmissionsMPCA ID Model ID Description Controlled Maximum

PM10 Emission Maximum EmissionsFactor, E Throughput(lb/ton) (tons/year) (tpy)


Excludable Emissions - PM2.5 Annual EmissionsMPCA ID Model ID Description Controlled Maximum

PM2.5 Emission Maximum EmissionsFactor, E Throughput(lb/ton) (tons/year) (tpy)


Pollutant PM PM10 PM2.5

Max Emissions (tons/yr): 1.92 0.91 0.14Ave Annual Emissions

(tons/yr): 1.35 0.64 0.10Excludable Emissions

(tons/yr): 0.57 0.27 0.04

MN Power - Boswell Energy CenterExcludable Insignicant Activity Calculations

E = k * (0.0032) * (U/5)^1.3 * (M/2)^-1.4

where:E = Emission factor (lb/ton material handled) from AP-42, Section 13.2.4, Equation 1, (11/06).k = Particle size multiplier (dimensionless) from AP-42, pg. 13.2.4-4.U = Mean wind speed, (mph) is based on MPCA default value of 20 mph for 24-hour averaging period.M = Mean moisture content (%) is based on MP coal analyses.




Dust Exhaust Max Maximum PM PM10 PM2.5Collection DC System Name Flowrate Capacity Throughput

ID (acfm) ton/hr ton/yr (tpy) (tpy) (tpy)

DC-4 Coal Storage Silo Bldg 130,850 3550.00 6,715,951 1.92 0.91 0.14 DC-7 Railcar Dumper Baghouse 155,000 7400.00 6,715,951 1.92 0.91 0.14

Sums 3.84 1.82 0.27

Pollutant PM PM10 PM2.5

Max Emissions (tons/yr): 3.84 1.82 0.27Ave Annual Emissions

(tons/yr): 2.70 1.28 0.19Excludable Emissions

(tons/yr): 1.14 0.54 0.08

Total Excludable EmissionsPM PM10 PM2.5

Excludable Excludable Excludable(tpy) (tpy) (tpy)

1.71 0.81 0.12

Comment

MN Power Boswell Energy CenterCoal Handling

FUGITIVE DUST EMISSIONS FROM PRODUCT HANDLING

E = k * (0.0032) * (U/5)^1.3 * (M/2)^-1.4



Multiplier, k Speed, U Content, M Emission Factor, E Efficiency Factor, E(mph) (%) (lb/ton) (%) (lb/ton)


Baseline Emissions - PM Hourly Emissions Annual EmissionsMPCA ID Model ID Description Controlled Baseline

PM Emission Emission Baseline EmissionsFactor, E Throughput Rate Throughput(lb/ton) (tons/hr) (lbs/hr) (tons/year) (tpy)

FS006 BECFS101 Coal Stockpile: Material Handling 0.0006 3,500.00 2.000 4,724,834.97 1.350

Baseline Emissions - PM10 Hourly Emissions Annual EmissionsMPCA ID Model ID Description Controlled Baseline

PM10 Emission Emission Baseline EmissionsFactor, E Throughput Rate Throughput(lb/ton) (tons/hr) (lbs/hr) (tons/year) (tpy)


BaselineEmissions - PM2.5 Hourly Emissions Annual EmissionsMPCA ID Model ID Description Controlled Baseline

PM2.5 Emission Emission Baseline EmissionsFactor, E Throughput Rate Throughput(lb/ton) (tons/hr) (lbs/hr) (tons/year) (tpy)


Pile Maintenance

Pile MaintenanceDozer Activity across stockpiles

Baseline EmissionsMPCA ID Model ID Description k s M

% % PM PM10 PM2.5 PM PM10 PM2.5FS005 BECFS101 Coal Storage Pile Maintenance 0.75 4.8 20.0 10.48 2.21 0.23 43.34 9.15 0.95

Total 43.34 9.15 0.95

From AP-42 Section 11.9, Western Surface Coal Mining, Table 11.9-1 (10/98)PM PM10 PM2.5

TSP <= 30ug TSP <= 15ug Scaling factor = 0.022 * TSPEF = (78.4)(s)^1.2 k(18.6)(s)^1.5

(M)^1.3 (M)^1.4where:

k = (PM10 mult factor), lb/hrs = Silt content Coal: From Minnesota Power, 4.8%

M = Moisture Content Coal: From Minnesota Power, 20%

6 mph49,611 VMT/yr

8268.46 hr/yr

Emission Factor (lb/hr) Emissions (ton/yr)

Wind Erosion Summary Wind Erosion Summary Wind Erosion Summary1.12 m/s 1.12 m/s 1.12 m/s

784,074 ft2 784,074 ft2 784,074 ft21.000 0.500 0.075

Coal Storage Pile - Wind Erosion Coal Storage Pile - Wind Erosion Coal Storage Pile - Wind Erosion

2006 2007 2008 2009 2010 2006 2007 2008 2009 2010 2006 2007 2008 2009 2010January 19.90 - 62.99 48.96 - January 9.95 - 31.49 24.48 - January 1.49 - 4.72 3.67 - February - 117.87 19.05 - - February - 58.93 9.52 - - February - 8.84 1.43 - - March - - 24.73 - - March - - 12.36 - - March - - 1.85 - - April 2.84 - 9.21 - - April 1.42 - 4.60 - - April 0.21 - 0.69 - - May 5.99 118.74 47.60 33.24 - May 2.99 59.37 23.80 16.62 - May 0.45 8.91 3.57 2.49 - June 106.76 - 123.86 159.48 60.83 June 53.38 - 61.93 79.74 30.41 June 8.01 - 9.29 11.96 4.56 July - 147.67 - - - July - 73.84 - - - July - 11.08 - - - August - - - - - August - - - - - August - - - - - September - - - - 77.10 September - - - - 38.55 September - - - - 5.78 October 189.71 - - - 278.39 October 94.85 - - - 139.20 October 14.23 - - - 20.88 November - - - - - November - - - - - November - - - - - December - - - - - December - - - - - December - - - - - Total 325.20 384.28 287.43 241.68 416.32 Total 162.60 192.14 143.71 120.84 208.16 Total 24.39 28.82 21.56 18.13 31.22

Max yr 416.32 lb/yr Max mo 278.39 lb/month Max yr 208.16 lb/yr Max mo 139.20 lb/month Max yr 31.22 lb/yr Max mo 20.88 lb/month0.0475 lb/hr PM 0.37 lb/hr PM 0.0238 lb/hr PM10 0.19 lb/hr PM10 0.0036 lb/hr PM2.5 0.03 lb/hr PM2.5

Notes: Notes:Wind Erosion calculations were based on AP-42 Section 13.2.5 Wind Erosion calculations were based on AP-42 Section 13.2.5For these piles, Pile B1 from Figure 13.2.5-2 in AP-42 was used. For these piles, Pile B1 from Figure 13.2.5-2 in AP-42 was used.Threshold Friction Velocity of 1.12 m/s from Table 13.2.5-2 Threshold Friction Velocity of 1.12 m/s from Table 13.2.5-2Daily 2006-2010 wind speeds from Park Rapids met station Daily 2006-2010 wind speeds from Park Rapids met station 18 acres disturbed daily 18 acres disturbed daily

Threshold Friction Velocity =Surface Area =For PM2.5, k =

PM2.5 Emissions (lb/yr)

Threshold Friction Velocity =Surface Area =

For PM, k =

PM Emissions (lb/yr)

Threshold Friction Velocity =Surface Area =For PM10, k =

PM10 Emissions (lb/yr)

H:\MP BEC\draft documents\Public Notice Documents w_App & Attach\TSD Attachments Public Notice\[TSD Att 2 - Coal Stockpile Exp IND20150001 Calcs.xlsx.xls]Baseline Unpaved Roads

MN Power Boswell Energy CenterUnpaved Haul Roads FS007 FS004 (corrected by MCole; FS007 is paved roads)

Unpaved Haul Road Equation 1a (AP-42 Section 13.2.2 - 11/06)E = k * (s/12)a * (W/3)b * [(365-P)/365]

where:E = Emission factor (lb/VMT, vehicle miles traveled)k = Particle size multiplier (lb/VMT) from AP-42, Table 13.2.2-2, k=4.9 PM, k= 1.5 PM10, k=0.15 PM2.5.

a,b = Empirical constants (a, b) from AP-42, Table 13.2.2-2, a=0.7 PM, a=0.9 PM10, a=0.9 PM2.5, b=0.45.s = Road surface material silt content (%) From testing of Fly Ash Haul Road 3.5%

Silt content of Fly ash used for trips on Fly ash pond, data from testing 70.0%Silt content of coal used for trips on coal pile, data from testing 4.8%MPCA Default used for other roads. 10.0%

W = Mean vehicle weight based on the "fleet" average weight of all vehicles traveling the road.P = Number of days in a year with at least 0.01 in of precipitation, P = 110 days

FS004 - UNPAVED ROADS FOR ANNUAL AVERAGING PERIODRound Trip Daily Number of Miles Avg. Veh. Wt. Avg. Avg Silt Uncontrolled Emissions Dust Control Strategy Controlled Emissions

Distance Production Trips/Day Per Year Weight Vehicle Content (tpy) Control Control (tpy)Traffic Type (mi.) (tons) (tons) (tons) (%) PM PM10 PM2.5 PM PM10 PM2.5 Method Efficiency (%) PM PM10 PM2.5

1. Coal Stockpile

Dozer/Scraper See Below See Below See Below 49,611 12.00 12.00

BECFS401 49611 12.00 4.8 3.36 0.86 0.09 83.44 21.27 2.13Moisture

Content of Coal

90.0 8.34 2.13 0.21

Uncontrolled Emissions Controlled Emissions(tpy) (tpy)

PM PM10 PM2.5 PM PM10 PM2.5

83.44 21.27 2.13 8.34 2.13 0.21Controlled Emissions

Detailed information for Actual Calculations (lb/hr)PM PM10 PM2.5

1.90 0.49 0.05Coal Stockpile InformationDozer VMT per ton coal VMT/ton coal Data from MN Power 5-7-15Annual Coal Throughput tons/yrPotential total facility Loader mileage VMT/yr

0.0105 4,724,83549,610.77

Vehicle EmissionFactor (lb/VMT)

Value

MN Power - Boswell Energy CenterInsignicant Activity Calculations

E = k * (0.0032) * (U/5)^1.3 * (M/2)^-1.4

where:E = Emission factor (lb/ton material handled) from AP-42, Section 13.2.4, Equation 1, (11/06).k = Particle size multiplier (dimensionless) from AP-42, pg. 13.2.4-4.U = Mean wind speed, (mph) is based on MPCA default value of 20 mph for 24-hour averaging period.M = Mean moisture content (%) is based MP coal analyses.

Emission Factor Calculations Material Pollutant Particle Size Mean Wind Moisture Uncontrolled Control Controlled



Dust Exhaust Max Annual PM PM PM10 PM10 PM2.5 PM2.5Collection DC System Name Flowrate Capacity Throughput Max Baseline Max Baseline Max Baseline

ID (acfm) ton/hr ton/yr (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy)

DC-4 Coal Storage Silo Bldg 130,850 3550.00 4,724,835 2.03 1.35 0.96 0.64 0.15 0.10 DC-7 Coal Rotary Car Dumper Baghouse 155,000 7400.00 4,724,835 4.23 1.35 2.00 0.64 0.30 0.10

Sums 6.26 2.70 2.96 1.28 0.45 0.19

Comment



E = k * (0.0032) * (U/5)^1.3 * (M/2)^-1.4





Future Emissions - PM Hourly Emissions Annual EmissionsMPCA ID Model ID Description Controlled Future Future

PM Emission Emission Projected ProjectedFactor, E Throughput Rate Throughput Actuals(lb/ton) (tons/hr) (lbs/hr) (tons/year) (tpy)


Future Emissions - PM10 Hourly Emissions Annual EmissionsMPCA ID Model ID Description Controlled Future Future

PM10 Emission Emission Projected ProjectedFactor, E Throughput Rate Throughput Actuals(lb/ton) (tons/hr) (lbs/hr) (tons/year) (tpy)


Future Emissions - PM2.5 Hourly Emissions Annual EmissionsMPCA ID Model ID Description Controlled Future Future

PM2.5 Emission Emission Projected ProjectedFactor, E Throughput Rate Throughput Actuals(lb/ton) (tons/hr) (lbs/hr) (tons/year) (tpy)


Pile Maintenance

Pile MaintenanceDozer Activity across stockpiles

Future EmissionsMPCA ID Model ID Description k s M

% % PM PM10 PM2.5 PM PM10 PM2.5FS005 BECFS101 Coal Storage Pile Maintenance 0.75 4.8 20.0 10.48 2.21 0.23 53.43 11.28 1.18

Total 53.43 11.28 1.18

From AP-42 Section 11.9, Western Surface Coal Mining, Table 11.9-1 (10/98)PM PM10 PM2.5

TSP <= 30ug TSP <= 15ug Scaling factor = 0.022 * TSPEF = (78.4)(s)^1.2 k(18.6)(s)^1.5

(M)^1.3 (M)^1.4where:

k = (PM10 mult factor), lb/hrs = Silt content Coal: From Minnesota Power, 4.8%

M = Moisture Content Coal: From Minnesota Power, 20%

6 mph61160.77 VMT/yr10193.46 hr/yr

Emission Factor (lb/hr) Emissions (ton/yr)

Wind Erosion Summary Wind Erosion Summary Wind Erosion Summary1.12 m/s 1.12 m/s 1.12 m/s

2,177,983 ft2 2,177,983 ft2 2,177,983 ft21.000 0.500 0.075

Coal Storage Pile - Wind Erosion Coal Storage Pile - Wind Erosion Coal Storage Pile - Wind Erosion

2006 2007 2008 2009 2010 2006 2007 2008 2009 2010 2006 2007 2008 2009 2010January 55.29 - 174.97 136.00 - January 27.64 - 87.48 68.00 - January 4.15 - 13.12 10.20 - February - 327.42 52.90 - - February - 163.71 26.45 - - February - 24.56 3.97 - - March - - 68.69 - - March - - 34.34 - - March - - 5.15 - - April 7.90 - 25.57 - - April 3.95 - 12.79 - - April 0.59 - 1.92 - - May 16.63 329.83 132.23 92.34 - May 8.31 164.92 66.12 46.17 - May 1.25 24.74 9.92 6.93 - June 296.56 - 344.05 442.99 168.97 June 148.28 - 172.02 221.49 84.49 June 22.24 - 25.80 33.22 12.67 July - 410.20 - - - July - 205.10 - - - July - 30.77 - - - August - - - - - August - - - - - August - - - - - September - - - - 214.16 September - - - - 107.08 September - - - - 16.06 October 526.97 - - - 773.31 October 263.49 - - - 386.66 October 39.52 - - - 58.00 November - - - - - November - - - - - November - - - - - December - - - - - December - - - - - December - - - - - Total 903.34 1,067.45 798.41 671.33 1,156.44 Total 451.67 533.72 399.21 335.66 578.22 Total 67.75 80.06 59.88 50.35 86.73

Max yr 1,156.44 lb/yr Max mo 773.31 lb/month Max yr 578.22 lb/yr Max mo 386.66 lb/month Max yr 86.73 lb/yr Max mo 58.00 lb/month0.1320 lb/hr PM 1.04 lb/hr PM 0.0660 lb/hr PM10 0.52 lb/hr PM10 0.0099 lb/hr PM2.5 0.08 lb/hr PM2.5

Notes: Notes:Wind Erosion calculations were based on AP-42 Section 13.2.5 Wind Erosion calculations were based on AP-42 Section 13.2.5For these piles, Pile B1 from Figure 13.2.5-2 in AP-42 was used. For these piles, Pile B1 from Figure 13.2.5-2 in AP-42 was used.Threshold Friction Velocity of 1.12 m/s from Table 13.2.5-2 Threshold Friction Velocity of 1.12 m/s from Table 13.2.5-2Daily 2006-2010 wind speeds from Park Rapids met station Daily 2006-2010 wind speeds from Park Rapids met station 50 acres disturbed daily 50 acres disturbed daily

Threshold Friction Velocity =Surface Area =

For PM, k =

PM Emissions (lb/yr)

Threshold Friction Velocity =Surface Area =For PM2.5, k =

PM2.5 Emissions (lb/yr)

Threshold Friction Velocity =Surface Area =For PM10, k =

PM10 Emissions (lb/yr)

H:\MP BEC\draft documents\Public Notice Documents w_App & Attach\TSD Attachments Public Notice\[TSD Att 2 - Coal Stockpile Exp IND20150001 Calcs.xlsx.xls]FPA Unpaved Roads

MN Power Boswell Energy CenterUnpaved Haul Roads FS007 FS004 (corrected by MCole; FS007 is paved roads)

Unpaved Haul Road Equation 1a (AP-42 Section 13.2.2 - 11/06)E = k * (s/12)a * (W/3)b * [(365-P)/365]

where:E = Emission factor (lb/VMT, vehicle miles traveled)k = Particle size multiplier (lb/VMT) from AP-42, Table 13.2.2-2, k=4.9 PM, k= 1.5 PM10, k=0.15 PM2.5.

a,b = Empirical constants (a, b) from AP-42, Table 13.2.2-2, a=0.7 PM, a=0.9 PM10, a=0.9 PM2.5, b=0.45.s = Road surface material silt content (%) From testing of Fly Ash Haul Road 3.5%

Silt content of Fly ash used for trips on Fly ash pond, data from testing 70.0%Silt content of coal used for trips on coal pile, data from testing 4.8%MPCA Default used for other roads. 10.0%

W = Mean vehicle weight based on the "fleet" average weight of all vehicles traveling the road.P = Number of days in a year with at least 0.01 in of precipitation, P = 110 days

FS004 - UNPAVED ROADS FOR ANNUAL AVERAGING PERIODRound Trip Daily Number of Miles Avg. Veh. Wt. Avg. Avg Silt Uncontrolled Emissions Dust Control Strategy Controlled Emissions

Distance Production Trips/Day Per Year Weight Vehicle Content (tpy) Control Control (tpy)Traffic Type (mi.) (tons) (tons) (tons) (%) PM PM10 PM2.5 PM PM10 PM2.5 Method Efficiency (%) PM PM10 PM2.5

1. Coal Stockpile

Dozer/Scraper See Below See Below See Below 61,161 12.00 12.00

BECFS401 61161 12.00 4.8 3.36 0.86 0.09 102.86 26.22 2.62Moisture

Content of Coal

90.0 10.29 2.62 0.26

Uncontrolled Emissions Controlled Emissions(tpy) (tpy)

PM PM10 PM2.5 Pb PM PM10 PM2.5

102.86 26.22 2.62 5.966E-05 10.29 2.62 0.26Controlled Emissions

Detailed information for Future Calculations (lb/hr)PM PM10 PM2.5

2.35 0.60 0.06Coal Stockpile InformationDozer VMT per ton coal VMT/ton coal Data from MN Power 5-7-15Annual Coal Throughput tons/yrPotential total facility Loader mileage VMT/yr

0.0105 5,824,83561,160.77

Vehicle EmissionFactor (lb/VMT)

Value

MN Power - Boswell Energy CenterInsignicant Activity Calculations

E = k * (0.0032) * (U/5)^1.3 * (M/2)^-1.4

where:E = Emission factor (lb/ton material handled) from AP-42, Section 13.2.4, Equation 1, (11/06).k = Particle size multiplier (dimensionless) from AP-42, pg. 13.2.4-4.U = Mean wind speed, (mph) is based on MPCA default value of 20 mph for 24-hour averaging period.M = Mean moisture content (%) is based MP coal analyses.

Emission Factor Calculations Material Pollutant Particle Size Mean Wind Moisture Uncontrolled Control Controlled



Dust Exhaust Max Annual PM PM PM10 PM10 PM2.5 PM2.5Collection DC System Name Flowrate Capacity Throughput Max FPA Max FPA Max FPA

ID (acfm) ton/hr ton/yr (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy)

DC-4 Coal Storage Silo Bldg 130,850 3550.00 5,824,835 2.03 1.66 0.96 0.79 0.15 0.12 DC-7 Coal Rotary Car Dumper Baghouse 155,000 7400.00 5,824,835 4.23 1.66 2.00 0.79 0.30 0.12

Sums 6.26 3.33 2.96 1.57 0.45 0.24 Pb 1.93E-05

Comment



E = k * (0.0032) * (U/5)^1.3 * (M/2) -̂1.4

where:E = Emission factor (lb/ton material handled) from AP-42, Section 13.2.4, Equation 1, (11/06).k = Particle size multiplier (dimensionless) from AP-42, pg. 13.2.4-4.U = Mean wind speed, (mph) confirmd by MPCA staff using 2012 - 2016 Hibbing met data for 24-hour averaging period.M = Mean moisture content (%) is based on data from Minnesota Power.




Potential Emissions - PM Hourly Emissions Annual EmissionsMPCA ID Model ID Description Controlled Number Potential

PM Emission Emission of toFactor, E Throughput Rate Throughput Transfer Emit

Points(lb/ton) (tons/hr) (lbs/hr) (tons/year) (tpy)

Conveyor transferring coal across railroad 0.0006 450.00 2.829 3,942,000.00 11.00 12.392

Potential Emissions - PM10 Hourly Emissions Annual EmissionsMPCA ID Model ID Description Controlled Number Potential

PM10 Emission Emission of toFactor, E Throughput Rate Throughput Transfer Emit



Potential Emissions - PM2.5 Hourly Emissions Annual EmissionsMPCA ID Model ID Description Controlled Number Potential

PM2.5 Emission Emission of toFactor, E Throughput Rate Throughput Transfer Emit



Max hourly throughput of 450 tons/hr based on Jeff McCulloch 03-21-2015 emailAnnual throughput based on max hourly throughput of 450 tons/hr and 8760 hr/yr.

Potential Emissions - Lead

MPCA ID Model ID Pollutant Name

Maximum Weight Fraction in PM

emissions (ppm)

Maximum Uncontrolled PM Emission Rate

(lbs/hr)

Maximum Uncontrolled

Emission Rate (lbs/hr)


(tons/yr)

Maximum Uncontrolled

Emission Rate (tons/hr)

Lead 5.8 2.829 1.64E-05 12.39 7.19E-05Lead calculation assumes worst case lead in coal for all coal (5.8 ppm).



Potential Particulate HAP Emissions

Particulate HAP Name

Weight Fraction

HAP in PM emissions1

(ppm)


(lbs/hr)

Maximum Uncontrolled HAP

Emission Rate (lbs/hr)


(tons/yr)

Maximum Uncontrolled HAP

Emission Rate (tons/yr)

Antimony 0.17 2.83 4.81E-07 12.39 2.11E-06Arsenic 3.50 2.83 9.90E-06 12.39 4.34E-05Beryllium 0.36 2.83 1.02E-06 12.39 4.46E-06Cadmium 0.22 2.83 6.22E-07 12.39 2.73E-06Chromium 4.86 2.83 1.37E-05 12.39 6.02E-05Cobalt 2.20 2.83 6.22E-06 12.39 2.73E-05Manganese 32.00 2.83 9.05E-05 12.39 3.97E-04Mercury 0.13 2.83 3.68E-07 12.39 1.61E-06Nickel 6.02 2.83 1.70E-05 12.39 7.46E-05Selenium 3.00 2.83 8.49E-06 12.39 3.72E-05Total 1.48E-04 6.50E-041HAP Fraction: Maximum from vendor data for the three types of coal combusted.

ATTACHMENT 3 – SUBJECT ITEM INVENTORY AND FACILITY REQUIREMENTS



Agency Interest Name Subject Item ID Subject Item Designation Subject Item Description

Minnesota Power -Boswell Energy Center

ACTV4 Null All IA's

AISI2493 Null Null

COMG1 GP004 SO2 LimitsBoilers 1-4 Sulfur DioxideLimits

COMG3 GP005 Dust CollectorsLow Temperature FabricFilters Requirements

COMG4 GP002 COMS COMS Requirements

COMG6SO2, NOx, & CO2 CEMS, &Flow Monitors

SO2, NOx, & CO2 CEMS, &Flow Monitors Requireme..

COMG7 MATSPart 63, Subpart UUUUURequirements - REQUIRE..

COMG8 CO CEMS RequirementsCarbon Monoxide and CO2Diluent CEMS Requiremen..

COMG9EGU AdditionalRequirements

EGU Acid Rain, Ignitor Gun,Consent Decree, Hg Contr..

COMG10 Null2015 Coal StockpileExpansion

EQUI1 EU011 Crusher House C-8

EQUI3 EU013 Fly Ash - #1 & #2 Silo

EQUI4 EU014 #1&2 Fly Ash Separator

EQUI5 EU019 Unit 3 Limestone Silo

EQUI6 EU020 Unit 3 Limestone Day Bin 1


EQUI8 TK012 Ethylene Glycol

List of SIs

Agency Interest: Minnesota Power - Boswell Energy CenterAgency Interest ID: 2493Activity: IND20110004 (Part 70 Reissuance)

Details for:SI Category: NoneSI Type: All

Agency Interest Name Subject Item ID Subject Item Designation Subject Item DescriptionMinnesota Power -Boswell Energy Center






EQUI14 TK006 Fuel Oil



EQUI23 EU033Emergency Gen. Unit 3;1800 rpm constant speed ..

EQUI28 MR027 Boiler 3 COMS




EQUI35 MR041 Boiler 4 Air Flow Monitor

EQUI36 MR028 Boiler 1 SO2 CEMS

EQUI37 MR029 Boiler 1 NOx CEMS

EQUI38 MR030 Boiler 1 CO2 CEMS


List of SIs














EQUI52 MR045 Boiler 4 CO CEMS




EQUI71 MR024 Boiler 3 CO CEMS

EQUI81 EU023Emergency Gen. Unit 3APCE; 1800 rpm constant ..

EQUI82 EU001Unit 1 - wall fired drybottom

EQUI83 EU002 Unit 2 - wall fired drybottom

List of SIs






EQUI85 EU004 Unit 4 - tangential fired

EQUI86 EU024 Unit 4 Lime Silo

EQUI87 EU025 Unit 4 Lime Day Bin A

EQUI88 EU026 Unit 4 Lime Day Bin B

EQUI89 EU027 Unit 4 Lime Day Bin C

EQUI90 EU028 Unit 4 Lime Day Bin D

EQUI91 EU029 Unit 4 Lime Day Bin E

EQUI93 EU031 Fly Ash Silo B

EQUI94 EU032Fly Ash Silo B Loadout -Truck Bay

EQUI97 EU018Fly Ash Silo A Loadout -Truck Bay

EQUI98 EU017 Fly Ash Silo A

EQUI99 EU015Hg Additive Handling andUnit 3 PAC Silo

EQUI100 EU003 Unit 3 - tangential fired

EQUI102 EU012 Crusher House C-14

EQUI105 DA005 Units 1, 2, 3, 4 DAS

EQUI106 MR046 Sorbent Trap Hg Sampler

List of SIs




EQUI105 DA005 Units 1, 2, 3, 4 DAS

EQUI106 MR046 Sorbent Trap Hg Sampler

EQUI107 MR047 STRU13 PM CEMS

EQUI108 MR048 Boiler 4 PM CEMS

EQUI109 MR025 Boiler 3 Hg CEMS

EQUI110 MR026 Boiler 4 Hg CEMS

EQUI111 EU035 Rail Unloading

EQUI112 EU036 Lowering Well

EQUI113 EU047 Coal Silos

EQUI114 EU037 Transfer House A C16/C18

EQUI115 EU038 Transfer House B C9/C10

EQUI116 EU039 Dust Tank

EQUI117 EU040Units 1, 2, 3 Bunkers &Trippers

EQUI118 EU041 Unit 4 Bunkers & Trippers


EQUI120 EU030Unit 4 Activated CarbonSilo

EQUI122 NullFly Ash Silo A LoadoutSpout with Ventilated An..

EQUI123 Null Aqua Ammonia 1092

List of SIs




EQUI122 Null

Fly Ash Silo A LoadoutSpout with Ventilated An..





EQUI127 Null Gasoline 1064

EQUI128 Null Dust Suppressant 1107

EQUI129 Null Dust Suppressant 002

EQUI130 Null Waste Glycol 1106

FUGI1 EU006 Unit 3 Cooling Tower

FUGI2 EU005 Unit 4 Cooling Tower

FUGI3 FS004 Unpaved Road Dust

FUGI4 FS008Fly Ash Handling -Unloading to Disposal Cell..

FUGI5 FS003Fly Ash Pond - WindErosion

FUGI6 FS005Coal Stockpile & Fly AshPond Maintenance (Bulld..

FUGI7 FS002Bottom Ash Pond - WindErosion

FUGI8 FS009Fly Ash Disposal Cell - WindErosion

FUGI9 FS001 Coal Stockpile - WindErosion

List of SIs




FUGI8 FS009Fly Ash Disposal Cell - WindErosion

FUGI9 FS001Coal Stockpile - WindErosion

FUGI10 FS007 Paved Road Dust

FUGI11 FS006Coal Stockpile MaterialHandling (Existing Coal Dr..

STRU1 SV024 Unit 4 Lime Silo Stack

STRU2 SV025 Unit 4 Lime Day Bin A Stack

STRU3 SV026 Unit 4 Lime Day Bin B Stack

STRU4 SV027 Unit 4 Lime Day Bin C Stack

STRU5 SV028 Unit 4 Lime Day Bin D Stack

STRU6 SV029 Unit 4 Lime Day Bin E Stack

STRU7 SV030Unit 4 Activated CarbonSilo Stack

STRU8 SV031 Fly Ash Silo B Bin Stack

STRU9 SV032Fly Ash Silo B LoadoutTruck Bay Stack

STRU12 SV001 Units 1 & 2 Alternate Stack

STRU13 SV003Units 1, 2, & 3 CommonStack

STRU14 SV004 Unit 4 Stack

STRU15 SV005 Unit 4 cooling tower


List of SIs






STRU18 SV011 Crusher House

STRU19 SV012 Crusher House

STRU20 SV013Units 1&2 Fly Ash SiloStack

STRU21 SV014Units 1&2 Fly AshSeparator Stack

STRU22 SV018Fly Ash Silo A LoadoutTruck Bay Stack

STRU23 SV017Fly Ash Silo A & LoadoutSpout Vented Annular Ho..

STRU25 SV015 Unit 3 PAC Silo Stack

STRU26 SV019 Limestone Silo Stack

STRU27 SV020Unit 3 Limestone Day Bin 1Stack


STRU29 SV022Emergency Generator -Unit 3 APCE

STRU30 BG001 Unit 4

STRU31 BG002 Unit 3

STRU32 BG003 Scrubber Area, Unit 3

STRU33 BG004 Units 1 & 2

STRU34 BG005 Unit 1 Baghouse

List of SIs




STRU33 BG004 Units 1 & 2



STRU36 BG007 #4 Absorber Building

STRU37 BG008Existing Coal HandlingEquipment Building

STRU38 BG009 Unit 3 Cooling Tower

STRU39 BG010 Unit 4 Cooling Tower

STRU40 SV035 Rail Unloading

STRU41 SV042 Rail Unloading

STRU42 SV036 Lowering Well & Coal Silos

STRU43 SV043 Lowering Well & Coal Silos

STRU44 SV037 Transfer House C16/C18

STRU45 SV038 Transfer House C9/C10

STRU46 SV039 Dust Tank

STRU47 SV040Units 1, 2, 3 Bunkers &Trippers

STRU48 SV041 Unit 4 Bunkers & Trippers

STRU49 SV034Unit 4 EmergencyGenerator

STRU50 SV033 Unit 3 EmergencyGenerator

List of SIs




STRU49 SV034Unit4EmergencyGenerator


TFAC1 06100004Minnesota Power -Boswell Energy Center

TREA1 CE016Unit 3 Limestone SiloFabric Filter

TREA2 CE044Fly Ash Silo A LoadoutTruck Bay Fabric Filter

TREA5 CE020Unit 3 SCR (SelectiveCatalytic Reduction)

TREA6 CE027 Unit 4 LNB/SOFA

TREA7 CE028 Unit 4 ROTA-Mix SNCR

TREA8 CE019Unit 3 Low NOxBurners/Over-Fire Air

TREA9 CE021 Unit 3 Fabric Filter

TREA10 CE022Unit 3 Wet Flue GasDesulfurization


TREA12 CE025 Unit 1 ROFA

TREA13 CE026 Unit 2 ROFA




TREA21 CE030 Unit4Semi-DryFlueGasDesulfurization&High-Te..

List of SIs





TREA21 CE030Unit 4 Semi-Dry Flue GasDesulfurization & High-Te..

TREA22 CE031Unit 4 Activated CarbonInjection

TREA23 CE032Unit 4 Lime Silo FabricFilter

TREA24 CE033Unit 4 Lime Day Bin AFabric Filter

TREA25 CE034Unit 4 Lime Day Bin BFabric Filter

TREA26 CE035Unit 4 Lime Day Bin CFabric Filter

TREA27 CE036Unit 4 Lime Day Bin DFabric Filter

TREA28 CE029Unit 3 Activated CarbonInjection

TREA29 CE037Unit 4 Lime Day Bin EFabric Filter

TREA30 CE038Unit 4 Activated CarbonSilo Fabric Filter

TREA31 CE039 Fly Ash Silo B Fabric Filter

TREA32 CE040Fly Ash Silo B Truck BayFabric Filter

TREA33 CE041Paved roadwatering/sweeping

TREA34 CE042Dust Suppression byChemical Stabilizers or W..

TREA35 CE043 2 - 3 % Moisture Content

TREA36 CE015Fly Ash Silo A & LoadoutSpout Vented Annular Ho..

TREA37 CE007 Crusher House C-8 (DC-8)

List of SIs




TREA36 CE015

Fly Ash Silo A & LoadoutSpout Vented Annular Ho..

TREA37 CE007 Crusher House C-8 (DC-8)

TREA38 CE008Crusher House C-14(DC-14)

TREA39 CE009Fly Ash #1 & #2 Silo FabricFilter

TREA40 CE010#1 & #2 Fly Ash SeparatorFabric Filter

TREA41 CE013Unit 3 Activated CarbonSilo Fabric Filter

TREA42 CE017Limestone Day Bin 1 FabricFilter

TREA43 CE018Limestone Day Bin 2 FabricFilter

TREA46 CE045 Rail Unloading (DC-7)

TREA47 CE046Lowering Well & Coal Silos(DC-4)

TREA48 CE047Transfer House A C16/C18(DC-16)

TREA49 CE048Transfer House B C9/C10(DC-10)

TREA50 CE049 Dust Tank (DC-DT)

TREA51 CE050Units 1, 2, 3 Bunkers &Trippers (DC-12)

TREA52 CE051Unit 4 Bunkers & Trippers(DC-5)

List of SIs



Agency Interest Na.. Activity ID Subject Ite..Subject Item Type Description Subject Item ID Subject Ite..Subject Ite..Status Desc..Sub Attribute Description

Minnesota Power -Boswell EnergyCenter

IND20110004 Activity Insignificant Air Emissions Activity ACTV4 Null All IA's Active /Existing

Minn. R. 7007.1300, subp.3(B)(2)

Minn. R. 7007.1300, subp. 3(G)

Minn. R. 7007.1300, subp.3(H)(3)

Minn. R. 7007.1300, subp. 3(I)

Minn. R. 7007.1300, subp. 4

Insignificant air emissions activity


Details for:SI Category: ActivitySI Type: Insignificant Air Emissions Activity

Agency Interest Name Subject Item ID Subject Item DesignationSubject Item Description Group Member ID (padded)

Minnesota Power -Boswell Energy Center

COMG1 GP004 SO2 Limits Boilers 1-4 Sulfur DioxideLimits

EQUI82

EQUI83

EQUI85

EQUI100

STRU12

STRU13

STRU14

COMG3 GP005 Dust Collectors Low Temperature FabricFilters Requirements

TREA1

TREA2

TREA23

TREA24

TREA25

TREA26

TREA27

TREA29

TREA30

TREA31

Component Group (Members)

Agency Interest: Minnesota Power - Boswell Energy CenterAgency Interest ID: 2493Activity: None (Part 70 Reissuance)

Details for:SI Category: Component GroupSI Type: Air Component Group

Agency Interest Name Subject Item ID Subject Item DesignationSubject Item Description Group Member ID (padded)Minnesota Power -Boswell Energy Center


TREA30

TREA31

TREA32

TREA36

TREA37

TREA38

TREA39

TREA40

TREA41

TREA42

TREA43

TREA46

TREA47

TREA48

TREA49

TREA50

TREA51

TREA52






TREA51

TREA52

COMG4 GP002 COMS COMS Requirements EQUI28

EQUI29

EQUI30

EQUI34

COMG6 SO2, NOx, & CO2 CEMS, &Flow Monitors

SO2, NOx, & CO2 CEMS, &Flow MonitorsRequirements

EQUI35

EQUI36

EQUI37

EQUI38

EQUI39

EQUI40

EQUI41

EQUI42

EQUI43

EQUI44

EQUI45

EQUI50





COMG6 SO2, NOx, & CO2 CEMS, &Flow Monitors

SO2, NOx, & CO2 CEMS, &Flow MonitorsRequirements

EQUI45

EQUI50

EQUI51

EQUI53

EQUI54

EQUI55

COMG7 MATS Part 63, Subpart UUUUURequirements -REQUIREMENTS APPLYINDIVIDUALLY TO EACHCOMG7 BOILER ASAPPLICABLE, UNLESSOTHERWISE NOTED

EQUI82

EQUI83

EQUI85

EQUI100

COMG8 CO CEMS Requirements Carbon Monoxide andCO2 Diluent CEMSRequirements

EQUI50

EQUI52

EQUI55

EQUI71

COMG9 EGU AdditionalRequirements

EGU Acid Rain, IgnitorGun, Consent Decree, HgControl, TransportRule/CSAPR, & Test BurnAdditional Requirements(Apply individually toeach COMG9 EGU asapplicable unlessotherwise noted)

EQUI82

EQUI83

EQUI85

EQUI100







EQUI85

EQUI100

STRU12

STRU13

STRU14

TREA5

TREA6

TREA7

TREA8

TREA9

TREA10

TREA11

TREA12

TREA13

TREA14

TREA15

TREA16

TREA21







TREA16

TREA21

TREA22

TREA28

COMG10 Null 2015 Coal StockpileExpansion

EQUI111

EQUI112

FUGI3

FUGI6

FUGI9

FUGI11




Subject ItemCategory Description

Subject Item TypeDescription Subject Item ID

Subject ItemDesignation Subject Item Description Pollutant

Potential (lbs/hr)

Unrestricted Potential

(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Equipment Boiler EQUI82 EU001 Unit 1 - wall fired drybottom

1,1,1-Trichloroethane

1,2-Dibromoethane (Ethyl..

1,2-Dichloroethane

2-Chloroacetophenone

2-Methylnaphthalene

2,4-Dinitrotoluene

3-Methylcholanthrene

7,12-Dimethylbenz[a]ant..

Acenaphthene

Acenaphthylene

Acetaldehyde

Acetophenone

Acrolein

Anthracene

Antimony compounds

Arsenic compounds

Benzene

Benzo(a)anthracene

Benzo(b)fluoranthene

Benzo(ghi)perylene

Benzo(k)fluoranthene

Benzo[a]pyrene

Beryllium Compounds

Biphenyl

Bis(2-ethylhexyl) phthalate

Bromoform

Bromomethane (Methyl b..

Cadmium compounds

Carbon Dioxide

Carbon Dioxide Equivalent

Carbon disulfide

Carbon Monoxide

Chlorobenzene (Monochlo..

Chloroethane

Chloroform

Chloromethane

Chloromethylbenzene

Chromium compounds

Chrysene

Cobalt compounds

Cumene (Isopropylbenzen..

Cyanide compounds

Dibenz[a,h]anthracene

Dichloromethane (Methyl..

Dimethyl sulfate

Ethylbenzene

Fluoranthene

Fluorene

Formaldehyde

HAPs - Total

Hexane

Hydrochloric acid

Hydrofluoric acid


Isophorone

Lead

Manganese compounds

Mercury

Methane

Methyl ethyl ketone (MEK)

Methyl methacrylate

Methyl-tert-butylether

Methylhydrazine

Naphthalene

Nickel compounds

0.009916.05

0.002030.005550.06420.01150.593,296

0.006690.348

9.14e-050.102

0.00979176.6176.6

0.004280.000733

70.616.28941.70.07490.006960.04550.009360.005350.104111.9

0.005650.1311.610.155

1.74e-0540.19.42

0.017954.41980.0642

0.0002450.0001920.02510.01280.07767.42e-070.669

0.001420.02682.79e-050.06960.1870.1420.01580.01120.00589133.80.0348

996,430.4988,780.30.01360.04280.01040.01950.000910.005621.09e-051.11e-067.97e-061.11e-062.25e-050.3480.11

0.004825.77e-050.07760.004010.1526.8e-050.0001389.89e-061.11e-067.49e-051.48e-050.001870.0107

0.0003210.00535

0.009916.05

0.002030.005550.06420.011516.355,618.10.006690.348

9.14e-050.102

0.009794,333.71,136.50.004280.00073318,807.216.283,210.30.07490.006960.04550.009360.005350.104111.90.02220.1311.610.155

1.74e-0540.1321

0.0179366.05780.0642

0.0002450.0001920.02510.01280.07767.42e-070.669

0.001420.02682.79e-050.06960.1870.1420.01580.01120.00589133.80.0348

996,430.4988,780.30.01360.04280.01040.01950.000910.005621.09e-051.11e-067.97e-061.11e-062.25e-050.3480.11

0.004825.77e-050.07760.004010.1526.8e-050.0001389.89e-061.11e-067.49e-051.48e-050.001870.0107

0.0003210.00535

0.002263.66

0.0004640.001270.01470.002630.13752.5

0.001530.07942.09e-050.02320.0022440.3140.31

0.0009770.00016716.133.72215

0.01710.001590.01040.002140.001220.023825.6

0.005070.02990.3660.03543.98e-06

9.162.15

0.0040912.05810.01475.6e-054.38e-050.005740.002930.01771.69e-070.153

0.0003240.006116.36e-060.01590.04280.03240.00360.002570.0013430.54

0.00794227,495.5225,748.90.003120.009770.002380.004460.0002080.001282.49e-062.54e-071.82e-062.54e-075.14e-060.07940.0250.00111.32e-050.0177

0.0009160.03481.55e-053.14e-052.26e-062.54e-071.71e-053.39e-060.0004280.002447.33e-050.00122

PTE by subject item

Agency Interest: NoneAgency Interest ID: 2493Activity: None (Part 70 Reissuance)

Details for:SI Category: AllSI Type: All




Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)


Naphthalene

Nickel compounds

Nitrogen Oxides

Nitrous Oxide

Particulate Matter

Phenanthrene

Phenol

PM < 2.5 micron

PM < 10 micron

Polycyclic organic matter

Propionaldehyde

Pyrene

Selenium compounds

Styrene

Sulfur Dioxide

Sulfuric Acid Mist

Tetrachloroethylene (Per..

Toluene

Total Polycyclic aromatic ..

Vinyl acetate (Acetic acid)

Volatile Organic Compoun..

Xylenes, Total


1,1,1-Trichloroethane


1,2-Dichloroethane


2-Methylnaphthalene

2,4-Dinitrotoluene



Acenaphthene

Acenaphthylene

Acetaldehyde

Acetophenone

Acrolein

Anthracene

Antimony compounds

Arsenic compounds

Benzene

Benzo(a)anthracene


Benzo(ghi)perylene


Benzo[a]pyrene

Beryllium Compounds

Biphenyl


Bromoform


Cadmium compounds

Carbon Dioxide


Carbon disulfide

Carbon Monoxide


Chloroethane

Chloroform

Chloromethane

Chloromethylbenzene

Chromium compounds

Chrysene

Cobalt compounds


Cyanide compounds



0.009916.05

0.002030.005550.06420.01150.593,296

0.006690.348

9.14e-050.102

0.00979176.6176.6

0.004280.000733

70.616.28941.70.0749

0.009916.05

0.002030.005550.06420.011516.355,618.10.006690.348

9.14e-050.102

0.009794,333.71,136.50.004280.00073318,807.216.283,210.30.0749

0.002263.66

0.0004640.001270.01470.002630.13752.5

0.001530.07942.09e-050.02320.0022440.3140.31

0.0009770.00016716.133.72215

0.0171

0.0083813.59

0.001720.00470.05440.00974

0.52,790.10.005660.294

7.78e-050.08610.00829149.5149.5

0.003620.000622

59.813.78797.20.06340.005890.03850.007930.004530.088394.75

0.004780.1111.360.131

1.49e-05347.97

0.015246.06720.0544

0.0002080.0001630.02130.01090.06577.42e-070.5660.00120.02262.38e-050.05890.1590.12

0.01340.009510.00498113.20.0294843,490837,0140.01150.03620.008830.01650.000770.004769.35e-061.11e-066.86e-061.11e-061.92e-050.2940.09290.004084.9e-050.06570.00340.129

5.77e-050.0001179.89e-061.11e-066.34e-051.48e-050.001590.009060.0002720.00453

0.0083813.59

0.001720.00470.05440.0097413.844,755.80.005660.294

7.78e-050.08610.008293,668.5962

0.003620.00062215,920.613.782,717.60.06340.005890.03850.007930.004530.088394.750.01880.1111.360.131

1.49e-0534272

0.0152309.87230.0544

0.0002080.0001630.02130.01090.06577.42e-070.5660.00120.02262.38e-050.05890.1590.12

0.01340.009510.00498113.20.0294843,490837,0140.01150.03620.008830.01650.000770.004769.35e-061.11e-066.86e-061.11e-061.92e-050.2940.09290.004084.9e-050.06570.00340.129

5.77e-050.0001179.89e-061.11e-066.34e-051.48e-050.001590.009060.0002720.00453

0.001913.1

0.0003930.001070.01240.002220.11637

0.001290.06721.78e-050.01960.0018934.134.1

0.0008270.000142

13.73.15182

0.01450.001340.008790.001810.001030.020221.63

0.004290.02530.310.03

3.41e-067.761.82

0.0034610.20740.01244.74e-053.71e-050.004860.002480.015

1.69e-070.129

0.0002740.005175.42e-060.01340.03620.02740.003050.002170.0011425.9

0.00672192,577.6191,099.10.002640.008270.002020.003770.0001760.001092.13e-062.54e-071.57e-062.54e-074.39e-060.06720.0212

0.0009311.12e-050.015

0.0007760.02951.32e-052.66e-052.26e-062.54e-071.45e-053.39e-060.0003620.002076.2e-050.00103

PTE by subject item






Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)




Dimethyl sulfate

Ethylbenzene

Fluoranthene

Fluorene

Formaldehyde

HAPs - Total

Hexane

Hydrochloric acid

Hydrofluoric acid


Isophorone

Lead

Manganese compounds

Mercury

Methane


Methyl methacrylate


Methylhydrazine

Naphthalene

Nickel compounds

Nitrogen Oxides

Nitrous Oxide

Particulate Matter

Phenanthrene

Phenol

PM < 2.5 micron

PM < 10 micron


Propionaldehyde

Pyrene

Selenium compounds

Styrene

Sulfur Dioxide

Sulfuric Acid Mist


Toluene




Xylenes, Total

EQUI85 EU004 Unit 4 - tangential fired 1,1,1-Trichloroethane


1,2-Dichloroethane


2-Methylnaphthalene

2,4-Dinitrotoluene



Acenaphthene

Acenaphthylene

Acetaldehyde

Acetophenone

Acrolein

Anthracene

Antimony compounds

Arsenic compounds

Benzene

Benzo(a)anthracene


Benzo(ghi)perylene


Benzo[a]pyrene

Beryllium Compounds

0.0083813.59

0.001720.00470.05440.00974

0.52,790.10.005660.294

7.78e-050.08610.00829149.5149.5

0.003620.000622

59.813.78797.20.06340.005890.03850.007930.004530.088394.75

0.004780.1111.360.131

1.49e-05347.97

0.015246.06720.0544

0.0002080.0001630.02130.01090.06577.42e-070.5660.00120.02262.38e-050.05890.1590.12

0.01340.009510.00498113.20.0294843,490837,0140.01150.03620.008830.01650.000770.004769.35e-061.11e-066.86e-061.11e-061.92e-050.2940.09290.004084.9e-050.06570.00340.129

5.77e-050.0001179.89e-061.11e-066.34e-051.48e-050.001590.009060.0002720.00453

0.0083813.59

0.001720.00470.05440.0097413.844,755.80.005660.294

7.78e-050.08610.008293,668.5962

0.003620.00062215,920.613.782,717.60.06340.005890.03850.007930.004530.088394.750.01880.1111.360.131

1.49e-0534272

0.0152309.87230.0544

0.0002080.0001630.02130.01090.06577.42e-070.5660.00120.02262.38e-050.05890.1590.12

0.01340.009510.00498113.20.0294843,490837,0140.01150.03620.008830.01650.000770.004769.35e-061.11e-066.86e-061.11e-061.92e-050.2940.09290.004084.9e-050.06570.00340.129

5.77e-050.0001179.89e-061.11e-066.34e-051.48e-050.001590.009060.0002720.00453

0.001913.1

0.0003930.001070.01240.002220.11637

0.001290.06721.78e-050.01960.0018934.134.1

0.0008270.000142

13.73.15182

0.01450.001340.008790.001810.001030.020221.63

0.004290.02530.310.03

3.41e-067.761.82

0.0034610.20740.01244.74e-053.71e-050.004860.002480.015

1.69e-070.129

0.0002740.005175.42e-060.01340.03620.02740.003050.002170.0011425.9

0.00672192,577.6191,099.10.002640.008270.002020.003770.0001760.001092.13e-062.54e-071.57e-062.54e-074.39e-060.06720.0212

0.0009311.12e-050.015

0.0007760.02951.32e-052.66e-052.26e-062.54e-071.45e-053.39e-060.0003620.002076.2e-050.00103

0.0626101.50.01290.03510.4060.07283.72893.50.04232.2

0.0005750.6430.0715595.7595.70.02710.00463357.4103

3,574.10.4740.0440.2880.05920.03380.667080.0130.8290.1220.982

0.00010925.3859.60.113

105.62170.406250

0.001550.001210.1590.08120.4914e-064.23

0.008970.169

0.0001750.441.180.8970.09980.07110.03724,467.60.22

6,303,0006,254,6100.08630.2710.0660.124

0.005750.03556.83e-056e-06

4.97e-056e-06

0.0001412.2

0.6940.0305

0.0003630.4910.02540.965

0.0004420.000869

06e-06

0.0004748e-050.01180.06770.002030.0338

0.0626101.50.01290.03510.4060.0728103.4135,537.70.04232.2

0.0005750.6430.071527,413.17,188.80.02710.00463118,966.8

10312,184.40.4740.0440.2880.05920.03380.667080.140.8291790.982

0.000109253.842,0300.113

4,985.9450.4062,500

0.001550.001210.1590.08120.4914e-064.23

0.008970.169

0.0001750.441.180.8970.09980.07110.03724,467.60.22

6,303,0006,254,6100.08630.2710.0660.124

0.005750.03556.83e-056e-06

4.97e-056e-06

0.0001412.2

0.6940.0305

0.0003630.4910.02540.965

0.0004420.000869

06e-06

0.0004748e-050.01180.06770.002030.0338

0.014323.2

0.002940.008020.09270.01660.852,600

0.009660.502

0.0001310.1470.0163136136

0.006180.0010681.623.518160.1080.01

0.06570.01350.007730.151161.7

0.003210.1890.02790.224

2.49e-055.79513.6

0.025924.08660.092757.1

0.0003540.0002770.03630.01850.112

9.13e-070.966

0.002050.03864e-050.10.270.2050.02280.01620.00851,0200.0502

1,439,0401,427,9930.01970.06180.01510.02820.001310.008111.56e-051.37e-061.13e-051.37e-063.23e-050.5020.158

0.006958.3e-050.1120.00580.22

0.0001010.0001985.33e-051.37e-060.0001081.83e-050.00270.0155

0.0004640.00773

PTE by subject item






Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Equipment Boiler EQUI85 EU004 Unit 4 - tangential firedBenzo[a]pyrene

Beryllium Compounds

Biphenyl


Bromoform


Cadmium compounds

Carbon Dioxide


Carbon disulfide

Carbon Monoxide


Chloroethane

Chloroform

Chloromethane

Chloromethylbenzene

Chromium compounds

Chrysene

Cobalt compounds


Cyanide compounds



Dimethyl sulfate

Ethylbenzene

Fluoranthene

Fluorene

Fluorides

Formaldehyde

HAPs - Total

Hexane

Hydrochloric acid

Hydrofluoric acid


Isophorone

Lead

Manganese compounds

Mercury

Methane


Methyl methacrylate


Methylhydrazine

Naphthalene

Nickel compounds

Nitrogen Oxides

Nitrous Oxide

Particulate Matter

Phenanthrene

Phenol

PM < 2.5 micron

PM < 10 micron


Propionaldehyde

Pyrene

Selenium compounds

Styrene

Sulfur Dioxide

Sulfuric Acid Mist


Toluene




Xylenes, Total

EQUI100 EU003 Unit 3 - tangential fired 1,1,1-Trichloroethane

0.0626101.50.01290.03510.4060.07283.72893.50.04232.2

0.0005750.6430.0715595.7595.70.02710.00463357.4103

3,574.10.4740.0440.2880.05920.03380.667080.0130.8290.1220.982

0.00010925.3859.60.113

105.62170.406250

0.001550.001210.1590.08120.4914e-064.23

0.008970.169

0.0001750.441.180.8970.09980.07110.03724,467.60.22

6,303,0006,254,6100.08630.2710.0660.124

0.005750.03556.83e-056e-06

4.97e-056e-06

0.0001412.2

0.6940.0305

0.0003630.4910.02540.965

0.0004420.000869

06e-06

0.0004748e-050.01180.06770.002030.0338

0.0626101.50.01290.03510.4060.0728103.4135,537.70.04232.2

0.0005750.6430.071527,413.17,188.80.02710.00463118,966.8

10312,184.40.4740.0440.2880.05920.03380.667080.140.8291790.982

0.000109253.842,0300.113

4,985.9450.4062,500

0.001550.001210.1590.08120.4914e-064.23

0.008970.169

0.0001750.441.180.8970.09980.07110.03724,467.60.22

6,303,0006,254,6100.08630.2710.0660.124

0.005750.03556.83e-056e-06

4.97e-056e-06

0.0001412.2

0.6940.0305

0.0003630.4910.02540.965

0.0004420.000869

06e-06

0.0004748e-050.01180.06770.002030.0338

0.014323.2

0.002940.008020.09270.01660.852,600

0.009660.502

0.0001310.1470.0163136136

0.006180.0010681.623.518160.1080.01

0.06570.01350.007730.151161.7

0.003210.1890.02790.224

2.49e-055.79513.6

0.025924.08660.092757.1

0.0003540.0002770.03630.01850.112

9.13e-070.966

0.002050.03864e-050.10.270.2050.02280.01620.00851,0200.0502

1,439,0401,427,9930.01970.06180.01510.02820.001310.008111.56e-051.37e-061.13e-051.37e-063.23e-050.5020.158

0.006958.3e-050.1120.00580.22

0.0001010.0001985.33e-051.37e-060.0001081.83e-050.00270.0155

0.0004640.00773

PTE by subject item






Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Equipment BoilerEQUI85 EU004 Unit 4 - tangential fired Xylenes, TotalEQUI100 EU003 Unit 3 - tangential fired 1,1,1-Trichloroethane


1,2-Dichloroethane


2-Methylnaphthalene

2,4-Dinitrotoluene



Acenaphthene

Acenaphthylene

Acetaldehyde

Acetophenone

Acrolein

Anthracene

Antimony compounds

Arsenic compounds

Benzene

Benzo(a)anthracene


Benzo(ghi)perylene


Benzo[a]pyrene

Beryllium Compounds

Biphenyl


Bromoform


Cadmium compounds

Carbon Dioxide


Carbon disulfide

Carbon Monoxide


Chloroethane

Chloroform

Chloromethane

Chloromethylbenzene

Chromium compounds

Chrysene

Cobalt compounds


Cyanide compounds



Dimethyl sulfate

Ethylbenzene

Fluoranthene

Fluorene

Fluorides

Formaldehyde

HAPs - Total

Hexane

Hydrochloric acid

Hydrofluoric acid


Isophorone

Lead

Manganese compounds

Mercury

Methane


Methyl methacrylate


Methylhydrazine

Naphthalene

0.040766.07

0.008370.02290.2640.04743.84581.40.02751.43

0.0003740.4180.0465678.4678.40.01760.00301271.367.021,162.90.3080.02860.1870.03850.0220.429460.70.0050.540.7750.06397.09e-0557.8138.8

0.0738110.72320.26434.9

0.001010.0007880.1040.05290.319

2.47e-062.75

0.005840.11

0.0001140.2860.7710.5840.0650.04630.02422,907.230.143

4,101,585.84,070,1000.05620.1760.04290.08040.003740.02314.43e-053.71e-063.22e-053.71e-069.18e-05

1.430.4520.0198

0.0002360.3190.01650.628

0.0002790.0005653.3e-053.71e-060.0003084.95e-050.007710.044

0.001320.022

0.040766.07

0.008370.02290.2640.0474253.9423,125.70.02751.43

0.0003740.4180.046517,838.74,6780.01760.0030177,415.967.027,928.80.3080.02860.1870.03850.0220.429460.70.09140.546.61

0.06397.09e-05165.181,3200.0738

1,606.47810.26499.7

0.001010.0007880.1040.05290.319

2.47e-062.75

0.005840.11

0.0001140.2860.7710.5840.0650.04630.02422,907.230.143

4,101,585.84,070,1000.05620.1760.04290.08040.003740.02314.43e-053.71e-063.22e-053.71e-069.18e-05

1.430.4520.0198

0.0002360.3190.01650.628

0.0002790.0005653.3e-053.71e-060.0003084.95e-050.007710.044

0.001320.022

0.009315.09

0.001910.005220.06030.01080.88132.8

0.006290.327

8.53e-050.09550.0106154.9154.9

0.004020.000687

61.915.3265.50.07040.006540.04270.00880.005030.0981105.2

0.002090.1230.1770.01461.62e-05

13.28.85

0.016825.10230.06037.97

0.000230.000180.02360.01210.07295.65e-070.629

0.001330.02512.6e-050.06540.1760.1330.01480.01060.00553663.750.0327

936,435.1929,2460.01280.04020.009810.0184

0.0008550.005281.01e-058.47e-077.35e-068.47e-072.1e-050.3270.103

0.004535.39e-050.07290.003770.143

6.37e-050.0001297.53e-068.47e-077.04e-051.13e-050.001760.0101

0.0003020.00503

PTE by subject item






Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Equipment Boiler EQUI100 EU003 Unit 3 - tangential firedMethylhydrazine

Naphthalene

Nickel compounds

Nitrogen Oxides

Nitrous Oxide

Particulate Matter

Phenanthrene

Phenol

PM < 2.5 micron

PM < 10 micron


Propionaldehyde

Pyrene

Selenium compounds

Styrene

Sulfur Dioxide

Sulfuric Acid Mist


Toluene




Xylenes, Total

Crusher EQUI1 EU011 Crusher House C-8 Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI102 EU012 Crusher House C-14 Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

Hopper EQUI4 EU014 #1&2 Fly Ash Separator Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

Loading-UnloadingEquipment

EQUI94 EU032 Fly Ash Silo B Loadout -Truck Bay

Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI97 EU018 Fly Ash Silo A Loadout -Truck Bay

Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI122 Null Fly Ash Silo A LoadoutSpout with VentilatedAnnular Hood

Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

Material HandlingEquipment

EQUI99 EU015 Hg Additive Handling andUnit 3 PAC Silo

Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI111 EU035 Rail Unloading Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI112 EU036 Lowering Well Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI114 EU037 Transfer House A C16/C18 Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI115 EU038 Transfer House B C9/C10 Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

0.040766.07

0.008370.02290.2640.04743.84581.40.02751.43

0.0003740.4180.0465678.4678.40.01760.00301271.367.021,162.90.3080.02860.1870.03850.0220.429460.70.0050.540.7750.06397.09e-0557.8138.8

0.0738110.72320.26434.9

0.001010.0007880.1040.05290.319

2.47e-062.75

0.005840.11

0.0001140.2860.7710.5840.0650.04630.02422,907.230.143

4,101,585.84,070,1000.05620.1760.04290.08040.003740.02314.43e-053.71e-063.22e-053.71e-069.18e-05

1.430.4520.0198

0.0002360.3190.01650.628

0.0002790.0005653.3e-053.71e-060.0003084.95e-050.007710.044

0.001320.022

0.040766.07

0.008370.02290.2640.0474253.9423,125.70.02751.43

0.0003740.4180.046517,838.74,6780.01760.0030177,415.967.027,928.80.3080.02860.1870.03850.0220.429460.70.09140.546.61

0.06397.09e-05165.181,3200.0738

1,606.47810.26499.7

0.001010.0007880.1040.05290.319

2.47e-062.75

0.005840.11

0.0001140.2860.7710.5840.0650.04630.02422,907.230.143

4,101,585.84,070,1000.05620.1760.04290.08040.003740.02314.43e-053.71e-063.22e-053.71e-069.18e-05

1.430.4520.0198

0.0002360.3190.01650.628

0.0002790.0005653.3e-053.71e-060.0003084.95e-050.007710.044

0.001320.022

0.009315.09

0.001910.005220.06030.01080.88132.8

0.006290.327

8.53e-050.09550.0106154.9154.9

0.004020.000687

61.915.3265.50.07040.006540.04270.00880.005030.0981105.2

0.002090.1230.1770.01461.62e-05

13.28.85

0.016825.10230.06037.97

0.000230.000180.02360.01210.07295.65e-070.629

0.001330.02512.6e-050.06540.1760.1330.01480.01060.00553663.750.0327

936,435.1929,2460.01280.04020.009810.0184

0.0008550.005281.01e-058.47e-077.35e-068.47e-072.1e-050.3270.103

0.004535.39e-050.07290.003770.143

6.37e-050.0001297.53e-068.47e-077.04e-051.13e-050.001760.0101

0.0003020.00503

1.381.380.66

3.81e-06

212170.1

0.000406

0.340.340.16

9.28e-07

1.381.380.66

3.81e-06

26.326.387.6

0.000508

0.420.420.2

1.16e-06

0.910.910.2

1.24e-06

13.113.120.3

0.000124

0.210.210.05

2.83e-07

2.22.22.2

1.79e-06

62.962.997.7

0.000598

0.50.50.5

4.09e-07

0.70.231.19

7.31e-06

2.690.415.69

3.48e-05

0.670.221.15

7.03e-06

3.51.165.97

3.65e-05

13.442.0428.43

0.000167

3.361.125.74

3.51e-05

0.946.570.94

93.993.993.9

0.211.50.21

0.020.0030.006

3.43e-08

0.280.0420.591

3.43e-06

0.0210.0030.006

3.65e-08

0.0390.0060.012

6.86e-08

0.5590.0851.183

6.86e-06

0.0270.0040.0084.7e-08

0.020.0030.006

3.43e-08

0.280.0420.591

3.43e-06

0.0060.0010.002

1.04e-08

0.020.0030.006

3.43e-08

0.280.0420.591

3.43e-06

0.0050.0010.001

8.35e-09

PTE by subject item






Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

EquipmentMaterial HandlingEquipment EQUI115 EU038 Transfer House B C9/C10

PM < 2.5 micron

PM < 10 micron

Reciprocating IC EngineEQUI23 EU033 Emergency Gen. Unit 3;1800 rpm constant speed398 hp; 250 ekW; CI; 2012

1,3-Butadiene

Acenaphthene

Acenaphthylene

Acetaldehyde

Acrolein

Anthracene

Benzene

Benzo(a)anthracene


Benzo(ghi)perylene


Benzo[a]pyrene

Carbon Dioxide


Carbon Monoxide

Chrysene


Fluoranthene

Fluorene

Formaldehyde

HAPs - Total


Lead

Methane

Naphthalene

Nitrogen Oxides

Nitrous Oxide

Particulate Matter

Phenanthrene

PM < 2.5 micron

PM < 10 micron

Pyrene

Sulfur Dioxide

Sulfuric Acid Mist

Toluene


Xylenes, Total

EQUI81 EU023 Emergency Gen. Unit 3APCE; 1800 rpm constantspeed 480 hp; 300 ekW; CI;2009

1,3-Butadiene

Acenaphthene

Acenaphthylene

Acetaldehyde

Acrolein

Anthracene

Benzene

Benzo(a)anthracene


Benzo(ghi)perylene


Benzo[a]pyrene

Carbon Dioxide


Carbon Monoxide

Chrysene


Fluoranthene

Fluorene

Formaldehyde

HAPs - Total


Lead

Methane

Naphthalene

Nitrogen Oxides

Nitrous Oxide

0.020.0030.006

3.43e-08

0.280.0420.591

3.43e-06

0.0050.0010.001

8.35e-09

0.0001990.65

0.0002852.42e-050.001063.33e-06

0.030.03

2.05e-050.03

0.0009220.65

5.91e-050.004616.27e-062.61e-070.002710.0008222.03e-055.3e-064.06e-072.46e-07

0.49115.8115.4

1.31e-071.08e-073.41e-076.91e-081.17e-060.000651.3e-066.45e-050.0005343.53e-069.89e-072.72e-05

0.0001990.65

0.0002852.42e-050.001063.33e-06

0.030.03

2.05e-050.03

0.0009220.65

5.91e-050.004616.27e-062.61e-070.002710.0008222.03e-055.3e-064.06e-072.46e-07

0.49115.8115.4

1.31e-071.08e-073.41e-076.91e-081.17e-060.000651.3e-066.45e-050.0005343.53e-069.89e-072.72e-05

0.0007942.62

0.001149.7e-050.004221.33e-05

0.130.13

8.19e-050.13

0.003692.62

0.0002360.01842.51e-051.05e-060.01080.003298.14e-052.12e-051.62e-069.84e-07

1.96463.1461.5

5.24e-074.32e-071.36e-062.76e-074.68e-060.00265.21e-060.0002580.002141.41e-053.96e-060.000109

0.0002280.79

0.0003272.78e-050.00123.82e-06

0.040.04

2.35e-050.04

0.001060.79

6.78e-050.005297.2e-063e-07

0.003110.0009442.34e-056.09e-064.66e-072.82e-07

0.59132.92132.481.5e-071.24e-073.91e-077.93e-081.34e-060.0007461.5e-067.4e-050.0006144.05e-061.14e-063.13e-05

0.0002280.79

0.0003272.78e-050.00123.82e-06

0.040.04

2.35e-050.04

0.001060.79

6.78e-050.005297.2e-063e-07

0.003110.0009442.34e-056.09e-064.66e-072.82e-07

0.59132.92132.481.5e-071.24e-073.91e-077.93e-081.34e-060.0007461.5e-067.4e-050.0006144.05e-061.14e-063.13e-05

0.0009123.16

0.001310.0001110.00481.53e-05

0.160.16

9.41e-050.16

0.004233.16

0.0002710.02122.88e-051.2e-060.01240.003789.34e-052.44e-051.87e-061.13e-06

2.37531.7529.916.02e-074.96e-071.56e-063.17e-075.38e-060.002995.98e-060.0002960.002451.62e-054.54e-060.000125

PTE by subject item






Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Equipment Reciprocating IC EngineEQUI81 EU023 Emergency Gen. Unit 3APCE; 1800 rpm constantspeed 480 hp; 300 ekW; CI;2009

Nitrogen Oxides

Nitrous Oxide

Particulate Matter

Phenanthrene

PM < 2.5 micron

PM < 10 micron

Pyrene

Sulfur Dioxide

Sulfuric Acid Mist

Toluene


Xylenes, Total

EQUI119 EU034 Emergency Gen. Unit 4;1800 rpm constant speed2206 hp; 1500 ekW; CI;2015

Acenaphthene

Acenaphthylene

Acetaldehyde

Acrolein

Anthracene

Benzene

Benzo(a)anthracene


Benzo(ghi)perylene


Benzo[a]pyrene

Carbon Dioxide


Carbon Monoxide

Chrysene


Fluoranthene

Fluorene

Formaldehyde

HAPs - Total


Lead

Methane

Naphthalene

Nitrogen Oxides

Nitrous Oxide

Particulate Matter

Phenanthrene

PM < 2.5 micron

PM < 10 micron

Pyrene

Sulfur Dioxide

Sulfuric Acid Mist

Toluene


Xylenes, Total

Silo/Bin EQUI3 EU013 Fly Ash - #1 & #2 Silo Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI5 EU019 Unit 3 Limestone Silo Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI6 EU020 Unit 3 Limestone Day Bin 1Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI7 EU021 Unit 3 Limestone Day Bin 2Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI86 EU024 Unit 4 Lime Silo Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI87 EU025 Unit 4 Lime Day Bin A Particulate Matter

PM < 2.5 micron

0.0002280.79

0.0003272.78e-050.00123.82e-06

0.040.04

2.35e-050.04

0.001060.79

6.78e-050.005297.2e-063e-07

0.003110.0009442.34e-056.09e-064.66e-072.82e-07

0.59132.92132.481.5e-071.24e-073.91e-077.93e-081.34e-060.0007461.5e-067.4e-050.0006144.05e-061.14e-063.13e-05

0.0002280.79

0.0003272.78e-050.00123.82e-06

0.040.04

2.35e-050.04

0.001060.79

6.78e-050.005297.2e-063e-07

0.003110.0009442.34e-056.09e-064.66e-072.82e-07

0.59132.92132.481.5e-071.24e-073.91e-077.93e-081.34e-060.0007461.5e-067.4e-050.0006144.05e-061.14e-063.13e-05

0.0009123.16

0.001310.0001110.00481.53e-05

0.160.16

9.41e-050.16

0.004233.16

0.0002710.02122.88e-051.2e-060.01240.003789.34e-052.44e-051.87e-061.13e-06

2.37531.7529.916.02e-074.96e-071.56e-063.17e-075.38e-060.002995.98e-060.0002960.002451.62e-054.54e-060.000125

0.0007070.13

0.001030.0001270.005551.36e-05

0.030.03

0.0001490.04

0.004846.18

0.0004760.02423.29e-051.52e-060.005790.0002894.69e-051.48e-051.27e-065.6e-060.53608.3606.2

9.41e-077.98e-072.04e-064.06e-062.28e-060.002844.5e-062.88e-059.23e-053.38e-051.71e-05

0.0007070.13

0.001030.0001270.005551.36e-05

0.030.03

0.0001490.04

0.004846.18

0.0004760.02423.29e-051.52e-060.005790.0002894.69e-051.48e-051.27e-065.6e-060.53608.3606.2

9.41e-077.98e-072.04e-064.06e-062.28e-060.002844.5e-062.88e-059.23e-053.38e-051.71e-05

0.002830.53

0.004110.0005090.02225.43e-05

0.120.12

0.0005970.15

0.019424.710.00190.0969

0.0001326.06e-060.02320.001160.0001875.9e-055.07e-062.24e-05

2.142,433.22,425

3.76e-063.19e-068.14e-061.63e-059.11e-060.01141.8e-050.0001150.0003690.0001356.85e-05

0.910.910.2

1.24e-06

13.113.120.3

0.000124

0.210.210.05

2.83e-07

0.382.630.38

37.537.537.5

0.090.60.09

0.624.340.62

61.961.961.9

0.140.990.14

0.624.340.62

61.961.961.9

0.140.990.14

0.380.380.38

55

7.76

0.090.090.09

0.280.280.28

11

1.55

0.060.060.06

PTE by subject item






Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Equipment Silo/Bin EQUI87 EU025 Unit 4 Lime Day Bin AParticulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI88 EU026 Unit 4 Lime Day Bin B Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI89 EU027 Unit 4 Lime Day Bin C Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI90 EU028 Unit 4 Lime Day Bin D Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI91 EU029 Unit 4 Lime Day Bin E Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI93 EU031 Fly Ash Silo B Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI98 EU017 Fly Ash Silo A Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI113 EU047 Coal Silos Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI116 EU039 Dust Tank Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI117 EU040 Units 1, 2, 3 Bunkers &Trippers

Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI118 EU041 Unit 4 Bunkers & Trippers Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

EQUI120 EU030 Unit 4 Activated CarbonSilo

Particulate Matter

PM < 2.5 micron

PM < 10 micron

Fugitive Cooling Tower FUGI1 EU006 Unit 3 Cooling Tower Particulate Matter

PM < 2.5 micron

PM < 10 micron

FUGI2 EU005 Unit 4 Cooling Tower Particulate Matter

PM < 2.5 micron

PM < 10 micron

Material Handling/Transfer/Storage

FUGI4 FS008 Fly Ash Handling -Unloading to Disposal Cell& Uncaptured EmissionsFrom Silo A Loadout Truc..

Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

FUGI11 FS006 Coal Stockpile MaterialHandling (Existing CoalDrop Onto Pile Segmentand Ten New Portable Co..

Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

Open Air Source FUGI5 FS003 Fly Ash Pond - WindErosion

Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

FUGI8 FS009 Fly Ash Disposal Cell -Wind Erosion

Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron


Lead

Particulate Matter

0.280.280.28

11

1.55

0.060.060.06

0.280.280.28

11

1.55

0.060.060.06

0.280.280.28

11

1.55

0.060.060.06

0.280.280.28

11

1.55

0.060.060.06

0.280.280.28

11

1.55

0.060.060.06

1.451.451.45

1.49e-06

62.962.997.7

0.000598

0.330.330.33

3.41e-07

5.8816.866.5

3.98e-05

47.636.281.4

0.000498

3.914.75.86

3.59e-05

0.020.0030.006

3.43e-08

0.280.0420.591

3.43e-06

0.0050.0010.001

8.35e-09

0.50.50.11

6.85e-07

7.217.2111.19

6.85e-05

0.120.120.03

1.56e-07

0.010.0010.003

1.66e-08

0.1360.0210.287

1.66e-06

0.0130.0020.0042.3e-08

0.010.0020.003

1.77e-08

0.1440.0220.304

1.77e-06

0.0110.0020.003

1.88e-08

0.190.190.19

0.090.090.14

0.040.040.04

54.70.1881.3

54.70.1881.3

12.50.0418.6

850.27126.3

850.27126.3

19.40.0628.8

0.740.111.56

9.56e-06

0.740.111.56

9.56e-06

0.930.491.5

9.19e-06

6.751.0214.27

8.28e-05

6.751.0214.27

8.28e-05

1.540.233.26

1.89e-05

8.061.2116.13

9.87e-05

8.061.2116.13

9.87e-05

1.840.283.68

2.25e-05

17.272.5934.54

0.000211

17.272.5934.54

0.000211

3.940.597.89

4.83e-05

8.091.2116.18

9.38e-05

8.091.2116.18

9.38e-05

1.850.283.69

2.14e-05

PTE by subject item






Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Fugitive Open Air Source FUGI9 FS001 Coal Stockpile - WindErosion

Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

Paved Road FUGI10 FS007 Paved Road Dust Particulate Matter

PM < 2.5 micron

PM < 10 micron

Piles FUGI6 FS005 Coal Stockpile & Fly AshPond Maintenance(Bulldozer)

Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

Unpaved Roads FUGI3 FS004 Unpaved Road Dust Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

Structure Stack/Vent STRU13 SV003 Units 1, 2, & 3 Common S..Sulfur Dioxide

8.091.2116.18

9.38e-05

8.091.2116.18

9.38e-05

1.850.283.69

2.14e-05

5.291.3

26.43

21.145.19105.7

3.690.9

18.43

114.3729.76319.7

0.00194

114.3729.76319.7

0.00194

26.116.7973

0.000443

10.371.3226.08

9.05e-05

82.438.24

245.850.000814

11.011.8418.74

7.48e-05

04,450

PTE by subject item



Subject ItemCategoryDescription


Subject ItemDesignation Subject Item Description Relationship

Related SubjectItem ID % Flow

Related Subject ItemType Description

Start Date (RelatedSubject Item)

End Date (RelatedSubject Item)


is controlledby

TREA16 Null016-Fabric Filter - HighTemp, T>250 Degrees F

1/1/1979 Null

is controlledin parallel by

TREA12 Null 099-Other 8/19/2010 Null


is monitoredby

EQUI29 NullContinuous OpacityMonitor

10/1/2002 Null

EQUI36 NullContinuous EmissionMonitor

7/6/2009 Null


7/6/2009 Null


7/6/2009 Null


7/6/2009 Null

sends to EQUI105 Null Data Acquisition System 6/14/2010 Null

STRU12 Null Stack/Vent 3/24/1997 Null



is controlledby


1/1/1979 Null




is monitoredby


10/1/2002 Null


8/14/2009 Null


7/6/2009 Null


7/6/2009 Null


7/6/2009 Null




EQUI85 EU004 Unit 4 - tangential fired is controlledby


TREA22 Null 207-Carbon Injection 11/30/2015 Null




is monitoredby


2/4/2008 Null


7/7/2008 Null


7/30/2010 Null

EQUI53 Null Continuous EmissionMonitor

7/6/2009 Null

SI - SI relationships










Equipment Boiler EQUI85 EU004 Unit 4 - tangential fired is monitoredby

EQUI52 NullContinuous EmissionMonitor 7/30/2010 Null


7/6/2009 Null


7/6/2009 Null


7/6/2009 Null


5/5/2016 Null


6/15/2007 Null


STRU14 100 Stack/Vent 3/24/1997 Null

EQUI100 EU003 Unit 3 - tangential fired is controlledby

TREA5 Null139-SCR (SelectiveCatalytic Reduction)

10/30/2009 Null



10/30/2009 Null



is monitoredby


11/13/2009 Null


10/30/2009 Null


10/30/2009 Null


10/30/2009 Null


8/14/2009 Null


2/8/2009 Null


6/16/2007 Null



Crusher EQUI1 EU011 Crusher House C-8is controlledby

TREA37 Null018-Fabric Filter - LowTemp, T<180 Degrees F

3/24/1997 Null

sends to STRU18 100 Stack/Vent 3/24/1997 Null

EQUI102 EU012 Crusher House C-14is controlledby


3/24/1997 Null


Data AcquisitionSystem

EQUI105 DA005 Units 1, 2, 3, 4 DAS receivesfrom


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null











Equipment Data AcquisitionSystem

EQUI105 DA005 Units 1, 2, 3, 4 DAS receivesfrom

EQUI34 NullContinuous OpacityMonitor 6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null


6/14/2010 Null

Hopper EQUI4 EU014 #1&2 Fly Ash Separatoris controlledby


3/24/1997 Null



EQUI94 EU032 Fly Ash Silo B Loadout -Truck Bay

is controlledby


10/25/2015 Null


EQUI97 EU018 Fly Ash Silo A Loadout -Truck Bay

is controlledby

TREA2 100018-Fabric Filter - LowTemp, T<180 Degrees F

10/30/2009 Null



is controlledby

TREA36 100 018-Fabric Filter - LowTemp, T<180 Degrees F

10/30/2009 Null











Equipment Loading-UnloadingEquipment

EQUI97 EU018Fly Ash Silo A Loadout -Truck Bay sends to STRU22 100 Stack/Vent 10/30/2009 Null


is controlledby


10/30/2009 Null


Material HandlingEquipment

EQUI99 EU015 Hg Additive Handling andUnit 3 PAC Silo

is controlledby


10/30/2009 Null


EQUI111 EU035 Rail Unloadingis controlledby


5/4/2007 Null



EQUI112 EU036 Lowering Wellis controlledby


4/7/2010 Null



EQUI114 EU037 Transfer House A C16/C18is controlledby


3/25/2011 Null

sends to STRU44 Null Stack/Vent 3/25/2011 Null

EQUI115 EU038 Transfer House B C9/C10is controlledby


10/4/2013 Null


Reciprocating ICEngine







Silo/Bin EQUI3 EU013 Fly Ash - #1 & #2 Silois controlledby


3/24/1997 Null


EQUI5 EU019 Unit 3 Limestone Silois controlledby


10/30/2009 Null


EQUI6 EU020 Unit 3 Limestone Day Bin 1is controlledby


10/30/2009 Null


EQUI7 EU021 Unit 3 Limestone Day Bin 2is controlledby


10/30/2009 Null


EQUI86 EU024 Unit 4 Lime Silois controlledby


10/25/2015 Null


EQUI87 EU025 Unit 4 Lime Day Bin Ais controlledby


10/25/2015 Null


EQUI88 EU026 Unit 4 Lime Day Bin Bis controlledby

TREA25 Null 018-Fabric Filter - LowTemp, T<180 Degrees F

10/25/2015 Null











Equipment Silo/BinEQUI87 EU025 Unit 4 Lime Day Bin A sends to STRU2 100 Stack/Vent 10/25/2015 Null

EQUI88 EU026 Unit 4 Lime Day Bin Bis controlledby


10/25/2015 Null


EQUI89 EU027 Unit 4 Lime Day Bin Cis controlledby


10/25/2015 Null


EQUI90 EU028 Unit 4 Lime Day Bin Dis controlledby


10/25/2015 Null


EQUI91 EU029 Unit 4 Lime Day Bin Eis controlledby


10/25/2015 Null


EQUI93 EU031 Fly Ash Silo Bis controlledby


10/25/2015 Null


EQUI98 EU017 Fly Ash Silo Ais controlledby


10/30/2009 Null


EQUI113 EU047 Coal Silosis controlledby


4/7/2010 Null



EQUI116 EU039 Dust Tankis controlledby


12/31/2011 Null


EQUI117 EU040 Units 1, 2, 3 Bunkers &Trippers

is controlledby


7/1/2008 Null


EQUI118 EU041 Unit 4 Bunkers & Trippersis controlledby


4/7/2010 Null


EQUI120 EU030 Unit 4 Activated CarbonSilo

is controlledby


10/25/2015 Null


Fugitive Cooling Tower FUGI1 EU006 Unit 3 Cooling Tower sends to STRU16 100 Stack/Vent 10/24/1997 Null

FUGI2 EU005 Unit 4 Cooling Tower sends to STRU15 100 Stack/Vent 3/24/1997 Null

Paved Road FUGI10 FS007 Paved Road Dustis controlledby


Unpaved Roads FUGI3 FS004 Unpaved Road Dust is controlledin parallel by

TREA34 Null062-Dust Suppress byChem Stabilizer/Wetting..

6/13/2013 Null

TREA35 Null901-2 - 3 % MoistureContent

6/13/2013 Null

Structure Stack/Vent STRU13 SV003 Units 1, 2, & 3 CommonStack

is monitoredby


11/11/2014 Null


11/8/2014 Null











Structure Stack/Vent STRU13 SV003 Units 1, 2, & 3 CommonStack

is monitoredby

EQUI106 NullContinuous EmissionMonitor 11/11/2014 Null


11/8/2014 Null


Treatment 099-Other TREA6 CE027 Unit 4 LNB/SOFA is controlledin series by



TREA7 CE028 Unit 4 ROTA-Mix SNCR is controlledin series by



TREA8 CE019 Unit 3 Low NOxBurners/Over-Fire Air

is controlledin series by

TREA5 Null139-SCR (SelectiveCatalytic Reduction)

10/30/2009 Null


10/30/2009 Null



TREA11 CE024 Unit 2 ROTA-Mix SNCRis controlledin series by


2/9/2009 Null

TREA12 CE025 Unit 1 ROFAis controlledin series by


6/13/2009 Null

TREA13 CE026 Unit 2 ROFAis controlledin series by


12/2/2008 Null

TREA15 CE023 Unit 1 ROTA-Mix SNCRis controlledin series by


7/10/2009 Null




Subject ItemTypeDescription Subject Item ID

Subject ItemDesignation

Subject ItemDescription Capacity (gal)Substance Stored

ColumnDiameter (ft)

Number ofColumns Deck Type

InteriorDiameter (ft)

InteriorHeight (ft)

MaximumTrue VaporPressure(psia)

ConstructionType Seal Type

SupportType

AbovegroundStorage Tank

EQUI8 TK012 Ethylene Glycol 150 Ethylene glycol Null Null Null 0 0 Null Fixed Roof Null Null




EQUI14 TK006 Fuel Oil 20360 Fuel Oil #2 Null Null Null 11 33 Null Fixed Roof Null Null



EQUI123 NullAqua Ammonia1092

48000 Ammonia (aqueous) Null Null Null 15 36 Null Fixed Roof Null Null







EQUI127 Null Gasoline 1064 1000Gasoline Blends(E1-E49)

Null Null Null 4 8 Null Fixed Roof Null Null

EQUI128 NullDust Suppressant1107

12400 Other Null Null Null 10 21 Null Fixed Roof Null Null

EQUI129 NullDust Suppressant002

12400 Other Null Null Null 10 21 Null Fixed Roof Null Null

EQUI130 Null Waste Glycol 1106 800 Ethylene glycol Null Null Null 4 8 Null Fixed Roof Null Null

Aboveground Storage Tanks, General


Details for:SI Category: EquipmentSI Type: Aboveground Storage Tank



Subject ItemDescription Manufacturer Model

Max DesignCapacity

Max DesignCapacityUnits(numerator)

Max DesignCapacity Units(denominator) Material

ConstructionStart Date

OperationStart Date

ModificationDate

Crusher EQUI1 EU011 Crusher House C-8 NA NA 800 tons hours Coal 12/1/1972 5/1/1973 Null

EQUI102 EU012 Crusher House C-14 NA NA 1000 tons hours Coal 12/1/1972 5/1/1973 Null

Hopper EQUI4 EU014 #1&2 Fly Ash SeparatorUCC NA 84 tons hours Ash 12/1/1977 5/1/1980 Null


EQUI94 EU032Fly Ash Silo B Loadout -Truck Bay

NA NA 23400 cubic feet minutes Airflow 4/1/2013 1/1/2015 Null

EQUI97 EU018Fly Ash Silo A Loadout -Truck Bay

NA NA 17.7 tons hours Ash 6/1/2007 10/1/2009 Null

EQUI122 NullFly Ash Silo A LoadoutSpout with VentilatedAnnular Hood

Bay Shore SteelWorks

EL250-14 7 tons hours Ash 1/1/2009 10/30/2009 Null

MaterialHandlingEquipment

EQUI99 EU015Hg Additive Handlingand Unit 3 PAC Silo

AES 3GSI-SLO-700 17.7 tons hours Carbon 6/1/2007 10/1/2009 Null

EQUI111 EU035 Rail Unloading NA NA 3500 tons hours Coal 1/1/1956 1/1/1960 Null

EQUI112 EU036 Lowering Well NA NA 3500 tons hours Coal 1/1/1956 1/1/1960 Null

EQUI114 EU037Transfer House AC16/C18

NA NA 1000 tons hours Coal 1/1/1956 1/1/1960 Null

EQUI115 EU038Transfer House BC9/C10


Silo/Bin EQUI3 EU013 Fly Ash - #1 & #2 Silo UCC NA 84 tons hours Ash 12/1/1977 5/1/1980 Null

EQUI5 EU019 Unit 3 Limestone Silo MAC NA 2000 cubic feet minutes Limestone 1/1/2009 10/1/2009 Null

EQUI6 EU020Unit 3 Limestone DayBin 1

MAC NA 3300 cubic feet minutes Limestone 1/1/2009 10/1/2009 Null

EQUI7 EU021Unit 3 Limestone DayBin 2

MAC NA 3300 cubic feet minutes Limestone 10/1/2009 10/1/2009 Null

EQUI86 EU024 Unit 4 Lime Silo Pittsburgh 12-1791 2000 cubic feet minutes Airflow 4/1/2013 1/1/2015 Null

EQUI87 EU025 Unit 4 Lime Day Bin A Pittsburgh 12-1791 1500 cubic feet minutes Airflow 4/1/2013 1/1/2015 Null

EQUI88 EU026 Unit 4 Lime Day Bin B Pittsburgh 12-1791 1500 cubic feet minutes Airflow 4/1/2013 1/1/2015 Null

EQUI89 EU027 Unit 4 Lime Day Bin C Pittsburgh 12-1791 1500 cubic feet minutes Airflow 4/1/2013 1/1/2015 Null

EQUI90 EU028 Unit 4 Lime Day Bin D Pittsburgh 12-1791 1500 cubic feet minutes Airflow 4/1/2013 1/1/2015 Null

EQUI91 EU029 Unit 4 Lime Day Bin E Pittsburgh 12-1791 1500 cubic feet minutes Airflow 4/1/2013 1/1/2015 Null

EQUI93 EU031 Fly Ash Silo B NA NA 15500 cubic feet minutes Airflow 4/1/2013 1/1/2015 Null

EQUI98 EU017 Fly Ash Silo A NA NA 2700 cubic feet minutes Ash 6/1/2007 10/1/2009 Null

EQUI113 EU047 Coal Silos NA NA 3500 tons hours Coal 1/1/1956 1/1/1960 Null

EQUI116 EU039 Dust Tank NA NA 3.5 tons hours Coal 1/1/1956 1/1/1960 Null

EQUI117 EU040Units 1, 2, 3 Bunkers &Trippers


EQUI118 EU041 Unit 4 Bunkers &Trippers


Emission Units 1


Details for:SI Category: NoneSI Type: Crusher, Hopper, Loading-Unloading Equipment and 2 more




Max DesignCapacity

Max DesignCapacityUnits(numerator)



OperationStart Date

ModificationDate

Silo/BinEQUI117 EU040

Units1,2,3Bunkers&Trippers NA NA 2200 tons hours Coal 1/1/1956 1/1/1960 Null

EQUI118 EU041Unit 4 Bunkers &Trippers


EQUI120 EU030Unit 4 Activated CarbonSilo

Alstom NA 1000 cubic feet minutes Carbon 4/1/2013 1/1/2015 Null

Emission Units 1


Details for:SI Category: NoneSI Type: Crusher, Hopper, Loading-Unloading Equipment and 2 more


Subject ItemDesignation Subject Item Description Manufacturer Model

Max DesignCapacity

Max DesignCapacity Units(numerator)



OperationStart Date

ModificationDate

Boiler EQUI82 EU001Unit 1 - wall fired drybottom

Riley-Stoker 3211 1075million Britishthermal units

hours Heat 11/1/1954 4/1/1958 Null


Riley-Stoker 3293 910million Britishthermal units

hours Heat 1/1/1956 12/1/1960 Null

EQUI85 EU004 Unit 4 - tangential fired Combustion Engineering CCRR 11875 6800million Britishthermal units

hours Heat 1/1/1978 5/1/1980 Null

EQUI100 EU003 Unit 3 - tangential fired Combustion Engineering CCRR 21037 4425million Britishthermal units

hours Heat 1/1/1970 5/1/1973 Null

Reciprocating IC EngineEQUI23 EU033Emergency Gen. Unit 3;1800 rpm constant speed ..

Caterpillar 250 KW 250 kilowatt hour each Electrical Energy 9/16/2012 10/17/2012 Null


Caterpillar Standby 300 300 kilowatt hour each Electrical Energy 1/31/2009 10/1/2009 Null


Caterpillar 3512C 1500 kilowatt hour each Electrical Energy 8/1/2015 10/7/2015 Null

Emission Units 2


Details for:SI Category: EquipmentSI Type: Boiler & Reciprocating IC Engine


Subject ItemDesignation Subject Item Description Firing Method Engine Use

EngineDisplacement

EngineDisplacementUnits

Subject toCSAPR?

ElectricGeneratingCapacity(MW)

Boiler EQUI82 EU001Unit 1 - wall fired drybottom

Pulverized coal, drybottom

Null Null Null Y 100


Pulverized coal, drybottom


EQUI85 EU004 Unit 4 - tangential firedPulvrzd coal, drybot/tangential firing


EQUI100 EU003 Unit 3 - tangential firedPulvrzd coal, drybot/tangential firing


Reciprocating IC EngineEQUI23 EU033Emergency Gen. Unit 3;1800 rpm constant speed ..

CI Emergency/blackstart 1.46 liters per cylinderNull Null





Emission Units 2 (continued)


Details for:SI Category: EquipmentSI Type: Boiler & Reciprocating IC Engine

Subject ItemTypeDescription Subject Item IDSI Designation and Description Manufacturer Model

SerialNumber

ParameterMonitored(CEMs/COMs)

Primary orBackup?(monitors)

BypassCapability?(CEMs/COMs)

Install Date(CEMs/COMs)

CertificationDate

CertificationBasis Span

System FullScale Value

Optical PathLength

ContinuousEmissionMonitor

EQUI35MR041Boiler 4 Air Flow Monitor

Teledyne MonitorLabs

Ultraflow150

1500870 Air Flow Rate Primary No 7/7/2008 Null Null 2060 2060 Null

EQUI36MR028Boiler 1 SO2 CEMS


TML 50 SO2070 Sulfur Dioxide Primary No 7/6/2009 Null Null 1000 1350 Null

EQUI37MR029Boiler 1 NOx CEMS


TML 41 NO2616 Nitrogen Oxides Primary No 7/6/2009 Null Null 350 1050 Null

EQUI38MR030Boiler 1 CO2 CEMS


TML20 CO2306 Carbon Dioxide Primary No 7/6/2009 Null Null 20 20 Null



Ultraflow150

1500981 Air Flow Rate Primary No 7/6/2009 Null Null 250 250 Null





Teledyne Monitor Labs




TML 20 CO2358 Carbon Dioxide Primary No 7/6/2009 Null Null 20 20 Null



TBDUltraflow150

Air Flow Rate Primary No 7/6/2009 Null Null 250 250 Null









TML 20-M CO2143 Carbon Dioxide Primary No 10/30/2009 Null Null 20 20 Null



UF 150 1501035 Air Flow Rate Primary No 10/30/2009 Null Null 1300 1300 Null

EQUI52MR045Boiler 4 CO CEMS


TML-30-U CO123 Carbon Monoxide Primary No 7/30/2010 Null Null 900 900 Null









TML 20 CO2326 Carbon Dioxide Primary No 7/6/2009 Null Null 20 20 Null

EQUI71MR024Boiler 3 CO CEMS


TML30 CO193 Carbon Monoxide Primary Null 10/30/2009 Null Null 900 900 Null

EQUI106MR046Sorbent Trap Hg Sampler

M&CSorbent TrapSampler

0519 Mercury Primary No 11/11/2014 9/3/2015 40 CFR Pt 63 Null Null Null

EQUI107MR047STRU13 PM CEMS

PCME 181WS 47110ParticulateMatter

Primary No 11/8/2014 12/5/2014 40 CFR Pt 63 Null Null Null

EQUI108MR048Boiler 4 PM CEMS


Laser Hawk360

3600 213ParticulateMatter

Primary Yes 11/8/2015 5/5/2016 40 CFR Pt 63 Null Null Null

EQUI109MR025Boiler 3 Hg CEMS

Thermo Scientific 80i 618117764 Mercury Primary No 6/16/2007 Null 40 CFR Pt 63 5 5 Null

EQUI110MR026Boiler 4 Hg CEMS

Thermo Scientific 80i 0618117745Mercury Primary No 6/15/2007 6/15/2007 40 CFR Pt 63 5 5 Null

ContinuousOpacityMonitor

EQUI28MR027Boiler 3 COMS


Lighthawk560

5601973 Opacity Primary No 10/30/2009 Null Null 100 100 0.93



Lighthawk560

5600273 Opacity Primary Null 10/1/2002 Null Null 100 100 2.05



Lighthawk560

5600274 Opacity Primary Null 10/1/2002 Null Null 100 100 2.05



Lighthawk560

5601608 Opacity Primary No 2/4/2008 Null Null 100 100 0.84

CEMs/COM, General


Details for:SI Category: EquipmentSI Type: Continuous Emission Monitor & Continuous Opacity Monitor

Labs

Subject Item IDSubject ItemDesignation

Subject ItemDescription Manufacturer Model Serial Number

Primary orBackup? (DASs) Install Date (DASs)

EQUI105 DA005Units 1, 2, 3,4 DAS

EnvironmentalSystems Corp

Stack Vision NA Primary 6/14/2010

Data Acquisition System, General


Details for:SI Category: EquipmentSI Type: Data Acquisition System



Subject ItemDescription Install Year Pollutants Emitted

Cooling Tower FUGI1 EU006 Unit 3 Cooling Tower Null Particulate Matter

PM < 2.5 micron

PM < 10 micron

FUGI2 EU005 Unit 4 Cooling Tower Null Particulate Matter

PM < 2.5 micron

PM < 10 micron

Material Handling/Transfer/Storage

FUGI4 FS008 Fly Ash Handling -Unloading to DisposalCell & UncapturedEmissions From Silo ALoadout Truck Bay(EQUI97/EU018) andSilo A Loadout AnnularSpout (EQUI122)

Null Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

FUGI11 FS006 Coal Stockpile MaterialHandling (Existing CoalDrop Onto Pile Segmentand Ten New PortableConveyors/Eleven DropPoints Segment)

Null Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

Open Air Source FUGI5 FS003 Fly Ash Pond - WindErosion

Null Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

FUGI7 FS002 BottomAshPond-WindErosion

NullLead

Fugitive Sources


Details for:SI Category: FugitiveSI Type: Cooling Tower, Material Handling/Transfer/Storage, Open Air Source and 3more




Open Air SourceFUGI5 FS003

FlyAshPond-WindErosion Null PM < 10 micron

FUGI7 FS002 Bottom Ash Pond -Wind Erosion

Null Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

FUGI8 FS009 Fly Ash Disposal Cell -Wind Erosion

Null Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron


Null Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

Paved Road FUGI10 FS007 Paved Road Dust Null Particulate Matter

PM < 2.5 micron

PM < 10 micron

Piles FUGI6 FS005 Coal Stockpile & Fly AshPond Maintenance(Bulldozer)

Null Lead

Particulate Matter

PM < 2.5 micron

PM < 10 micron

Fugitive Sources






Piles FUGI6 FS005Coal Stockpile & Fly AshPond Maintenance(Bulldozer)

NullPM < 2.5 micron

PM < 10 micron

Unpaved Roads FUGI3 FS004 Unpaved Road Dust Null Particulate Matter

PM < 2.5 micron

PM < 10 micron

Fugitive Sources





Subject ItemDescription Height

Units(height) Length

Units(length) Width

Units(width)

Building STRU30 BG001 Unit 4 277 feet 294 feet 324.8 feet

STRU31 BG002 Unit 3 236 feet 234 feet 250.7 feet

STRU32 BG003 Scrubber Area, Unit 3 206 feet 148 feet 90 feet

STRU33 BG004 Units 1 & 2 104 feet 300 feet 182.8 feet

STRU34 BG005 Unit 1 Baghouse 107.5 feet 61 feet 72 feet

STRU35 BG006 Unit 2 Baghouse 107.5 feet 61 feet 72 feet

STRU36 BG007 #4 Absorber Building 145.9 feet 183.3 feet 236 feet

STRU37 BG008Existing Coal HandlingEquipment Building

100.8 feet 70 feet 126 feet

STRU38 BG009 Unit 3 Cooling Tower 65.3 feet 289 feet 75 feet

STRU39 BG010 Unit 4 Cooling Tower 53.3 feet 560.7 feet 69 feet

Buildings, General


Details for:SI Category: StructureSI Type: Building


Subject ItemDesignation Subject Item Description

Stack Height(feet)

StackDiameter(feet)

Stack Length(feet)

Stack Width(feet)

Stack Flow Rate(cubic ft/min)

DischargeTemperature(°F)

Flow Rate/TempInformationSource Discharge Direction

Stack/Vent STRU1 SV024 Unit 4 Lime Silo Stack 105 1.4 Null Null 2000 68 ManufacturerUpwards with no cap onstack/vent

STRU2 SV025 Unit 4 Lime Day Bin A Stack100 1.4 Null Null 1500 68 ManufacturerUpwards with no cap onstack/vent

STRU3 SV026 Unit 4 Lime Day Bin B Stack100 1.4 Null Null 1500 68 ManufacturerUpwards with no cap onstack/vent

STRU4 SV027 Unit 4 Lime Day Bin C Stack100 1.4 Null Null 1500 68 ManufacturerUpwards with no cap onstack/vent

STRU5 SV028 Unit 4 Lime Day Bin D Stack100 1.4 Null Null 1500 68 ManufacturerUpwards with no cap onstack/vent

STRU6 SV029 Unit 4 Lime Day Bin E Stack100 1.4 Null Null 1500 68 ManufacturerUpwards with no cap onstack/vent

STRU7 SV030Unit 4 Activated CarbonSilo Stack

68 1.4 Null Null 1000 68 Manufacturer Horizontally

STRU8 SV031 Fly Ash Silo B Bin Stack 138 0.7 Null Null 15500 68 ManufacturerUpwards with no cap onstack/vent

STRU9 SV032Fly Ash Silo B LoadoutTruck Bay Stack

40 1 Null Null 23400 68 ManufacturerUpwards with no cap onstack/vent

STRU12 SV001 Units 1 & 2 Alternate Stack250 9.5 Null Null 590000 300 ManufacturerUpwards with no cap onstack/vent

STRU13 SV003Units 1, 2, & 3 CommonStack

700 29 Null Null 2027000 175 Test dataUpwards with no cap onstack/vent

STRU14 SV004 Unit 4 Stack 616 32 Null Null 2217000 158 Test dataUpwards with no cap onstack/vent

STRU15 SV005 Unit 4 cooling tower 53.3 Null 561 70 18452 87 ManufacturerUpwards with no cap onstack/vent

STRU16 SV006 Unit 3 cooling tower 65.3 Null 289 75 12304 87 ManufacturerUpwards with no cap onstack/vent

STRU18 SV011 Crusher House 10 1.4 Null Null 11700 70 ManufacturerUpwards with no cap onstack/vent

STRU19 SV012 Crusher House 23 Null 4 1.75 16030 70 Manufacturer Horizontally

STRU20 SV013Units 1&2 Fly Ash SiloStack


STRU21 SV014Units 1&2 Fly AshSeparator Stack

42 0.67 Null Null 200 70 ManufacturerUpwards with no cap onstack/vent

STRU22 SV018Fly Ash Silo A LoadoutTruck Bay Stack

17.67 3.17 Null Null 23000 68 ManufacturerUpwards with no cap onstack/vent

STRU23 SV017Fly Ash Silo A & LoadoutSpout Vented Annular Ho..


STRU25 SV015 Unit 3 PAC Silo Stack 59 0.5 Null Null 2500 70 ManufacturerUpwards with no cap onstack/vent

STRU26 SV019 Limestone Silo Stack 81 1.9 Null Null 2000 70 ManufacturerUpwards with no cap onstack/vent





STRU29 SV022Emergency Generator -Unit 3 APCE


STRU40 SV035 Rail Unloading 21.7 4.7 Null Null 77500 70 ManufacturerUpwards with no cap onstack/vent

STRU41 SV042 Rail Unloading 21.7 4.7 Null Null 77500 70 ManufacturerUpwards with no cap onstack/vent

STRU42 SV036 Lowering Well & Coal Silos 21.7 4.7 Null Null 65425 70 ManufacturerUpwards with no cap onstack/vent

STRU43 SV043 Lowering Well & Coal Silos 21.7 4.7 Null Null 65425 70 ManufacturerUpwards with no cap onstack/vent

STRU44 SV037 Transfer House C16/C18 151.3 3.4 Null Null 26400 70 ManufacturerUpwards with no cap onstack/vent

STRU45 SV038 Transfer House C9/C10 53.6 2.3 Null Null 11000 70 ManufacturerUpwards with no cap onstack/vent

STRU46 SV039 Dust Tank 59.8 0.83 Null Null 3000 70 Manufacturer Horizontally

STRU47 SV040Units 1, 2, 3 Bunkers &Trippers


STRU48 SV041 Unit 4 Bunkers & Trippers 164 3.66 Null Null 38800 70 ManufacturerUpwards with no cap onstack/vent

STRU49 SV034 Unit 4 EmergencyGenerator

18.6 1.33 Null Null 10909 759 Manufacturer Upwards with no cap onstack/vent

Stack/Vent, General


Details for:SI Category: StructureSI Type: Stack/Vent


Subject ItemDesignation Subject Item Description

Stack Height(feet)

StackDiameter(feet)

Stack Length(feet)

Stack Width(feet)

Stack Flow Rate(cubic ft/min)

DischargeTemperature(°F)

Flow Rate/TempInformationSource Discharge Direction

Stack/VentSTRU48 SV041 Unit 4 Bunkers & Trippers 164 3.66 Null Null 38800 70 Manufacturer

Upwardswithnocaponstack/vent


18.6 1.33 Null Null 10909 759 ManufacturerUpwards with no cap onstack/vent



Stack/Vent, General


Details for:SI Category: StructureSI Type: Stack/Vent




InstallationStart Date

PollutantControlled

CaptureEfficiency(%)

Destruction CollectEfficiency (%)

Subject toCAM?

Large orOther PSEU?

EfficiencyBasis

Otheroperatingparameters?

Other operatingparametersdescription

062-Dust Suppress byChemStabilizer/WettingAgent

TREA34 CE042 Dust Suppression byChemical Stabilizers orWetting Agents

NA NA 4/1/2007ParticulateMatter

75 99.99 Null Null Null No Null

PM < 2.5micron


PM < 10micron


099-Other TREA6 CE027 Unit 4 LNB/SOFA Alstom LNCF 10/15/2010NitrogenOxides

100 27 No Null Null No Null

TREA7 CE028 Unit 4 ROTA-Mix SNCR Nalco Mobotec RotaMix 1/12/2009NitrogenOxides

100 70.7 Yes Large Null No Null

TREA8 CE019Unit 3 Low NOxBurners/Over-Fire Air

Alstom LNCF 10/30/2009NitrogenOxides

0 0.01 No Null Null No Null

TREA10 CE022 Unit 3 Wet Flue GasDesulfurization

Hitachi 332-003310/30/2009 Fluorides 100 65 No Null Null No Null

HydrogenChloride


SulfurDioxide




TREA12 CE025 Unit 1 ROFA Nalco Mobotec ROFA 6/13/2009NitrogenOxides


TREA13 CE026 Unit 2 ROFA Nalco Mobotec ROFA 12/2/2008NitrogenOxides




TREA21 CE030 Unit 4 Semi-Dry FlueGas Desulfurization &High-Temp Fabric Filter

Alstom NID 10/25/2015 Fluorides 100 90 Yes Large Null No Null

HydrogenChloride


Lead 100 99.9 No Null Null No Null

ParticulateMatter


PM < 2.5micron


PM < 10micron


SulfurDioxide


TREA33 CE041 Paved roadwatering/sweeping



PM < 2.5micron


PM < 10micron


139-SCR (SelectiveCatalytic Reduction)

TREA5 CE020Unit 3 SCR (SelectiveCatalytic Reduction)

Hitachi 332-003310/30/2009NitrogenOxides


901-2 - 3 % MoistureContent

TREA35 CE043 2 - 3 % MoistureContent


83.5 99.99 Null Null Null No Null

PM < 2.5micron


PM < 10micron

68.8 99.99 Null Null Null No Null

Other Control Equipment


Details for:SI Category: TreatmentSI Type: 062-Dust Suppress by Chem Stabilizer/Wetting Agent, 099-Other, 139-SCR (Selective Catalytic Reduction) and 1 more




Installation Start Date

PollutantControlled


DestructionCollectEfficiency(%)

Subject toCAM?

Large orOther PSEU?

EfficiencyBasis

Fabric FilterMinimumPressureDrop (in. of ..

Fabric FilterMaximumPressureDrop (in. of ..

Bag leakdetector inuse?

016-FabricFilter - HighTemp, T>250Degrees F

TREA9 CE021 Unit 3 FabricFilter

Hamon LPHV 10/30/20..Lead 100 88.3 No Null Null Null Null Null

ParticulateMatter

100 99.6 Yes Large Null Null Null Null

PM < 2.5micron

100 88.4 No Null Null Null Null Null

PM < 10micron

100 97 Yes Large Null Null Null Null


Western Precip.(Joy Mfg.)

8 1/1/1974ParticulateMatter

100 99.6 Yes Other Null Null Null Null

PM < 2.5micron


PM < 10micron



Western Precip.(Joy Mfg.)

8 1/1/1974ParticulateMatter

100 99.6 Yes Other Null Null Null Null

PM < 2.5micron


PM < 10micron


018-FabricFilter - LowTemp, T<180Degrees F

TREA1 CE016 Unit 3LimestoneSilo FabricFilter

MAC 39AVRC..10/30/20..ParticulateMatter

100 99 No Null Null Null Null Null

PM < 2.5micron


PM < 10micron


TREA2 CE044 Fly Ash Silo ALoadoutTruck BayFabric Filter

Air-Cure 484RF8 12/30/20..Lead 80 99 No Null Null Null Null Null

ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA23 CE032 Unit 4 LimeSilo FabricFilter

FlexKleen 100-BV..10/25/20..ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA24 CE033 Unit 4 LimeDay Bin AFabric Filter

Donaldson ToritTBV-4 10/25/20..ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA25 CE034 Unit 4 LimeDay Bin BFabric Filter



PM < 2.5micron


PM < 10micron


TREA26 CE035 Unit 4 LimeDay Bin CFabric Filter



PM < 2.5micron


PM < 10micron


TREA27 CE036 Unit 4 LimeDay Bin DFabric Filter



PM < 2.5micron


PM < 10micron


TREA29 CE037 Unit 4 LimeDay Bin EFabric Filter



PM < 2.5micron


PM < 10micron


TREA30 CE038 Unit 4ActivatedCarbon SiloFabric Filter

IAC 39PE-BVI10/25/20..ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA31 CE039 Fly Ash Silo BFabric Filter

Camcorp 15TR10..10/25/20..Lead 100 99.75 No Null Null Null Null Null

ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA32 CE040 FlyAshSiloBTruckBayFabricFilter

Air-Cure 484RF8 10/25/20..Lead 100 99.7 No Null Null Null Null Null

Fabric Filters, General


Details for:SI Category: TreatmentSI Type: 016-Fabric Filter - High Temp, T>250 Degrees F & 018-Fabric Filter - Low Temp, T<180 Degrees F





PollutantControlled



Subject toCAM?

Large orOther PSEU?

EfficiencyBasis





TREA31 CE039Fly Ash Silo BFabric Filter Camcorp 15TR10..10/25/20..

PM < 10micron 100 99.75 No Null Null Null Null Null

TREA32 CE040 Fly Ash Silo BTruck BayFabric Filter

Air-Cure 484RF8 10/25/20..Lead 100 99.7 No Null Null Null Null Null

ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA36 CE015 Fly Ash Silo A& LoadoutSpoutVentedAnnularHood FabricFilter

IAC 120-TB-..10/30/20..Lead 80 99 No Null Null Null Null Null

ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA37 CE007 CrusherHouse C-8(DC-8)

Air-Cure 232RF8 1/1/1958 Lead 100 99 No Null Null Null Null Null

ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA38 CE008 CrusherHouse C-14(DC-14)


ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA39 CE009 Fly Ash #1 &#2 SiloFabric Filter

Mikropul (USFilter Corps)

NA 1/1/1958 Lead 100 99 No Null Null Null Null Null

ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA40 CE010 #1 & #2 FlyAshSeparatorFabric Filter

UnitedConveyor

NA 1/1/1958 Lead 100 99 No Null Null Null Null Null

ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA41 CE013 Unit 3ActivatedCarbon SiloFabric Filter



PM < 2.5micron


PM < 10micron


TREA42 CE017 LimestoneDay Bin 1Fabric Filter

MAC 39ARC3210/30/20..ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA43 CE018 LimestoneDay Bin 2Fabric Filter

MAC 39AVRC..10/30/20..ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA46 CE045 RailUnloading(DC-7)


ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA47 CE046 LoweringWell & CoalSilos (DC-4)


ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA48 CE047 TransferHouse AC16/C18(DC-16)


ParticulateMatter









PollutantControlled



Subject toCAM?

Large orOther PSEU?

EfficiencyBasis





TREA48 CE047 TransferHouse AC16/C18(DC-16)

Air-Cure 376RF12 3/25/2011Lead 100 99 No Null Null Null Null NullParticulateMatter


PM < 2.5micron


PM < 10micron


TREA49 CE048 TransferHouse BC9/C10(DC-10)


ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA50 CE049 Dust Tank(DC-DT)

Air-Cure 324/156..12/31/20..Lead 100 99 No Null Null Null Null Null

ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA51 CE050 Units 1, 2, 3Bunkers &Trippers(DC-12)


ParticulateMatter


PM < 2.5micron


PM < 10micron


TREA52 CE051 Unit 4Bunkers &Trippers(DC-5)


ParticulateMatter


PM < 2.5micron


PM < 10micron





Subject Item ID SI Designation and Description Manufacturer Model


PollutantControlled

CaptureEfficiency (%)


Subject toCAM?

Large orOther PSEU?

EfficiencyBasis

MaterialInjected

InjectionSystemMaximumInjection Ra..

MaximumInjectionRate Units

InjectionSystemMinimumInjection Ra..

MinimumInjectionRate Units

.. Injection, TREA22 CE031.. Alstom Mercure 11/30/20..Mercury 100 90 No Null Null Null Null Null Null Null

.. Injection, TREA28 CE029.. ADA-ES NA 10/30/20..Mercury 100 90 No Null Null Null Null Null Null Null

Injections Systems, General


Details for:SI Category: TreatmentSI Type: 207-Carbon Injection

Subject

Item ID

Sequence

Number Requirement

TFAC 1 1

Permit Appendices: This permit contains appendices as listed below and in the permit Table of Contents. The Permittee shall comply with all requirements contained in Appendices A, B, D, E, F, G, H, I, and J. Modeling parameters in Appendix C are included for reference only as described elsewhere in this permit.

Appendix A. Insignificant Ac vi es and General Applicable Requirements

Appendix B. Acid Rain Permit Applica on

Appendix C. Parameters used in Modeling

Appendix D. 2018 Fugi ve Emissions Control PlanAppendix E. Part 63, Subpart UUUUU Equa ons

Appendix F. Consent Decree Defini ons

Appendix G. Transport Rule Requirements

Appendix H. No ces of Compliance Status Appendix I. Emergency Generator Best Management Prac ces Appendix J: EPA Approval for STRU13 Alternate CO2 Monitoring Procedures [Minn. R. 7007.0800, subp. 2(A)&(B)]

TFAC 1 2

Permit Appendices (cont.)The Permittee may revise or request revision of any permit appendix as follows:

1. Revisions to the Consent Decree Definitions (App. F), EPA‐Approved STRU13 Alternate CO2 Monitoring (App.K), Modeling Parameters (App. C), part 97 Transport Rule (App. G), and Emergency Generator Best Management

Practices (App. I) must be made according to the requirements of Minn. R. 7007.1150 ‐ 7007.1500.

2. Revisions to the Insignificant Activity list (App. A) may be made according to Minn. R. 7007.1250, Minn. R.7007.1300, or Minn. R. 7007.1350. Revisions to the insignificant activity list shall be submitted on the applicableform (currently IA‐01) as part of the next permit application submitted by the Permittee after the change ismade.

3. Revisions to appendices based on a rule (such as the part 63, subp. UUUUU Notice Of Compliance Status(App. H), subp. UUUUU Equations (App. E), or part 72 Acid Rain Program (App. B)) where the rule pre‐authorizes, allows, or accommodates changes, do not need a permit amendment. Such revisions or changesmust be submitted to the agency by the submittal date specified in the rule, or if no date is specified therevision or change shall be submitted no later than 30 days after making the revision or change. Therevision/change will be incorporated into the permit by the next permit action.

4. Revisions to the Fugitive Emissions Control Plan (App. D) shall be made as prescribed in the followingrequirement. [Minn. R. 7007.0800, subp. 2(A)&(B)]

TFAC 1 3

The Permittee shall revise the Fugitive Emissions Control Plan (FECP) as needed to reflect any changing conditions at the facility. Such revisions must be dated and submitted to the Commissioner before the Permittee can operate pursuant to these revisions. The Commissioner may object to such revisions if the revised FECP does not meet the requirements of 40 CFR 60.254(c) and/or Minn. R. 7011.0150, as applicable. If an objection is raised, the Permittee, within 30 days from receipt of the objection, must submit a revised FECP to the Commissioner. The Permittee must operate in accordance with the revised FECP. The Commissioner retains the right, under 40 CFR 60.254(c)(5), to object to revisions regarding the coal storage pile (including equipment used in the loading, unloading, and conveying operations of the coal storage pile), and under Minn. R. 7007.0800, subp. 2(A)&(B), to object to revisions regarding the entire revised FECP, if it determines the FECPdoes not meet the requirements of under 40 CFR 60.254(c)(5) for the coal storage pile, or if it determines theFECP does not meet the requirements of Minn. R. 7011.0150 for any fugitive source in the FECP. [40 CFR60.254(c)(4)(ii)&(c)(5), Minn. R. 7007.0800, subp. 2(A)&(B)]

Subject

Item ID

Sequence

Number Requirement

TFAC 1 8

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 1 9

Comply with Fugitive Emissions Control Plan: The Permittee shall follow the actions and recordkeeping specified in the November 2017 Fugitive Emissions Control Plan (Appendix D of this permit). The plan may be amended by the Permittee according to the requirements of this permit. If the Commissioner determines the Permittee is out of compliance with Minn. R. 7011.0150 or the plan, then the Permittee may be required to amend the plan and/or to install and operate particulate matter ambient monitors as requested by the Commissioner. [40 CFR 60.254(c), Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7009.0020, Minn. R. 7011.0150, Minn. Stat. 116.07, subd. 4a, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

TFAC 1 10

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(A), Title I Condition: 40 CFR 52.21(r)(6) and Minn. R. 7007.3000]

TFAC 1 11

Preconstruction Documentation ‐‐ Before beginning actual construction on a project, the Permittee shall document the following:

1. Project descrip on

2. Iden fica on of any emission unit whose emissions of an NSR pollutant could be affected3. Pre‐change potential emissions of any affected existing emission unit, and the projected post‐change poten al emissions of any affected exis ng 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 determina on.

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]

Subject

Item ID

Sequence

Number Requirement

TFAC 1 12

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 1 13

The Permittee must submit a report to the Agency if the annual summed (actual, plus potential if 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 a er 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 preconstruc on projec on and significant emissions increase are exceededc. 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 1 14

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 1 15

For any project which includes any EUSGU, the Permittee must submit an annual report to the Agency, within 60 days a er 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 1 16

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 preconstruc on projec on 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 1 17

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 7009.0090. 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. 7009.0010‐7009.0090, Minn. Stat. 116.07, subd. 4a&9]

Subject

Item ID

Sequence

Number Requirement

TFAC 1 18

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 1 19

Air Pollution Control Equipment: Operate all pollution control equipment whenever the corresponding process equipment and emission units are operated unless specified otherwise in this permit (refer to requirements 5.20.19 and 5.32.14 in subject items EQUI85 (Unit 4) and EQUI100 (Unit 3), respectively for specific requirements allowing EQUI85 and EQUI100 to operate without operating TREA22 and TREA28 mercury controls, respectively, only when firing only natural gas). [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B)]

TFAC 1 21

Operation and Maintenance (O & M) Plan: Retain at the stationary source an O & M 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 1 22

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 1 23

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 1 24

Noise: The Permittee shall comply with the noise standards in Minn. R. 7030.0010 to 7030.0080 at all times during the operation of any emission unit(s). 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 1 25

Inspections: The Permittee shall comply with the inspection procedures and requirements at Minn. R. 7007.0800, subp. 9(A). [Minn. R. 7007.0800, subp. 9(A)]

TFAC 1 27

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

TFAC 1 28

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

TFAC 1 29

Performance Test No fica ons and Submi als

Performance Test No fica on and Plan: due 30 days before each Performance TestPerformance Test Pre‐test Mee ng: due 7 days before each Performance TestPerformance Test Report: due 45 days a er each Performance Test

The Notification, Test Plan, and Test Report must be submitted in a format specified by the commissioner. [Minn. R. 7017.2017, Minn. R. 7017.2030, subps. 1‐4, Minn. R. 7017.2035, subps. 1‐2]

TFAC 1 30

Operating and/or production limits will be placed on emission units based on operating conditions during compliance testing. Limits set as a result of a compliance test (conducted before or after permit issuance) apply until new operating/production limits are set following formal review of a performance test as specified by Minn. R. 7017.2025. This does not apply to EQUI82, EQUI83, EQUI100, and EQUI85. These units may be subject to specific operating and/or production limits. [Minn. R. 7017.2025]

Subject

Item ID

Sequence

Number Requirement

TFAC 1 35

Monitoring Equipment Calibra on ‐ The Permi ee shall either:1. Calibrate or replace required monitoring equipment every 12 months; or2. Calibrate at the frequency stated in the manufacturer's specifica ons.

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 1 36

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 1 37

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 1 38

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 1 39

If the Permittee determines 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. Records shall be kept for a period of five years from the date the change was made or until permit reissuance, whichever is longer. 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. Records may be maintained in either electronic or paper format. [Minn. R. 7007.1200, subp. 4]

TFAC 1 40

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 1 42

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 1 43

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]

Subject

Item ID

Sequence

Number Requirement

TFAC 1 45

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 informa on in this wri en descrip on:

1. the cause of the devia on; 2. the exact dates of the period of the devia on, if the devia on has been corrected;3. whether or not the devia on has been corrected; 4. the an cipated me by which the devia on 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 1 46

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 occurred, the Permittee shall submit the report stating no deviations. [Minn. R. 7007.0800, subp. 6(A)(2)]

TFAC 1 47

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. The preceding sentence does not apply if the effective date of the requirement is later than the date on which the permit is due to expire. [Minn. R. 7007.0400, subp. 3, Minn. R. 7007.1150 ‐ 7007.1500]

TFAC 1 53

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 1 57

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 1 58

Emission Inventory Report: due on or before April 1 of each calendar year following permit issuance. Submit the report in a format specified by the Commissioner. [Minn. R. 7019.3000‐7019.3100]

TFAC 1 59 Emission Fees: due 30 days after receipt of an MPCA bill. [Minn. R. 7002.0005‐7002.0095]

TFAC 1 60

The Permittee shall submit an application for permit reissuance : Due 180 calendar days before Permit Expiration Date. The application shall include the EQUI85 Mercury Control Optimization Plan for mercury control equipment optimization required by Minn. Stat. 216B.687, subd. 3. [Minn. R. 7007.0400, subp. 2, Minn. R. 7007.0800, subp. 2(B)]

TFAC 1 61

The Permittee shall submit excess emission/downtime report : Due by 30 days after the end of each calendar quarter following permit issuance. This report applies to EQUI82, EQUI83, EQUI85, and EQUI100. [Minn. R. 7017.1110, subp. 1‐2]

Subject

Item ID

Sequence

Number Requirement

TFAC 1 69

Modeled Parameters for SO2 and CO: The parameters used in modeling for the 1‐hour SO2 national ambient air quality standards for permit number 06100004‐008 and for EQUI85 and EQUI100 CO Significant Impact Levels modeling are listed in Appendix C of this permit. The parameters describe the operation of the facility at maximum permitted capacity. The purpose of listing the parameters in the appendix is to provide a benchmark for future changes. [Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 1&2(A)&(B), Minn. R. 7007.0800, subp. 4, Minn. R. 7009.0010‐7009.0090, Minn. Stat. 116.07, subd. 4a&9]

TFAC 1 70

This permit requires modeling to demonstrate compliance with the PM2.5 24‐hour National Ambient Air Quality Standard (NAAQS). The Permittee shall not make any change at the source that would result in an increase in PM2.5 ambient air impacts until it demonstrates the change will not cause the facility as permitted to cause an exceedance of the PM2.5 24‐hour NAAQS. [Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 1&2(A)&(B), Minn. R. 7007.0800, subp. 4, Minn. R. 7009.0010‐7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

TFAC 1 71

Computer Dispersion Modeling Protocol: due 180 days after issuance of permit No. 06100004‐008 for PM2.5 refined modeling. The Permittee shall submit a Computer Dispersion Modeling Protocol that is complete and approvable by MPCA by the deadline in this requirement. This protocol will describe the proposed modeling methodology and input data, in accordance with the current version of the MPCA Air Dispersion Modeling Guidance. [Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7009.0020, Minn. Stat. 116.07, subd. 4a&9]

TFAC 1 72

Computer Dispersion Modeling Protocol: due 60 days after receipt of written MPCA request for revisions to the submitted PM2.5 modeling protocol. [Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7009.0020, Minn. Stat. 116.07, subd. 4a&9]

TFAC 1 73

Computer Dispersion Modeling Results: due 180 days after receipt of written MPCA approval of Computer Dispersion Modeling Protocol for PM2.5. The Permittee shall submit a final Computer Dispersion Modeling Report that is complete and approvable by MPCA by the deadline in this requirement. The submittal shall adhere to the current version of the MPCA Air Dispersion Modeling Guidance and the approved Computer Dispersion Modeling Protocol. [Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7009.0020, Minn. Stat. 116.07, subd. 4a&9]

TFAC 1 74

Changes To 1‐Hour SO2 Modeled Parameters: If the Permittee desires to change any parameter used in 1‐hour SO2 (baseline) modeling listed in permit Appendix C, the Permittee shall obtain written approval from the MPCA before making any change. Any modeling submittal shall be prepared in accordance with the current version of the MPCA Air Dispersion Modeling Prac ce Manual.

To obtain approval, the Permi ee may be required to submit the baseline and revised STRU13 and STRU14 SO2 emission rate, location, height, diameters, exit velocity, exit temperature, discharge direction, use of rain caps or rain hats, and, if applicable, locations and dimensions of nearby buildings, using form AQDM‐08.

Additionally, if the baseline modeling is outdated the Permittee must remodel according to the current version of the MPCA Air Dispersion Modeling Practice Manual. When remodeling is required, the Permittee shall submit:

1. A complete, approvable modeling protocol no later than 180 days a er receipt of wri en MPCA request for SO2 refined modeling including form AQDM‐02 through the MPCA e‐services portal2. Protocol revisions no later than 60 days a er requested including form AQDM‐1.5, and3. Modeling results no later than 180 days a er MPCA approval of the protocol including form AQDM‐06.MPCA wri en approval of changes affec ng any modeled SO2 parameter applies only to the remodeling determination. Any written approval regarding remodeling does not exempt the Permittee from obtaining any required permit or permit amendment for making such change(s), and any written approval does not take the place of any permit or permit amendment that may be required due to such change(s). [Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 1&2, Minn. R. 7007.0800, subp. 4, Minn. R. 7009.0010‐7009.0090, Minn. Stat. 116.07, subd. 4a&9]

Subject

Item ID

Sequence

Number Requirement

COMG 1 1

EQUI82 Sulfur Dioxide <= 1.18 pounds per million Btu heat input 1‐hour average. This limit applies when EQUI82 flue gasses vent through STRU12. [Minn. R. 7009.0020]

COMG 1 2

EQUI82 Sulfur Dioxide <= 1.18 pounds per million Btu heat input 3‐hour average. This limit applies when EQUI82 flue gasses vent through STRU12. [40 CFR 50.5]

COMG 1 3

EQUI82 Sulfur Dioxide <= 4.00 pounds per million Btu heat input 1‐hour average when EQUI82 vents through STRU13 and EQUI100 and EQUI85 are operating. [Minn. R. 7009.0020]

COMG 1 4

EQUI82 Sulfur Dioxide <= 4.00 pounds per million Btu heat input 3‐hour average when EQUI82 and EQUI83 vent through STRU13 and EQUI100 is operating. [40 CFR 50.5]

COMG 1 5

EQUI82 Sulfur Dioxide <= 4.00 pounds per million Btu heat input 3‐hour average for solid fossil fuel. When solid and gaseous fossil fuels are burned simultaneously in any combination, the applicable standard shall be determined by prora on using the following formula:

w = 4z/(x+z)

where:

w = allowable Sulfur Dioxide emissions in pounds per million heat input Btu 3‐hour averagex = % heat input from gaseous fossil fuelz = % heat input from solid fossil fuel

This limit applies regardless of the operation and venting of other COMG1 boilers. [Minn. R. 7011.0505, subp. 3, Minn. R. 7011.0510, subp. 1]

COMG 1 6

EQUI83 Sulfur Dioxide <= 1.18 pounds per million Btu heat input 1‐hour average. This limit applies when EQUI83 flue gasses vent through STRU12. [Minn. R. 7009.0020]

COMG 1 7

EQUI83 Sulfur Dioxide <= 1.18 pounds per million Btu heat input 3‐hour average. This limit applies when EQUI83 flue gasses vent through STRU12. [40 CFR 50.5]

COMG 1 8

EQUI83 Sulfur Dioxide <= 4.00 pounds per million Btu heat input 1‐hour average when EQUI83 vent through STRU13 and EQUI100 and EQUI85 are operating. [Minn. R. 7009.0020]

COMG 1 9

EQUI83 Sulfur Dioxide <= 4.00 pounds per million Btu heat input 3‐hour average when EQUI82 and EQUI83 vent through STRU13 and EQUI100 is operating. [40 CFR 50.5]

COMG 1 10

EQUI83 Sulfur Dioxide <= 4.00 pounds per million Btu heat input 3‐hour average for solid fossil fuel. When solid and gaseous fossil fuels are burned simultaneously in any combination, the applicable standard shall be determined by proration using the following formula:

w = 4z/(x+z)

where:

w = allowable Sulfur Dioxide emissions in pounds per million Btu heat input 3‐hour averagex = % heat input from gaseous fossil fuelz = % heat input from solid fossil fuel


COMG 1 11

EQUI85 Sulfur Dioxide <= 1.20 pounds per million Btu heat input 1‐hour average. This limit applies when EQUI85 operates alone, or when EQUI82 and EQUI83 vent through STRU12, or when EQUI82, EQUI83, and EQUI100 vent through STRU13. [Minn. R. 7009.0020]

COMG 1 13

EQUI85 Sulfur Dioxide <= 1.20 pounds per million Btu heat input 3‐hour average. [40 CFR 60.43(a)(2), Minn. R. 7011.0555, 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 1 16

EQUI100 Sulfur Dioxide <= 2.97 pounds per million Btu heat input 1‐hour average when EQUI82 and EQUI83 are operating and vent through STRU12. [Minn. R. 7009.0020]

Subject

Item ID

Sequence

Number Requirement

COMG 1 17

EQUI100 Sulfur Dioxide <= 4.00 pounds per million Btu heat input 1‐hour average when EQUI100 is operating alone or, when EQUI82 and EQUI83 are operating and venting through STRU13 and EQUI85 is operating. [Minn. R. 7009.0020]

COMG 1 18

EQUI100 Sulfur Dioxide <= 4.00 pounds per million Btu heat input 3‐hour average when EQUI82 and EQUI83 vent through STRU13. [40 CFR 50.5]

COMG 1 19

EQUI100 Sulfur Dioxide <= 4.00 pounds per million Btu heat input 3‐hour average for solid fossil fuel. When solid and gaseous fossil fuels are burned simultaneously in any combination, the applicable standard shall be determined by proration using the following formula:

w = 4z/(x+z)

where:

w = allowable Sulfur Dioxide emissions in pounds per million Btu heat input 3‐hour averagex = % heat input from gaseous fossil fuelz = % heat input from solid fossil fuel


COMG 1 21

EQUI100/STRU13 and EQUI85/STRU14 Sulfur Dioxide Limits When EQUI82 and EQUI83 Are Not Operating:

Sulfur Dioxide <= to any one of the following conditions:

Condition 1) 3.52 pounds per million Btu heat input for STRU13 and 1.20 pounds per million Btu heat input for STRU14, both on a 1‐hour average; OR,

Condition 2) 4.00 pounds per million Btu heat input for STRU13 and 0.88 pounds per million Btu heat input for STRU14, both on a 1‐hour average; OR,

Condition 3) 3.67 pounds per million Btu heat input for STRU13 and 1.10 pounds per million Btu heat input for STRU14, both on a 1‐hour average. [Minn. R. 7009.0020]

COMG 1 22 STRU13 Sulfur Dioxide <= 4450 pounds per hour 1‐hour average. [40 CFR 50.17]COMG 1 23 STRU14 (EQUI85) Sulfur Dioxide <= 2600 pounds per hour 1‐hour average. [40 CFR 50.17]

Subject

Item ID

Sequence

Number Requirement

COMG 1 24

EQUI82, EQUI83, EQUI100, and EQUI85 Sulfur Dioxide <= 0.20 pounds per million Btu heat input from each boiler, or EQUI82, EQUI83, EQUI100, and EQUI85 Sulfur Dioxide <= 1.50 pounds/megawatt‐hour from each boiler;

OR

EQUI82, EQUI83, EQUI100, and EQUI85 Hydrogen Chloride <= 0.002 pounds per million Btu from each boiler, or EQUI82, EQUI83, EQUI100, and EQUI85 Hydrogen Chloride <= 0.02 pounds per megawatt‐hour from each boiler.

The Permittee has the option of complying with the either of the heat input‐based or electrical output‐based Hydrogen Chloride limits, or complying with either of the heat input‐based or electrical output‐based Sulfur Dioxide limits. The Permittee has elected to comply with the Sulfur Dioxide heat input‐based limit for EQUI85, and the Hydrogen Chloride heat input‐based limit for EQUI82, EQUI83, and EQUI100 (as indicated in Appendices H Notices of Compliance Status). If the Permittee elects to change the selected compliance option, the Permittee shall submit a revised Notice of Compliance Status as described in Section 5.6.7 of this permit, to both the US E.P.A Administrator and the MPCA Commissioner.

NOTE: These Part 63, subp. UUUUU Hydrogen Chloride (HCl) and alternate Sulfur Dioxide (SO2) limits are repeated in COMG7 (Part 63, Subpart UUUUU Requirements). [40 CFR pt. 63, subp. UUUUU (Table 2), Minn. R. 7011.0563]

COMG 1 25

Operate EQUI82 and EQUI83 such that each unit achieves and maintains an emission rate of Sulfur Dioxide <= 0.700 pounds per million Btu heat input 30‐day rolling average.

Note: The Permittee submitted a written notification dated December 19, 2016 to the USEPA and MPCA indicating EQUI82 and EQUI83 will be retired no later than December 31, 2018. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 1 26

If the Permittee chooses to Reroute the flue gas from EQUI82 and EQUI83, no later than December 31, 2018 the Permittee shall Continuously Operate an FGD device such that EQUI82, EQUI83, and EQUI100 achieve and maintain a combined emission rate for Sulfur Dioxide <= 0.030 pounds per million Btu heat input 30‐day rolling average.

Note: The Permittee submitted a written notification dated December 19, 2016 to the USEPA and MPCA indicating EQUI82 and EQUI83 will be retired no later than December 31, 2018. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 1 27

The Permittee shall Continuously Operate an FGD device (TREA10) at EQUI100 such that EQUI100 achieves and maintains an emission rate for Sulfur Dioxide <= 0.030 pounds per million Btu heat input 30‐day rolling average. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 1 28

The Permittee shall Continuously Operate an FGD device (TREA21) at EQUI85 such that EQUI85 achieves and maintains an emission rate for Sulfur Dioxide <= 0.030 pounds per million Btu heat input 30‐day rolling average. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

Subject

Item ID

Sequence

Number Requirement

COMG 1 29

Prior to 2019, the Permittee shall not exceed the System‐Wide Annual Tonnage Limitation for Sulfur Dioxide <= 7000 tons per year on a calendar year basis. Commencing 2019 and continuing thereafter, the Permittee shall not exceed the System‐Wide Annual Tonnage Limitation for Sulfur Dioxide <= 3,000 tons per year on a calendar year basis.

The Minnesota Power System is composed of Boswell Energy Center, Laskin Energy Center, Rapids Energy Center, and Taconite Harbor Energy Center. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 3 3

The Permittee shall operate and maintain TREA37/CE007 (EQUI1/EU011 Crusher House C‐8), TREA38/CE008 (EQUI102/EU012 Crusher House C‐14), TREA39/CE009 (EQUI3/EU013 Fly Ash ‐ #1 & #2 Silo), and TREA40/CE010 (EQUI4/EU014 #1&2 Fly Ash Separator) so that each filter achieves an overall control efficiency for Particulate Matter >= 99 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 3 4

The Permittee shall operate and maintain TREA37/CE007 (EQUI1/EU011 Crusher House C‐8), TREA38/CE008 (EQUI102/EU012 Crusher House C‐14), TREA39/CE009 (EQUI3/EU013 Fly Ash ‐ #1 & #2 Silo), and TREA40/CE010 (EQUI4/EU014 #1&2 Fly Ash Separator) so that each filter achieves an overall control efficiency for PM < 10 micron >= 93 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 3 5

The Permittee shall operate and maintain TREA37/CE007 (EQUI1/EU011 Crusher House C‐8), TREA38/CE008 (EQUI102/EU012 Crusher House C‐14), TREA39/CE009 (EQUI3/EU013 Fly Ash ‐ #1 & #2 Silo), and TREA40/CE010 (EQUI4/EU014 #1&2 Fly Ash Separator) so that each filter achieves an overall control efficiency for PM < 2.5 micron >= 93 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 3 6

The Permittee shall operate and maintain TREA37/CE007 (EQUI1/EU011 Crusher House C‐8), TREA38/CE008 (EQUI102/EU012 Crusher House C‐14), TREA39/CE009 (EQUI3/EU003 Fly Ash ‐ #1 & #2 Silo), and TREA40/CE010 (EQUI4/EU014 #1&2 Fly Ash Separator) so that each filter achieves an overall control efficiency for Lead >= 99 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 3 7

The Permittee shall operate and maintain TREA41/CE013 (EQUI99/EU015 Hg Additive Handling and Unit 3 PAC Silo), TREA1/CE016 (EQUI5/EU019 Unit 3 Limestone Silo), TREA42/CE017 (EQUI6/EU020 Unit 3 Limestone Day Bin 1), and TREA43/CE018 (EQUI7/EU021 Unit 3 Limestone Day Bin 2) so that each filter achieves an overall control efficiency for Particulate Matter >= 99 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 8

The Permittee shall operate and maintain TREA41/CE013 (EQUI99/EU015 Hg Additive Handling and Unit 3 PAC Silo), TREA1/CE016 (EQUI5/EU019 Unit 3 Limestone Silo), TREA42/CE017 (EQUI6/EU020 Unit 3 Limestone Day Bin 1), and TREA43/CE018 (EQUI7/EU021 Unit 3 Limestone Day Bin 2) so that each filter achieves an overall control efficiency for PM < 10 micron >= 99 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 9

The Permittee shall operate and maintain TREA41/CE013 (EQUI99/EU015 Hg Additive Handling and Unit 3 PAC Silo), TREA1/CE016 (EQUI5/EU019 Unit 3 Limestone Silo), TREA42/CE017 (EQUI6/EU020 Unit 3 Limestone Day Bin 1), and TREA43/CE018 (EQUI7/EU021 Unit 3 Limestone Day Bin 2) so that each filter achieves an overall control efficiency for PM < 2.5 micron >= 93 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 3 10

The Permittee shall operate and maintain TREA36/CE015 so the filter achieves an overall control efficiency for EQUI122 Fly Ash Silo A Loadout Spout w/Ventilated Annular Hood Particulate Matter >= 79 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 11

The Permittee shall operate and maintain TREA36/CE015 so the filter achieves an overall control efficiency for EQUI122 Fly Ash Silo A Loadout Spout w/Ventilated Annular Hood PM < 10 micron >= 74 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

Subject

Item ID

Sequence

Number Requirement

COMG 3 12

The Permittee shall operate and maintain TREA36/CE015 so the filter achieves an overall control efficiency for EQUI122 Fly Ash Silo A Loadout Spout w/Ventilated Annular Hood PM < 2.5 micron >= 43 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 13

The Permittee shall operate and maintain TREA36/CE015 so the filter achieves an overall control efficiency for EQUI122 Fly Ash Silo A Loadout Spout w/Ventilated Annular Hood Lead >= 79 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 3 14

The Permittee shall operate and maintain TREA36/CE015 so the filter achieves an overall control efficiency for EQUI98/EU017 Fly Ash Silo A Particulate Matter >= 99.0 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 15

The Permittee shall operate and maintain TREA36/CE015 so the filter achieves an overall control efficiency for EQUI98/EU017 Fly Ash Silo A PM < 10 micron >= 93 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 16

The Permittee shall operate and maintain TREA36/CE015 so the filter achieves an overall control efficiency for EQUI98/EU017 Fly Ash Silo A PM < 2.5 micron >= 54.0 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 3 17

The Permittee shall operate and maintain TREA36/CE015 so the filter achieves an overall control efficiency for EQUI98/EU017 Fly Ash Silo A Lead >= 99.0 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 3 18

The Permittee shall operate and maintain TREA23/CE032 (EQUI86/EU024 Unit 4 Lime Silo), TREA24/CE033 (EQUI87/EU025 Unit 4 Lime Day Bin A), TREA25/CE034 (EQUI88/EU026 Unit 4 Lime Day Bin B), TREA26/CE035 (EQUI89/EU027 Unit 4 Lime Day Bin C), TREA27/CE036 (EQUI90/EU028 Unit 4 Lime Day Bin D), TREA29/CE037 (EQUI91/EU029 Unit 4 Lime Day Bin E), and TREA30/CE038 (EQUI120/EU030 Unit 4 Activated Carbon Silo) so that each filter achieves an overall control efficiency for Particulate Matter >= 99.5 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 19

The Permittee shall operate and maintain TREA23/CE032 (EQUI86/EU024 Unit 4 Lime Silo), TREA24/CE033 (EQUI87/EU025 Unit 4 Lime Day Bin A), TREA25/CE034 (EQUI88/EU026 Unit 4 Lime Day Bin B), TREA26/CE035 (EQUI89/EU027 Unit 4 Lime Day Bin C), TREA27/CE036 (EQUI90/EU028 Unit 4 Lime Day Bin D), TREA29/CE037 (EQUI91/EU029 Unit 4 Lime Day Bin E), and TREA30/CE038 (EQUI120/EU030 Unit 4 Activated Carbon Silo) so that each filter achieves an overall control efficiency for PM < 10 micron >= 99.5 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 20

The Permittee shall operate and maintain TREA23/CE032 (EQUI86/EU024 Unit 4 Lime Silo), TREA24/CE033 (EQUI87/EU025 Unit 4 Lime Day Bin A), TREA25/CE034 (EQUI88/EU026 Unit 4 Lime Day Bin B), TREA26/CE035 (EQUI89/EU027 Unit 4 Lime Day Bin C), TREA27/CE036 (EQUI90/EU028 Unit 4 Lime Day Bin D), TREA29/CE037 (EQUI91/EU029 Unit 4 Lime Day Bin E), and TREA30/CE038 (EQUI120/EU030 Unit 4 Activated Carbon Silo) so that each filter achieves an overall control efficiency for PM < 2.5 micron >= 99.5 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 22

The Permittee shall operate and maintain TREA31/CE039 (EQUI93/EU031 Fly Ash Silo B) so the filter achieves an overall control efficiency for Particulate Matter >= 99.75 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 23

The Permittee shall operate and maintain TREA31/CE039 (EQUI93/EU031 Fly Ash Silo B) so the filter achieves an overall control efficiency for PM < 10 micron >= 99.75 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

Subject

Item ID

Sequence

Number Requirement

COMG 3 24

The Permittee shall operate and maintain TREA31/CE039 (EQUI93/EU031 Fly Ash Silo B) so the filter achieves an overall control efficiency for PM < 2.5 micron >= 99.75 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 25

The Permittee shall operate and maintain TREA31/CE039 (EQUI93/EU031 Fly Ash Silo B) so the filter achieves an overall control efficiency for Lead >= 99.75 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 3 26

The Permittee shall operate and maintain TREA32/CE040 (EQUI94/EU032 Fly Ash Silo B Loadout ‐ Truck Bay) so the filter achieves an overall control efficiency for Particulate Matter >= 99.7 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 27

The Permittee shall operate and maintain TREA32/CE040 (EQUI94/EU032 Fly Ash Silo B Loadout ‐ Truck Bay) so the filter achieves an overall control efficiency for PM < 10 micron >= 99.7 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 28

The Permittee shall operate and maintain TREA32/CE040 (EQUI94/EU032 Fly Ash Silo B Loadout ‐ Truck Bay) so the filter achieves an overall control efficiency for PM < 2.5 micron >= 99.7 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 29

The Permittee shall operate and maintain TREA32/CE040 (EQUI94/EU032 Fly Ash Silo B Loadout ‐ Truck Bay) so the filter achieves an overall control efficiency for Lead >= 99.7 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 3 30

The Permittee shall operate and maintain TREA2/CE044 (EQUI97/EU018 Fly Ash Silo A Loadout ‐ Truck Bay) so the filter achieves an overall control efficiency for Particulate Matter >= 79 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 31

The Permittee shall operate and maintain TREA2/CE044 (EQUI97/EU018 Fly Ash Silo A Loadout ‐ Truck Bay) so the filter achieves an overall control efficiency for PM < 10 micron >= 74 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 32

The Permittee shall operate and maintain TREA2/CE044 (EQUI97/EU018 Fly Ash Silo A Loadout ‐ Truck Bay) so the filter achieves an overall control efficiency for PM < 2.5 micron >= 43 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 33

The Permittee shall operate and maintain TREA2/CE044 (EQUI97/EU018) so that the filter achieves an overall control efficiency for Lead >= 79 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 3 34

The Permittee shall operate and maintain TREA46/CE045 (EQUI111/EU035 Rail Unloading), TREA47/CE046 (EQUI112/EU036 Lowering Well & EQUI113/EU047 Coal Silo), TREA48/CE047 (EQUI114/EU037 C16/C18 Transfer House), TREA49/CE048 (EQUI115/EU038 C9/C10 Transfer House), TREA50/CE049 (EQUI116/EU039 Dust Tank), TREA51/CE050 (EQUI117/EU040 Units 1, 2, 3 Bunkers), and TREA52/CE051 (EQUI118/EU041 Unit 4 Bunkers) so each filter achieves an overall control efficiency for Particulate Matter >= 99.0 percent control efficiency. [Minn. R. 7011.0070]

COMG 3 35

The Permittee shall operate and maintain TREA46/CE045 (EQUI111/EU035 Rail Unloading), TREA47/CE046 (EQUI112/EU036 Lowering Well & EQUI113/EU047 Coal Silo), TREA48/CE047 (EQUI114/EU037 C16/C18 Transfer House), TREA49/CE048 (EQUI115/EU038 C9/C10 Transfer House), TREA50/CE049 (EQUI116/EU039 Dust Tank), TREA51/CE050 (EQUI117/EU040 Units 1, 2, 3 Bunkers), and TREA52/CE051 (EQUI118/EU041 Unit 4 Bunkers) so each filter achieves an overall control efficiency for PM < 10 micron >= 93.0 percent control efficiency. [Minn. R. 7011.0070]

Subject

Item ID

Sequence

Number Requirement

COMG 3 36

The Permittee shall operate and maintain TREA46/CE045 (EQUI111/EU035 Rail Unloading), TREA47/CE046 (EQUI112/EU036 Lowering Well & EQUI113/EU047 Coal Silo), TREA48/CE047 (EQUI114/EU037 C16/C18 Transfer House), TREA49/CE048 (EQUI115/EU038 C9/C10 Transfer House), TREA50/CE049 (EQUI116/EU039 Dust Tank), TREA51/CE050 (EQUI117/EU040 Units 1, 2, 3 Bunkers), and TREA52/CE051 (EQUI118/EU041 Unit 4 Bunkers) so each filter achieves an overall control efficiency for PM < 2.5 micron >= 93.0 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 3 37

The Permittee shall operate and maintain TREA46/CE045 (EQUI111/EU035 Rail Unloading), TREA47/CE046 (EQUI112/EU036 Lowering Well & EQUI113/EU047 Coal Silo), TREA48/CE047 (EQUI114/EU037 C16/C18 Transfer House), TREA49/CE048 (EQUI115/EU038 C9/C10 Transfer House), TREA50/CE049 (EQUI116/EU039 Dust Tank), TREA51/CE050 (EQUI117/EU040 Units 1, 2, 3 Bunkers), and TREA52/CE051 (EQUI118/EU041 Unit 4 Bunkers) so each filter achieves an overall control efficiency for Lead >= 99.0 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 3 38

The Permittee shall operate and maintain each of the following fabric filters at all times that any emission unit controlled by the fabric filter is in operation: 1. TREA37/CE007 (EQUI1/EU011 Crusher House C‐8), 2. TREA38/CE008 (EQUI102/EU012 Crusher House C‐14), 3. TREA39/CE009 (EQUI3/EU003 Fly Ash ‐ #1 & #2 Silo), 4. TREA40/CE010 (EQUI4/EU014 #1&2 Fly Ash Separator). The Permittee shall document periods of non‐operation of the control equipment. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 3 39

The Permittee shall operate and maintain each of the following fabric filters at all times that any emission unit controlled by the fabric filter is in opera on:

1. TREA36/CE015 (EQUI98/EU017 Fly Ash Silo A & EQUI122 Fly Ash Silo A Loadout), 2. TREA2/CE044 (EQUI97/EU018 Fly Ash Silo A Loadout ‐ Truck Bay)

The Permittee shall document periods of non‐operation of the control equipment. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 40


1. TREA46/CE045 (EQUI111/EU035 Rail Unloading), 2. TREA47/CE046 (EQUI112/EU036 Lowering Well & EQUI113/EU047 Coal Silo), 3. TREA48/CE047 (EQUI114/EU037 C16/C18 Transfer House), 4. TREA49/CE048 (EQUI115/EU038 C9/C10 Transfer House), 5. TREA50/CE049 (EQUI116/EU039 Dust Tank), 6. TREA51/CE050 (EQUI117/EU040 Units 1, 2, 3 Bunkers), and 7. TREA52/CE051 (EQUI118/EU041 Unit 4 Bunkers).

The Permittee shall document periods of non‐operation of the control equipment. [Minn. R. 7011.0075]

Subject

Item ID

Sequence

Number Requirement

COMG 3 41


1. TREA41/CE013 (EQUI99/EU015 Hg Addi ve Handling and Unit 3 PAC Silo), 2. TREA1/CE016 (EQUI5/EU019 Unit 3 Limestone Silo), 3. TREA42/CE017 (EQUI6/EU020 Unit 3 Limestone Day Bin 1), 4. TREA43/CE018 (EQUI7/EU021 Unit 3 Limestone Day Bin 2), 5. TREA23/CE032 (EQUI86/EU024 Unit 4 Lime Silo), 6. TREA24/CE033 (EQUI87/EU025 Unit 4 Lime Day Bin A), 7. TREA25/CE034 (EQUI88/EU026 Unit 4 Lime Day Bin B), 8. TREA26/CE035 (EQUI89/EU027 Unit 4 Lime Day Bin C), 9. TREA27/CE036 (EQUI90/EU028 Unit 4 Lime Day Bin D), 10. TREA29/CE037 (EQUI91/EU029 Unit 4 Lime Day Bin E), 11. TREA30/CE038 (EQUI120/EU030 Unit 4 Ac vated Carbon Silo), 12. TREA31/CE039 (EQUI93/EU031 Fly Ash Silo B), 13. TREA32/CE040 (EQUI94/EU032 Fly Ash Silo B Loadout ‐ Truck Bay).

The Permittee shall document periods of non‐operation of the control equipment. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 42

Visible Emissions: The Permittee shall check the following stacks for any visible emissions once each day of operation during daylight hours: 1. STRU18/SV011 (TREA37/CE007; EQUI1/EU011 Crusher House C‐8), 2. STRU19/SV012 (TREA38/CE008; EQUI102/EU012 Crusher House C‐14), 3. STRU20/SV013 (TREA39/CE009; EQUI3/EU013 Units 1&2 Fly Ash Silo), 4. STRU21/SV014 (TREA40/CE010; EQUI4/EU014 Units 1&2 Fly Ash Separator). [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 3 43

Visible Emissions: The Permittee shall check the following stacks for any visible emissions once each day of opera on during daylight hours:

1. STRU23/SV017 (TREA36/CE015; EQUI98/EU017 Fly Ash Silo A & EQUI122 Fly Ash Silo A Loadout ‐ Spout with Vented Annular Hood),2. STRU22/SV018 (TREA2/CE044; EQUI97/EU018 Fly Ash Silo A Loadout ‐ Truck Bay). [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 44


1. STRU40/SV035 (TREA46/CE045; EQUI111/EU035 Rail Unloading), 2. STRU41/SV042 (TREA46/CE045; EQUI111/EU035 Rail Unloading), 3. STRU42/SV036 (TREA47/CE046; EQUI112/EU036 Lowering Well & EQUI113/EU047 Coal Silo), 4. STRU43/SV043 (TREA47/CE046; EQUI112/EU036 Lowering Well & EQUI113/EU047 Coal Silo), 5. STRU44/SV037 (TREA48/CE047; EQUI114/EU037 C16/C18 Transfer House), 6. STRU45/SV038 (TREA49/CE048; EQUI115/EU038 C9/C10 Transfer House), 7. STRU46/SV039 (TREA50/CE049; EQUI116/EU039 Dust Tank), 8. STRU47/SV040 (TREA51/CE050; EQUI117/EU040 Units 1, 2, 3 Bunkers), and 9. STRU48/SV041 (TREA52/CE051; EQUI118/EU041 Unit 4 Bunkers). [Minn. R. 7011.0080]

Subject

Item ID

Sequence

Number Requirement

COMG 3 45


1. STRU25/SV015 (TREA41/CE013; EQUI99/EU015 Unit 3 PAC Silo), 2. STRU26/SV019 (TREA1/CE016; EQUI5/EU019 Limestone Silo Bin Vent), 3. STRU27/SV020 (TREA42/CE017; EQUI6/EU020 Unit 3 Limestone Day Bin 1), 4. STRU28/SV021 (TREA43/CE018; EQUI7/EU021 Unit 3 Limestone Day Bin 2), 5. STRU1/SV024 (TREA23/CE032; EQUI86/EU024 Unit 4 Lime Silo), 6. STRU2/SV025 (TREA24/CE033; EQUI87/EU025 Unit 4 Lime Day Bin A), 7. STRU3/SV026 (TREA25/CE034; EQUI88/EU026 Unit 4 Lime Day Bin B), 8. STRU4/SV027 (TREA26/CE035; EQUI89/EU027 Unit 4 Lime Day Bin C), 9. STRU5/SV028 (TREA27/CE036; EQUI90/EU028 Unit 4 Lime Day Bin D), 10. STRU6/SV029 (TREA29/CE037; EQUI91/EU029 Unit 4 Lime Day Bin E ), 11. STRU7/SV030 (TREA30/CE038: EQUI120/EU030 Unit 4 Ac vated Carbon Silo), 12. STRU8/SV031 (TREA31/CE039; EQUI93/EU031 Fly Ash Silo B Bin Vent), 13. STRU9/SV032 (TREA32/CE040; EQUI94/EU032 Fly Ash Silo B Loadout ‐ Truck Bay). [Minn. R. 7007.0800, subp. 4, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 46

Recordkeeping of Visible Emissions Checks. The Permittee shall record the time and date of each visible emission inspection of the following fabric filter stacks, and whether or not any visible emissions were observed. 1. STRU18/SV011 (TREA37/CE007; EQUI1/EU011 Crusher House C‐8), 2. STRU19/SV012 (TREA38/CE008; EQUI102/EU012 Crusher House C‐14), 3. STRU20/SV013 (TREA39/CE009; EQUI3/EU013 Units 1&2 Fly Ash Silo), 4. STRU21/SV014 (TREA40/CE010; EQUI4/EU014 Units 1&2 Fly Ash Separator). [Minn. R. 7007.0800, subps. 4‐5]

COMG 3 47

Recordkeeping of Visible Emissions Checks. The Permittee shall record the time and date of each visible emission inspection of the following fabric filter stacks, and whether or not any visible emissions were observed.

1. STRU23/SV017 (TREA36/CE015; EQUI98/EU017 Fly Ash Silo A & EQUI122 Fly Ash Silo A Loadout ‐ Spout with Vented Annular Hood), 2. STRU22/SV018 (TREA2/CE044; EQUI97/EU018 Fly Ash Silo A Loadout ‐ Truck Bay). 3. STRU40/SV035 (TREA46/CE045; EQUI111/EU035 Rail Unloading), 4. STRU41/SV042 (TREA46/CE045; EQUI111/EU035 Rail Unloading), 5. STRU42/SV036 (TREA47/CE046; EQUI112/EU036 Lowering Well & EQUI113/EU047 Coal Silo), 6. STRU43/SV043 (TREA47/CE046; EQUI112/EU036 Lowering Well & EQUI113/EU047 Coal Silo), 7. STRU44/SV037 (TREA48/CE047; EQUI114/EU037 C16/C18 Transfer House), 8. STRU45/SV038 (TREA49/CE048; EQUI115/EU038 C9/C10 Transfer House), 9. STRU46/SV039 (TREA50/CE049; EQUI116/EU039 Dust Tank), 10. STRU47/SV040 (TREA51/CE050; EQUI117/EU040 Units 1, 2, 3 Bunkers), and 11. STRU48/SV041 (TREA52/CE051; EQUI118/EU041 Unit 4 Bunkers). [Minn. R. 7011.0080]

Subject

Item ID

Sequence

Number Requirement

COMG 3 48

Recordkeeping of Visible Emissions Checks. The Permittee shall record the time and date of each visible emission inspection of the following fabric filter stacks, and whether or not any visible emissions were observed.

1. STRU23/SV017 (TREA36/CE015; EQUI98/EU017 Fly Ash Silo A & EQUI122 Fly Ash Silo A Loadout ‐ Spout with Vented Annular Hood), 2. STRU22/SV018 (TREA2/CE044; EQUI97/EU018 Fly Ash Silo A Loadout ‐ Truck Bay). 3. STRU25/SV015 (TREA41/CE013; EQUI99/EU015 Unit 3 PAC Silo), 4. STRU26/SV019 (TREA1/CE016; EQUI5/EU019 Limestone Silo Bin Vent), 5. STRU27/SV020 (TREA42/CE017; EQUI6/EU020 Unit 3 Limestone Day Bin 1), 6. STRU28/SV021 (TREA43/CE018; EQUI7/EU021 Unit 3 Limestone Day Bin 2), 7. STRU1/SV024 (TREA23/CE032; EQUI86/EU024 Unit 4 Lime Silo), 8. STRU2/SV025 (TREA24/CE033; EQUI87/EU025 Unit 4 Lime Day Bin A), 9. STRU3/SV026 (TREA25/CE034; EQUI88/EU026 Unit 4 Lime Day Bin B), 10. STRU4/SV027 (TREA26/CE035; EQUI89/EU027 Unit 4 Lime Day Bin C), 11. STRU5/SV028 (TREA27/CE036; EQUI90/EU028 Unit 4 Lime Day Bin D), 12. STRU6/SV029 (TREA29/CE037; EQUI91/EU029 Unit 4 Lime Day Bin E ), 13. STRU7/SV030 (TREA30/CE038: EQUI120/EU030 Unit 4 Ac vated Carbon Silo), 14. STRU8/SV031 (TREA31/CE039; EQUI93/EU031 Fly Ash Silo B Bin Vent), 15. STRU9/SV032 (TREA32/CE040; EQUI94/EU032 Fly Ash Silo B Loadout ‐ Truck Bay). [Minn. R. 7007.0800, subps. 4‐5, Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

COMG 3 49

The Permittee shall operate and maintain each COMG3 fabric filter 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. 7007.0800, subp. 14]

COMG 3 50

Corrective Actions: The Permittee shall take corrective action as soon as possible if any of the following occur:

‐ visible emissions are observed from any COMG3 fabric filter; or‐ any COMG3 fabric filter or any of its components are found during the inspections to need repair.

Corrective actions shall eliminate visible emissions, 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 fabric filter. The Permittee shall keep a record of the type and date of any corrective action taken for each filter. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subps. 4‐5]

COMG 3 51

Periodic Inspections: At least once per calendar quarter, or more frequently as required by the manufacturing specifications, the Permittee shall inspect the COMG3 fabric filter control equipment components. The Permittee shall maintain a written record of these inspections. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subps. 4‐5]

COMG 3 52

Annual Hood Evaluation: The Permittee shall measure and record at least once every 12 months the fan rotation speed, fan power draw, or face velocity of each hood, or other comparable air flow indication method for the following fabric filters:

1. TREA36/CE015 (EQUI122 Fly Ash Silo A Loadout ‐ Spout with Vented Annular Hood), and 2. TREA2/CE044 (EQUI97/EU018 Fly Ash Silo A Loadout ‐ Truck Bay).

The Permi ee shall maintain a copy of the annual evalua on on site.

The TREA36 hood evaluation is conducted only for the purposes of determining the TREA36 capture efficiency for EQUI122 (Fly Ash Silo A Loadout ‐ Spout) emissions captured by the EQUI122 loadout annular sleeve/hood (that encompasses the spout and is vented to and controlled by TREA36). TREA36 also controls emissions from EQUI98/EU017 (Fly Ash Silo A) which is a totally enclosed process and not subject to the annual hood evaluation requirement. [Minn. R. 7011.0072, subp. 4]

Subject

Item ID

Sequence

Number Requirement

COMG 4 1

COMG4 contains common Continuous Opacity Monitoring System (COMS) requirements from 40 CFR pts. 60 and 75, and Minn. R. ch. 7017. Additional monitoring requirements may also apply to the Facility, and it is the responsibility of the Facility to meet all applicable requirements. [Minn. R. 7007.0800, subp. 4(A), Minn. R. 7017.1020]

COMG 4 2

Continuous Opacity Monitoring: The Permittee shall use a COMS to measure opacity from EQUI82/EU001, EQUI83/EU002, EQUI85/EU004, and EQUI100/EU003. [40 CFR 75.10(a)]

COMG 4 3

Continuous Opacity Monitoring ‐ The Permittee shall install and operate: 1. EQUI29/MR020 to continuously monitor opacity emissions from EQUI82/EU001.

2. EQUI30/MR021 to continuously monitor opacity emissions from EQUI83/EU002.

3. EQUI28/MR027 to continuously monitor opacity emissions from EQUI100/EU003.

4. EQUI34/MR040 to continuously monitor opacity emissions from EQUI85/EU004. [Minn. R. 7017.1006]

COMG 4 4

For EQUI85 only, the Permittee shall calibrate, maintain, and operate a COMS for measuring opacity. However, a COMS is not required under 40 CFR pt. 60, subp. D if the Permittee uses EQUI108 (PM CEMS) to measure PM. [40 CFR 60.45(a) & (b)(5)]

COMG 4 5

Subp. 1. Continuous Operation: COMS (EQUI28, EQUI29, and EQUI30 for opacity monitoring of EQUI100, EQUI82, and EQUI83, respectively) 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 COMS must not be bypassed except in emergencies where failure to bypass would endanger human health, safety, or plant equipment. Monitor downtime is a violation of Minn. R. 7017.1090, subp. 1, except for reasonable periods of monitor downtime listed in Minn. R. 7017.1090, subp. 2. [Minn. R. 7017.1090, subp. 1&2]

COMG 4 6

Except for system breakdowns, repairs, calibration checks, and zero and span adjustments required under 40 CFR Section 60.13(d), EQUI34 (the EQUI85 COMS) shall be in continuous operation and shall complete a minimum of one cycle of sampling and analyzing for each successive 10‐second period and one cycle of data recording for each successive 6‐minute period. [40 CFR 60.13(e)]

COMG 4 7

Monitoring Data: Each continuous opacity monitoring system shall complete a minimum of one cycle of sampling and analyzing for each successive 10‐sec period and one cycle of data recording for each successive 6‐min period. Reduce all opacity data to 6‐min averages. [40 CFR 75.10(d)(2)]

COMG 4 8

COMS Recertification Test: due 90 days after any change which invalidates the monitor's certification status according to Minn. R. 7017.1050, subp. 2. [Minn. R. 7017.1050, subp. 5]

COMG 4 9

COMS Recertification Test: Each required recertification test shall be completed according to the requirements at 40 CFR Section 75.20(b). [40 CFR 75.20(b)]

COMG 4 10

QC Program: The Permittee must conduct quality assurance and quality control as specified in Procedure 3 ‐ Quality Assurance Requirements for Continuous Opacity Monitoring Systems at Stationary Sources, 40 CFR Pt. 60, Appendix F. [Minn. R. 7017.1215]

COMG 4 11

COMS Daily Calibration Drift Test: The Permittee shall conduct daily instrument zero and upscale drift checks according to Procedure 3, section 10.1 of 40 CFR Pt. 60, Appendix F on each COMG4 COMS. [Minn. R. 7017.1215]

COMG 4 12

The Permittee shall perform zero alignment as described in Procedure 3, section 10.3 of 40 CFR Pt. 60, Appendix F. [Minn. R. 7017.1215]

COMG 4 13

COMS QA/QC: The Permittee shall operate, calibrate, and maintain each COMS used under the Acid Rain Program according to the procedures specified for State Implementation Plans, pursuant to pt. 51, Appendix M. [40 CFR 75.21(b)]

Subject

Item ID

Sequence

Number Requirement

COMG 4 14

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 contain all information required by 40 CFR Section 75.57. Records shall be kept at the source. [40 CFR 75.57, Minn. R. 7017.1130]

COMG 4 15

Quarterly Reports: Electronically report the data and information described in 40 CFR Section 75.64(a), (b), and (c) to the Administrator quarterly. Submit the data and information according to the requirements of Section 75.64. [40 CFR 75.64]

COMG 4 16

COMS Calibration Error Audit Results Summary: due 30 days after end of each calendar quarter in which the COMS calibration error audit was completed. [Minn. R. 7017.1220]

COMG 6 1

COMG6 contains common Continuous Emissions (including volumetric gas flow) Monitoring System (CEMS) requirements from 40 CFR pts. 60 and 75, and Minn. R. ch. 7017. Additional monitoring requirements may also apply to the Facility, and it is the responsibility of the Facility to meet all applicable requirements. [Minn. R. 7007.0800, subp. 4(A), Minn. R. 7017.1020]

COMG 6 2

Continuous Emissions Monitoring: The Permittee shall use CEMS to measure all SO2, NOx, and CO2 emissions from EQUI82/EU001, EQUI83/EU002, EQUI100/EU003, and EQUI85/EU004.

The Permittee shall measure SO2 emissions in parts per million and pounds per hour, NOx emissions in parts per million and pounds per million Btu heat input, and CO2 emissions in parts per million or percent, and tons per hour, in accordance with 40 CFR Section 75.10. The Permittee shall use flow monitors to measure volumetric gas flow rate (in standard cubic feet per hour) from EQUI82, EQUI83, EQUI100, and EQUI85. [40 CFR 75.10(a)]

COMG 6 3

Continuous Emissions Monitoring:

The Permittee shall install and operate EQUI36/MR028, EQUI40/MR032, EQUI44/MR036, and EQUI53/MR042 to continuously monitor SO2 emissions from EQUI82/EU001, EQUI83/EU002, EQUI100/EU003, and EQUI85/EU004, respectively.

The Permittee shall install and operate EQUI37/MR029, EQUI41/MR033, EQUI45/MR037, and EQUI54/MR043 to continuously monitor NOx emissions from EQUI82/EU001, EQUI83/EU002, EQUI100/EU003, and EQUI85/EU004, respectively.

The Permittee shall install and operate EQUI38/MR030, EQUI42/MR034, EQUI50/MR038, and EQUI55/MR044 to continuously monitor CO2 emissions from EQUI82/EU001, EQUI83/EU002, EQUI100/EU003, and EQUI85/EU004, respectively.

The Permittee shall install and operate EQUI39/MR031, EQUI43/MR035, EQUI51/MR039, and EQUI35/MR041 to continuously monitor flow from EQUI82/EU001, EQUI83/EU002, EQUI100/EU003, and EQUI85/EU004, respectively. [Minn. R. 7017.1006]

COMG 6 4

For EQUI85 only, the Permittee shall calibrate, maintain, and operate a CEMS for measuring SO2 emissions, NOx emissions, and either oxygen (O2) or carbon dioxide (CO2). [40 CFR 60.45(a)]

Subject

Item ID

Sequence

Number Requirement

COMG 6 5

Subp. 1. Continuous Operation: The Permittee shall continuously operate the following CEMS to measure SO2, NOx, and CO2, and flow monitors to measure exhaust gas flow rate as follows:

1. SO2 CEMS (EQUI36, EQUI40, EQUI44, and EQUI53); 2. NOx CEMS (EQUI37, EQUI41, EQUI45, and EQUI54) 3. CO2 CEMS (EQUI38, EQUI42, EQUI50, and EQUI55) 4. Flow monitors (EQUI39, EQUI43, EQUI51, and EQUI35).

CEMS and flow data must be 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. CEMS and flow monitors must not be bypassed except in emergencies where failure to bypass would endanger human health, safety, or plant equipment.

Monitor downtime is a violation of Minn. R. 7017.1090, subp. 1, except for reasonable periods of monitor downtime listed in Minn. R. 7017.1090, subp. 2. [Minn. R. 7017.1090, subp. 1&2]

COMG 6 7

Except for system breakdowns, repairs, calibration checks, and zero and span adjustments required under 40 CFR Section 60.13(d), EQUI53 (EQUI85 SO2 CEMS) and EQUI54 (EQUI85 NOx CEMS) shall be in continuous operation and shall complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15‐minute period. [40 CFR 60.13(e)]

COMG 6 8

Subp. 1. Data Points: All data points collected by a CEMS shall be used to calculate individual hourly emission averages unless another applicable requirement requires more frequent averaging.

Subp. 2. In order for an hour of data to be considered valid, it must contain the following minimum number of data points: A. four data points, equally spaced, if the emission unit operated during the en re hour;B. two data points, at least 15 minutes apart, during periods of monitor calibra on or rou ne maintenance;

C. one data point if the emission unit operated for 15 minutes or less during the hour.

Subp. 3. Data reduction procedures. Monitoring data shall be recorded in the same unit of measurement and averaging period for each of the facility's emission standards. [Minn. R. 7017.1160, subps. 1‐3]

COMG 6 9

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 40 CFR pt. 75, or backups of data from the data acquisition and handling system, or recertification, pursuant to 40 CFR Section 75.20. The Permittee 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 6 10

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 6 11

Daily Calibration Error (CE) Test: Conduct daily CE testing on all CEMS required by the Acid Rain Program, in accordance with 40 CFR pt. 75, Appendix B. [40 CFR pt. 75, App. B, Section 2.1]

COMG 6 12

CEMS Recertification Test: Each required recertification test shall be completed according to the requirements at 40 CFR Section 75.20(b). [40 CFR 75.20(b)]

COMG 6 13 Relative Accuracy Test Audit (RATA) Notification: due 30 days before CEMS RATA. [Minn. R. 7017.1180, subp. 2]

COMG 6 14

RATA Results Summary: due 30 days after end of each calendar quarter in which the RATA was conducted. Submit the summary on a form approved by the commissioner. [Minn. R. 7017.1180, subp. 3]

Subject

Item ID

Sequence

Number Requirement

COMG 6 15

Linearity Check Results Summary: due 30 days after end of each calendar quarter in which a linearity check was conducted. Submit the summary on a form approved by the commissioner. [Minn. R. 7017.1180, subp. 4]

COMG 6 16

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 contain all information required by 40 CFR Section 75.57. Records shall be kept at the source. [40 CFR 75.57, Minn. R. 7017.1130]

COMG 6 17

Quarterly Reports: Electronically report the data and information described in 40 CFR Section 75.64(a), (b), and (c) to the Administrator quarterly. Submit the data and information according to the requirements of Section 75.64. [40 CFR 75.64]

COMG 7 1

The Permittee shall comply with the requirements from 40 CFR pt. 63, subp. UUUUU prescribed in this permit. For any revision(s) to subp. UUUUU requirement(s) not yet incorporated into this permit, the Permittee shall comply with the revised subp. UUUUU requirement(s) in place of such obsolete requirement(s) in this permit. The Permittee shall submit an application in accordance with the requirements of Minn. R. 7007.1150 through Minn. R. 7007.1500 within nine months after promulgation of any subp. UUUUU revision that renders any subp. UUUUU permit requirement obsolete, to incorporate appropriate changes to the subp. UUUUU requirements in this permit (refer to requirement 5.1.31).

NOTE: Part 63, subp. UUUUU Hydrogen Chloride (HCl) and alternate Sulfur Dioxide (SO2) limits are repeated in COMG1 (GP004 SO2 Limits). [Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 7 2

40 CFR PART 63, SUBPART UUUUU: The Permittee is subject to 40 CFR pt. 63, subp. UUUUU because it owns and operates EQUI82 (Boiler 1), EQUI83 (Boiler 2), EQUI100 (Boiler 3), and EQUI85 (Boiler 4) all of which are coal‐fired electric utility steam generating units (EUSGU or EGU) as defined in Section 63.10042. [40 CFR 63.10042, 40 CFR 63.9981, Minn. R. 7011.0563]

COMG 7 3

EQUI82 (Unit 1), EQUI83 (Unit 2), EQUI100 (Unit 3), and EQUI85 (Unit 4) are each an EGU (as defined in Section 63.10042), and collectively are the affected source under pt. 63, subp. UUUUU. [40 CFR 63.9982(a)(1), Minn. R. 7011.0563]

COMG 7 4

For EQUI82, EQUI83, and EQUI100, the Permittee shall comply with 40 CFR pt. 63, subp. UUUUU no later than April 16, 2015. For EQUI85, the Permittee shall comply with 40 CFR pt. 63, subp. UUUUU no later than April 16, 2016 (as approved by the agency January 28, 2013 EQUI85 one‐year compliance date extension letter). [40 CFR 63.9982(b), Minn. R. 7011.0563]

COMG 7 5

EQUI82 (Boiler 1), EQUI83 (Boiler 2), EQUI100 (Boiler 3), and EQUI85 (Boiler 4) are existing EGUs because they weren't constructed or reconstructed after May 3, 2011. [40 CFR 63.9982(d), Minn. R. 7011.0563]

COMG 7 6

The Permittee shall meet the notification requirements in Section 63.10030 according to the schedule in Section 63.10030 and in pt. 63, subp. A. Some of the notifications must be submitted before the Permittee is required to comply with the emission limits and work practice standards in pt. 63, subp. UUUUU. [40 CFR 63.9984(c), Minn. R. 7011.0563]

COMG 7 7

The Permittee submitted a Notification of Compliance Status (NOCS) as required by 40 CFR Section 63.9(h) for EQUI82 (Boiler 1), EQUI83 (Boiler 2), EQUI100 (Boiler 3), and EQUI85 (Boiler 4). The NOCSs are included in this permit in Appendix H. The NOCSs contain the methods used by the Permittee to determine compliance with applicable pt. 63, subp. UUUUU emission limits, along with other required information. As required by 40 CFR Section 63.9(j), any change in the information already provided under Section 63.9 shall be provided to the Administrator in writing within 15 calendar days after the change. The Permittee shall also send a copy of the written notification required by 40 CFR Section 63.9(j), to the Minnesota Pollution Control Agency Commissioner within 15 calendar days after the change. [40 CFR 63.9(j), Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7019.0100]

COMG 7 8

The Permittee shall demonstrate that compliance has been achieved, by conducting the required performance tests and other activities, no later than 180 days after April 16, 2015. The Permittee conducted the required tests and submitted a Notice of Compliance Status to EPA on October 13, 2015. [40 CFR 63.9984(f), Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

COMG 7 9

EQUI82 (Boiler 1), EQUI83 (Boiler 2), EQUI100 (Boiler 3), and EQUI85 (Boiler 4) are coal‐fired EGUs in the subcategory of EGUs designed for coal with a heating value greater than or equal to 8,300 Btu/lb. [40 CFR 63.9990(a)(1), Minn. R. 7011.0563]

COMG 7 10

The Permittee shall at all times meet the following requirements: (i) Each emission limit and work practice standard in pt. 63, subp. UUUUU Tables 2 and 3, respectively, that applies to EQUI82 (Boiler 1), EQUI83 (Boiler 2), EQUI100 (Boiler 3), and EQUI85 (Boiler 4), except as provided under Section 63.10009, and (ii) Each operating limit in pt. 63, subp. UUUUU Table 4 that applies to EQUI82, EQUI83, EQUI100, and EQUI85. [40 CFR 63.9991(a), Minn. R. 7011.0563]

COMG 7 11

(b) As provided in Section 63.6(g), the Administrator may approve use of an alternative to the work practice standards in Sec on 63.9991.

(c) The Permi ee may use the alternate SO2 limit in Table 2 to subpart UUUUU only if the EGU: (1) Has a system using wet or dry flue gas desulfurization technology and an SO2 continuous emissions monitoring system (CEMS) installed on the EGU; and (2) At all times, the Permittee operates the wet or dry flue gas desulfurization technology and the SO2 CEMS installed on the EGU consistent with Sec on 63.10000(b).

EQUI100 (Boiler 3) is equipped with wet flue gas desulfurization technology (TREA10) with EQUI44 (a SO2 CEMS) installed on the EQUI100 stack (STRU13); EQUI85 (Boiler 4) is equipped with semi‐dry flue gas desulfurization technology (TREA21) with EQUI53 (a SO2 CEMS) installed on the EQUI85 stack (STRU14)).

The Permittee's April 2017 sight‐specific monitoring plan indicates the Permittee has elected to comply with the alternate SO2 limit for EQUI85, and comply with the HCl limit for EQUI100. [40 CFR 63.9991(b)&(c), Minn. R. 7011.0563]

COMG 7 12

The Permittee shall comply with the pt. 63, subp. UUUUU emission limits and operating limits. These limits apply at all times except during periods of startup and shutdown; however, the Permittee is required to meet the work practice requirements, items 3 and 4, in Table 3 of pt. 63, subp. UUUUU during periods of startup or shutdown. [40 CFR 63.10000(a), Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

COMG 7 13

The Permittee shall limit Filterable Particulate Matter <= 0.03 pounds per million Btu heat input from EQUI82, EQUI83, EQUI100, and EQUI85 or, the Permittee shall limit Filterable Total Particulate Matter <= 0.30 pounds/megawa ‐hour from EQUI82, EQUI83, EQUI100, and EQUI85. In lieu of these filterable total PM limits, the Permittee may elect to limit Total non‐Hg HAP metals to <=5.0 E‐05 lb/MMBtu from EQUI82, EQUI83, EQUI100, and EQUI85, or <=0.5 lb/GWh from EQUI82, EQUI83, EQUI100, and EQUI85, OR, The Permi ee may elect to limit individual HAP metals from EQUI82, EQUI83, EQUI100, and EQUI85 as follows: An mony (Sb): <=8.0E‐1 lb/TBtu or <=8.0E‐3 lb/GWh Arsenic (As): <=1.1E0 lb/TBtu or <=2.0E‐2 lb/GWh Beryllium (Be): <=2.0E‐1 lb/TBtu or <=2.0E‐3 lb/GWh Cadmium (Cd): <=3.0E‐1 lb/TBtu or <=3.0E‐3 lb/GWh Chromium (Cr): <=2.8E0 lb/TBtu or <=3.0E‐2 lb/GWh Cobalt (Co): <=8.0E‐1 lb/TBtu or <=8.0E‐3 lb/GWh Lead (Pb): <=1.2E0 lb/TBtu or <=2.0E‐2 lb/GWh Manganese (Mn): <=4.0E0 lb/TBtu or <=5.0E‐2 lb/GWh Nickel (Ni): <=3.5E0 lb/TBtu or <=4.0E‐2 lb/GWh Selenium (Se): <=5.0E0 lb/TBtu or <=6.0E‐2 lb/GWh. [40 CFR pt. 63, subp. UUUUU (Table 2), Minn. R. 7011.0563]

COMG 7 15

The Permittee shall limit EQUI82, EQUI83, EQUI100, and EQUI85 Hydrogen Chloride <= 0.002 pounds per million Btu heat input, or the Permittee shall limit EQUI82, EQUI83, EQUI100, and EQUI85 Hydrogen Chloride <= 0.02 pounds/megawa ‐hour;

OR

The Permittee shall limit EQUI82, EQUI83, EQUI100, and EQUI85 Sulfur Dioxide <= 0.20 pounds per million Btu, or the Permittee shall limit EQUI82, EQUI83, EQUI100, and EQUI85 Sulfur Dioxide <= 1.50 pounds per megawatt‐hour.

The Permi ee has the op on of complying with the either the: 1. Heat input‐based Hydrogen Chloride limit, or 2. Electrical output‐based Hydrogen Chloride limit, or 3. Heat input‐based Sulfur Dioxide limit, or 4. Electrical output‐based Sulfur Dioxide limit. The Permittee has elected to comply with the Hydrogen Chloride heat input‐based limit for EQUI82, EQUI83, and EQUI100, and with the Sulfur Dioxide heat input‐based limit for EQUI85 as described in the April 1, 2017 version of the Site Specific Monitoring Plan submitted pursuant to Section 63.10000(d). This requirement is repeated in COMG1 (SO2 limits). [40 CFR pt. 63, subp. UUUUU (Table 2), Minn. R. 7011.0563]

COMG 7 16

The Permittee shall limit Mercury <= 1.2 pounds per trillion Btu from EQUI82, EQUI83, EQUI100, and EQUI85, or Mercury <= 0.013 pound per gigawatt‐hour from EQUI82, EQUI83, EQUI100, and EQUI85. [40 CFR pt. 63, subp. UUUUU (Table 2), Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

COMG 7 17

Work Practice Standards (pt. 63, subp. UUUUU Table 3).1. The Permittee shall conduct a tune‐up of each EGU burner and combustion controls at least each 36 calendar months, or each 48 calendar months if neural network combustion optimization software is employed, as specified in Section 63.10021(e).3. A coal‐fired EGU during startup: The Permittee has the option of complying using either of the following work practice standards.a.(1) If the Permittee chooses to comply using paragraph (1) of the definition of "startup" in Section 63.10042, the Permittee must operate all Continuous Monitoring Systems (CMS) during startup. Startup means either the first‐ever firing of fuel in a boiler for the purpose of producing electricity, or the firing of fuel in a boiler after a shutdown event for any purpose. Startup ends when any of the steam from the boiler is used to generate electricity for sale over the grid or for any other purpose (including on site use). For startup of a unit, the Permittee must use clean fuels as defined in Section 63.10042 for ignition. Once the Permittee converts to firing coal the Permittee must engage all of the applicable control technologies except dry scrubber and SCR. The Permittee must start the dry scrubber and SCR systems, if present, appropriately to comply with relevant standards applicable during normal operation. The Permittee must comply with all applicable emissions limits at all times except for periods that meet the applicable definitions of startup and shutdown in pt. 63, subp. UUUUU. The Permittee must keep records during startup periods. The Permittee must provide reports concerning activities and startup periods, as specified in Section 63.10011(g) and Section 63.10021(h) and (i). [40 CFR pt. 63, subp. UUUUU (Table 3), Minn. R. 7011.0563]

COMG 7 17

Work Practice Standards (cont.).a.(2) If the Permittee chooses to comply using paragraph (2) of the definition of "startup" in Section 63.10042, the Permittee must operate all CMS during startup. The Permittee must also collect appropriate data, and must calculate the pollutant emission rate for each hour of startup. For startup of an EGU, the Permittee must use one or a combination of the clean fuels defined in Section 63.10042 to the maximum extent possible, taking into account considerations such as boiler or control device integrity, throughout the startup period. The Permittee must have sufficient clean fuel capacity to engage and operate its PM control device within one hour of adding coal to the unit. The Permittee must meet the startup period work practice requirements as identified in Section 63.10020(e). Once the Permittee starts firing coal, the Permittee must vent emissions to the main stack(s). The Permittee must comply with the applicable emission limits beginning with the hour after startup ends. The Permittee must engage and operate its particulate matter control(s) within 1 hour of first firing of coal. The Permittee must start all other applicable control devices as expeditiously as possible, considering safety and manufacturer/supplier recommendations, but, in any case, when necessary to comply with other standards made applicable to the EGU by a permit limit or a rule other than subp. UUUUU that require operation of the control devices.c. If the Permittee chooses to use just one set of sorbent traps to demonstrate compliance with the applicable Hg emission limit, the Permittee must comply with the limit at all times; otherwise, the Permittee must comply with the applicable emission limit at all times except for startup and shutdown periods.d. The Permittee must collect monitoring data during startup periods, as specified in Section 63.10020(a) and (e). The Permittee must keep records during startup periods, as provided in Sections 63.10032 and 63.10021(h). The Permittee must provide reports concerning activities and startup periods, as specified in Sections 63.10011(g), 63.10021(i), and 63.10031. [40 CFR pt. 63, subp. UUUUU (Table 3), Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

COMG 7 18

Work Prac ce Standards (cont.).4. A coal‐fired EGU during shutdown: The Permittee must operate all CMS during shutdown. The Permittee must also collect appropriate data, and the Permittee must calculate the pollutant emission rate for each hour of shutdown for those pollutants for which a CMS is used. While firing coal during shutdown, the Permittee you must vent emissions to the main stack(s) and operate all applicable control devices and continue to operate those control devices after the cessation of coal being fed into the EGU and for as long as possible thereafter considering operational and safety concerns. In any case, the Permittee must operate its controls when necessary to comply with other standards made applicable to the EGU by a permit limit or a rule other than subp. UUUUU and that require operation of the control devices. If, in addition to the fuel used prior to initiation of shutdown, another fuel must be used to support the shutdown process, that additional fuel must be one or a combination of the clean fuels defined in Section 63.10042 and must be used to the maximum extent possible, taking into account considerations such as not compromising boiler or control device integrity. The Permittee must comply with all applicable emission limits at all times except during startup periods and shutdown periods at which time you must meet this work practice. The Permittee must collect monitoring data during shutdown periods, as specified in Section 63.10020(a). The Permittee must keep records during shutdown periods, as provided in Sections 63.10032 and 63.10021(h). Any fraction of an hour in which shutdown occurs constitutes a full hour of shutdown. The Permittee must provide reports concerning activities and shutdown periods, as specified in Sections 63.10011(g), 63.10021(i), and 63.10031. [40 CFR pt. 63, subp. UUUUU (Table 3), Minn. R. 7011.0563]

COMG 7 19

At all times the Permittee shall operate and maintain EQUI82, EQUI83, EQUI100, and EQUI85, 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 EPA 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 63.10000(b), Minn. R. 7011.0563]

COMG 7 20

Initial performance testing is required for all pollutants to demonstrate compliance with the applicable emission limits. [40 CFR 63.10000(c)(1), Minn. R. 7011.0563]

COMG 7 21

The Permittee may conduct the initial performance testing in accordance with Section 63.10005(h), to determine whether EQUI82, EQUI83, EQUI100, and/or EQUI85 qualify as a low emitting EGU (LEE) for one or more applicable emissions limits. [40 CFR 63.10000(c)(1)(i), Minn. R. 7011.0563]

COMG 7 22

For EQUI82, EQUI83, EQUI100, and/or EQUI85 to continue qualifying as an LEE for Hg emissions limits, the Permittee shall conduct a 30‐day performance test using Method 30B at least once every 12 calendar months to demonstrate continued LEE status. [40 CFR 63.10000(c)(1)(ii), Minn. R. 7011.0563]

COMG 7 23

For EQUI82, EQUI83, EQUI100, and/or EQUI85 to continue qualifying as an LEE for any other applicable emissions limits, the Permittee must conduct a performance test at least once every 36 calendar months to demonstrate continued LEE status. [40 CFR 63.10000(c)(1)(iii), Minn. R. 7011.0563]

COMG 7 24

If EQUI82, EQUI83, EQUI100, and/or EQUI85 do not qualify as a LEE for total non‐mercury HAP metals, individual non‐mercury HAP metals, or filterable particulate matter (PM), the Permittee must demonstrate compliance through an initial performance test and must monitor continuous performance through either use of a particulate matter continuous parametric monitoring system (PM CPMS), a PM CEMS, or, compliance performance tes ng repeated quarterly.

Note: The Permittee has installed PM CEMS EQUI107 and EQUI108, on STRU13 (EQUI82, EQUI83, and EQUI100 common stack) and on STRU4 (EQUI85 stack), respectively. [40 CFR 63.10000(c)(1)(iv), Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

COMG 7 25

If EQUI82, EQUI83, EQUI100, and/or EQUI85 do not qualify as a LEE for hydrogen chloride (HCl), the Permittee may demonstrate initial and continuous compliance through use of an HCl CEMS, installed and operated in accordance with Appendix B to pt. 63, subp. UUUUU. As an alternative to HCl CEMS, the Permittee may demonstrate initial and continuous compliance by conducting an initial and periodic quarterly performance stack test for HCl. The Permittee may apply a second alternative to HCl CEMS for EQUI100/Unit 3 and EQUI85/Unit 4 (because flue gas desulfurization is employed in these units), by installing and operating a sulfur dioxide (SO2) CEMS installed and operated in accordance with part 75 to demonstrate compliance with the applicable SO2 emissions limit. [40 CFR 63.10000(c)(1)(v), Minn. R. 7011.0563]

COMG 7 26

If EQUI82, EQUI83, EQUI100, and/or EQUI85 do not qualify as a LEE for Hg, the Permittee must demonstrate initial and continuous compliance through use of a Hg CEMS or a sorbent trap monitoring system, in accordance with Appendix A of pt. 63, subp. UUUUU.

(A) The Permittee may choose to use separate sorbent trap monitoring systems to comply with pt. 63, subp. UUUUU: One sorbent trap monitoring system to demonstrate compliance with the numeric mercury emissions limit during periods other than startup or shutdown and the other sorbent trap monitoring system to report average mercury concentration during startup periods or shutdown periods.

(B) The Permittee may choose to use one sorbent trap monitoring system to demonstrate compliance with the mercury emissions limit at all times (including startup periods and shutdown periods) and to report average mercury concentration. The Permittee must follow the startup or shutdown requirements that follow and as given in Table 3 to pt. 63, subp. UUUUU for EQUI82, EQUI83, EQUI100, and EQUI85.

Note: The Permittee has installed the following mercury monitoring systems to meet the requirements of 40 CFR pt. 63, subp. UUUUU:

i. EQUI106 Sorbent Trap on STRU13 (common stack for EQUI82 (Unit 1), EQUI83 (Unit 2), and EQUI100 (Unit 3));

ii. EQUI110 CEMS on EQUI85/STRU14 (Unit 4).

The Permittee shall use either EQUI106 or EQUI109 to monitor EQUI100 mercury emissions before and after EQUI82 and EQUI83 shutdown. Refer to Subject Item EQUI106 for additional requirements when using EQUI106 as the EQUI100 mercury monitoring. [40 CFR 63.10000(c)(1)(vi), Minn. R. 7011.0563]

COMG 7 27

If the Permittee demonstrates compliance with any applicable emissions limit through use of a continuous monitoring system (CMS), where a CMS includes a continuous parameter monitoring system (CPMS) as well as a continuous emissions monitoring system (CEMS), the Permittee must develop a site‐specific monitoring plan and submit this site‐specific monitoring plan (SSMP), if requested, at least 60 days before the initial performance evaluation (where applicable) of the CMS. This requirement also applies if the Permittee petitions the Administrator for alternative monitoring parameters under Section 63.8(f). This requirement to develop and submit a SSMP does not apply to affected sources with existing monitoring plans that apply to CEMS and CPMS prepared under Appendix B to pts. 60 or 75, and that meet the requirements of Section 63.10010. Using the process described in Section 63.8(f)(4), the Permittee may request approval of monitoring system quality assurance and quality control procedures alternative to those specified in this paragraph of Section 63.10000 and, if approved, include those in the Permittee's SSMP. The SSMP must address the provisions in paragraphs 63.10000(d)(2) through (5). [40 CFR 63.10000(d)(1), Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

COMG 7 27

Continuous Monitoring System (CMS) (cont.)The Permittee's April 2017 SSMP states the Permittee will use:

1. A mercury sorbent trap (EQUI106) to demonstrate STRU13 (EQUI82, EQUI83, and EQUI100 common stack) 30‐boiler‐operating‐day rolling average mercury emissions compliance, 2. A mercury CEMS (EQUI110) to demonstrate EQUI85 30‐boiler‐operating‐day rolling average mercury emissions compliance, 3. A filterable particulate matter CEMS (EQUI107) to demonstrate STRU13 30‐boiler‐operating‐day rolling average filterable particulate matter compliance, 4. A filter particulate matter CEMS (EQUI108) to demonstrate EQUI85 30‐boiler‐operating‐day rolling average filterable particulate matter compliance, 5. A sulfur dioxide CEMS (EQUI53) to demonstrate EQUI85 30‐boiler‐operating‐day rolling average sulfur dioxide emissions compliance (an alternative to determining hydrogen chloride compliance permitted under pt. 63, subp. UUUUU Table 2), and 6. Hydrogen chloride stack testing on STRU13 to demonstrate STRU13 compliance for hydrogen chloride emissions. [40 CFR 63.10000(d)(1), Minn. R. 7011.0563]

COMG 7 28

The site‐specific monitoring plan shall include the information specified in paragraphs 63.10000(d)(5)(i) through (d)(5)(vii). Alternatively, the requirements of paragraphs 63.10000(d)(5)(i) through (d)(5)(vii) are considered to be met for a particular CMS or sorbent trap monitoring system if: (i) The CMS or sorbent trap monitoring system is installed, certified, maintained, operated, and quality‐assured either according to pt., or Appendix A or B to pt. 63, subp. UUUUU; and (ii) The recordkeeping and reporting requirements of pt. 75, or Appendix A or B to pt. 63, subp. UUUUU that pertain to the CMS are met. [40 CFR 63.10000(d)(2), Minn. R. 7011.0563]

COMG 7 29

(3) If requested by the Administrator, the Permittee must submit the monitoring plan (or relevant portion of the plan) at least 60 days before the initial performance evaluation of a particular CMS, except where the CMS has already undergone a performance evaluation that meets the requirements of Section 63.10010 (e.g., if the CMS was previously certified under another program). (4) The Permittee must operate and maintain the CMS according to the site‐specific monitoring plan. [40 CFR 63.10000(d)(3)&(4), Minn. R. 7011.0563]

COMG 7 30

The provisions of the site‐specific monitoring plan must address the following items: (i) Installation of the CMS or sorbent trap monitoring system sampling probe or other interface at a measurement location relative to STRU13, EQUI100, and EQUI85 such that the measurement is representative of control of the exhaust emissions (e.g., on or downstream of the last control device). See Section 63.10010(a) for further details. For PM CPMS installations, follow the procedures in Section 63.10010(h). (ii) Performance and equipment specifications for the sample interface, the pollutant concentration or parametric signal analyzer, and the data collection and reduction systems. (iii) Schedule for conducting initial and periodic performance evaluations. (iv) Performance evaluation procedures and acceptance criteria (e.g., calibrations), including the quality control program in accordance with the general requirements of Section 63.8(d). (v) On‐going operation and maintenance procedures, in accordance with the general requirements of Sections 63.8(c)(1)(ii), (c)(3), and (c)(4)(ii). (vi) Conditions that define a CMS that is out of control consistent with Section 63.8(c)(7)(i) and for responding to out of control periods consistent with Sections 63.8(c)(7)(ii) and (c)(8). (vii) On‐going recordkeeping and reporting procedures, in accordance with the general requirements of Sections 63.10(c), (e)(1), and (e)(2)(i), or as specifically required under subp. UUUUU. [40 CFR 63.10000(d)(5), Minn. R. 7011.0563]

COMG 7 31

The Permittee must perform periodic tune‐ups of EQUI82, EQUI83, EQUI100, and EQUI85 according to Section 63.10021(e), as part of showing continuous compliance. [40 CFR 63.10000(e), Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

COMG 7 32

The Permittee is subject to the requirements of pt. 63, subp. UUUUU for at least 6 months following the last date EQUI82, EQUI83, EQUI100, and/or EQUI85 met the definition of an EGU subject to subp. UUUUU (e.g., 6 months after a cogeneration unit provided more than one third of its potential electrical output capacity and more than 25 megawatts electrical output to any power distribution system for sale). The Permittee may opt to remain subject to the provisions of subp. UUUUU beyond 6 months after the last date EQUI82, EQUI83, EQUI100, and/or EQUI85 met the definition of an EGU subject to subp. UUUUU, unless EQUI82, EQUI83, EQUI100, and/or EQUI85 is a solid waste incineration unit subject to standards under CAA section 129 (e.g., 40 CFR Part 60, Subpart CCCC (New Source Performance Standards (NSPS) for Commercial and Industrial Solid Waste Incineration Units, or Subpart DDDD (Emissions Guidelines (EG) for Existing Commercial and Industrial Solid Waste Incineration Units). Notwithstanding the provisions of subp. UUUUU, an EGU that starts combusting solid waste is immediately subject to standards under CAA section 129 and the EGU remains subject to those standards until the EGU no longer meets the definition of a solid waste incineration unit consistent with the provisions of the applicable CAA section 129 standards. [40 CFR 63.10000(f), Minn. R. 7011.0563]

COMG 7 33

Except as provided under Section 63.10000(n), if EQUI82, EQUI83, EQUI100, and/or EQUI85 no longer meets the definition of an EGU subject to subp. UUUUU the Permittee must be in compliance with any newly applicable standards on the date EQUI82, EQUI83, EQUI100, and/or EQUI85 is no longer subject to subp. UUUUU. The date EQUI82, EQUI83, EQUI100, and/or EQUI85 is no longer subject to subp. UUUUU is a date selected by the Permittee, that must be at least 6 months from the date that EQUI82, EQUI83, EQUI100, and/or EQUI85 last met the definition of an EGU subject to subp. UUUUU or the date EQUI82, EQUI83, EQUI100, and/or EQUI85 begins combusting solid waste, consistent with Section 63.9983(d). EQUI82, EQUI83, EQUI100, and EQUI85 must remain in compliance with subp. UUUUU until the date the Permittee selects to cease complying with subp. UUUUU or the date EQUI82, EQUI83, EQUI100, and/or EQUI85 begins combusting solid waste, whichever is earlier. [40 CFR 63.10000(g), Minn. R. 7011.0563]

COMG 7 34

(1) If the Permittee owns or operates an EGU subject to subp. UUUUU, and it has been at least 6 months since the EGU was operated in a manner that caused the EGU to meet the definition of an EGU subject to subp. UUUUU, the Permittee may, consistent with Section 63.10000(g), select the date on which the EGU will no longer be subject to subp. UUUUU. The Permittee must be in compliance with any newly applicable section 112 or 129 standards on the date selected by the Permittee.

(2) The Permittee must provide 30 days prior notice of the date the EGU will cease complying with subp. UUUUU. The notification must identify: (i) The Permittee's name, the location of the facility, the EGU(s) that will cease complying with subp. UUUUU, and the date of the notice; (ii) The currently applicable subcategory under pt. 63, subp. UUUUU, and any 40 CFR part 60, part 62, or part 63 subpart and subcategory that will be applicable after the Permittee ceases complying with subp. UUUUU; (iii) The date on which the Permittee became subject to subp. UUUUU; (iv) The date upon which the Permittee will cease complying with subp. UUUUU, consistent with Section 63.10000(g). [40 CFR 63.10000(i), Minn. R. 7011.0563]

COMG 7 35

On or before the date an EGU is subject to subp. UUUUU, the Permittee must install, certify, operate, maintain, and quality assure each monitoring system necessary for demonstrating compliance with the work practice standards for PM or non‐mercury HAP metals during startup periods and shutdown periods. The Permittee must collect, record, report, and maintain data obtained from these monitoring systems during startup periods and shutdown periods. [40 CFR 63.10000(l), Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

COMG 7 37

If the Permittee permanently converts any of the facility EGUs from coal or oil to natural gas or biomass after the applicable compliance date, as demonstrated by being subject to a permit provision or physical limitation (including retirement) that prevents the Permittee from operating in a manner that would subject the EGU to pt. 63, subp. UUUUU, the Permittee is no longer subject to pt. 63, subp. UUUUU, notwithstanding the coal or oil usage in the previous calendar years. The date on which the Permittee is no longer subject to subp. UUUUU is the date on which the Permittee converted any facility EGU to natural gas or biomass firing; it is also the date on which the Permittee must be in compliance with any newly applicable standards. [40 CFR 63.10000(n), Minn. R. 7011.0563]

COMG 7 38

(a) General requirements. For each COMG7 EGU, the Permittee must demonstrate initial compliance with each applicable emissions limit in Table 2 of subp. UUUUU through performance testing. Where two emissions limits are specified for a particular pollutant (e.g., a heat input‐based limit in lb/MMBtu and a gross output‐based limit in lb/MWh), the Permittee may demonstrate compliance with either emission limit. For a particular compliance demonstration, the Permittee may be required to conduct one or more of the following activities in conjunction with performance testing: collection of data, e.g., hourly gross output data (megawatts); establishment of operating limits according to Section 63.10011 and Tables 4 and 7 to subp. UUUUU; and CMS performance evaluations. In all cases, the Permittee must demonstrate initial compliance no later than the date in Section 63.10005(f) for tune‐up work practices for EQUI82, EQUI83, EQUI100, and EQUI85; and the date that compliance must be demonstrated, as given in Section 63.9984 for other requirements for EQUI82, EQUI83, EQUI100, and EQUI85. [40 CFR 63.10005(a), Minn. R. 7011.0563]

COMG 7 39

To demonstrate initial compliance with an applicable emissions limit in Table 2 to subp. UUUUU using stack testing, the initial performance test generally consists of three runs at specified process operating conditions using approved methods. If the Permittee is required to establish operating limits (see Section 63.10005(d) and Table 4 to subp. UUUUU), the Permittee must collect all applicable parametric data during the performance test period. Also, if Permittee chooses to comply with an electrical output‐based emission limit, Permittee must collect hourly electrical load data during the test period. [40 CFR 63.10005(a)(1), Minn. R. 7011.0563]

COMG 7 40

(2) To demonstrate initial compliance using either a CMS that measures HAP concentrations directly (i.e., an Hg, HCl, or HF CEMS, or a sorbent trap monitoring system) or an SO2 or PM CEMS, the initial performance test shall consist of 30‐ or, for certain coal‐fired existing EGUs that use emissions averaging for Hg, 90‐boiler operating days. If the CMS is certified prior to the compliance date (or, if applicable, the approved extended compliance date), the test shall begin with the first operating day on or after that date, except as otherwise provided in Section 63.10005(b). If the CMS is not certified prior to the compliance date, the test shall begin with the first operating day after certification testing is successfully completed. In all cases, the initial 30‐ or 90‐ operating day averaging period must be completed on or before the date that compliance must be demonstrated (i.e., 180 days a er the applicable compliance date).(i) The CMS performance test must demonstrate compliance with the applicable Hg, HCl, HF, PM, or SO2 emissions limit in Table 2 to subp. UUUUU. (ii) The Permittee must collect hourly data from auxiliary monitoring systems (i.e., stack gas flow rate, CO2, O2, or moisture, as applicable) during the performance test period, in order to convert the pollutant concentrations to units of the standard. If the Permittee chooses to comply with a gross output‐based emission limit, the Permittee must also collect hourly gross output data during the performance test period. [40 CFR 63.10005(a)(2), Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

COMG 7 41

(iii) For EQUI82, EQUI83, and EQUI100 which are a group of affected units that are in the same subcategory, are subject to the same emission standards, and share common stack STRU13, if the Permittee elects to demonstrate compliance by monitoring emissions at the common stack, startup and shutdown emissions (if any) that occur during the 30‐(or, if applicable, 90) boiler operating day performance test must either be excluded from or included in the compliance demonstra on as follows:(A) If either EQUI82, EQUI83, or EQUI100 either starts up or shuts down at a time when none of the other two common‐stack units is operating, the Permittee must exclude all pollutant emission rates measured during the startup or shutdown period, unless the Permittee is using a sorbent trap monitoring system to measure Hg emissions and has elected to include startup and shutdown emissions in the compliance demonstra ons;

(B) If EQUI82, EQUI83, and EQUI100 are all currently operating, and are operating in the startup or shutdown mode, the Permittee must exclude all pollutant emission rates measured during the startup or shutdown period, unless the Permittee is using a sorbent trap monitoring system to measure Hg emissions and has elected to include startup and shutdown emissions in the compliance demonstra ons; or(C) If either EQUI82, EQUI83, or EQUI100 starts up or shuts down at a time when another common‐stack unit (either EQUI82, EQUI83, or EQUI100) is operating, and the other unit is not in the startup or shutdown mode, the Permittee must include all pollutant emission rates measured during the startup or shutdown period in the compliance demonstra ons. Section 63.10005(a)(2)(iii) does not apply to EQUI85, and will no longer apply to EQUI100 upon permanent shutdown of EQUI82 and EQUI83 (which will occur on or before December 31, 2018). [40 CFR 63.10005(a)(2)(iii), Minn. R. 7011.0563]

COMG 7 42

Performance testing requirements. If the Permittee chooses to use performance testing to demonstrate initial compliance with the applicable emissions limits in Table 2 to subp. UUUUU for its EGUs, the Permittee must conduct the tests according to Section 63.10007 and Table 5 to subp. UUUUU. For the purposes of the initial compliance demonstration, the Permittee may use test data and results from a performance test conducted prior to the date on which compliance is required as specified in Section 63.9984, provided that the following condi ons are fully met:

(1) For a performance test based on stack test data, the test was conducted no more than 12 calendar months prior to the date on which compliance is required as specified in Sec on 63.9984;(2) For a performance test based on data from a certified CEMS or sorbent trap monitoring system, the test consists of all valid CMS data recorded in the 30 boiler opera ng days immediately preceding that date;(3) The performance test was conducted in accordance with all applicable requirements in Section 63.10007 and Table 5 to subp. UUUUU;(4) A record of all parameters needed to convert pollutant concentrations to units of the emission standard (e.g., stack flow rate, diluent gas concentrations, hourly gross outputs) is available for the entire performance test period; and(5) For each performance test based on stack test data, the Permittee certifies, and keeps documentation demonstrating, that the EGU configuration, control devices, and fuel(s) have remained consistent with condi ons since the prior performance test was conducted. 6) For performance stack test data that are collected prior to the date that compliance must be demonstrated and are used to demonstrate initial compliance with applicable emissions limits, the interval for subsequent stack tests begins on the date that compliance must be demonstrated. [40 CFR 63.10005(b), Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

COMG 7 43

(d) CMS requirements. If, for a particular emission or operating limit, the Permittee is required to (or elects to) demonstrate initial compliance using a continuous monitoring system, the CMS must pass a performance evaluation prior to the initial compliance demonstration. If a CMS has been previously certified under another state or federal program and is continuing to meet the on‐going quality‐assurance (QA) requirements of that program, then, provided that the certification and QA provisions of that program meet the applicable requirements of Sections 63.10010(b) through (h), an additional performance evaluation of the CMS is not required under subp. UUUUU.

(1) For EQUI82, EQUI83, EQUI100, and EQUI85, the Permittee may demonstrate initial compliance with the applicable SO2, HCl, or HF emissions limit in Table 2 to subp. UUUUU through use of an SO2, HCl, or HF CEMS installed and operated in accordance with part 75 or appendix B to subp. UUUUU, as applicable. The Permittee may also demonstrate compliance with a filterable PM emission limit in Table 2 to subp. UUUUU through use of a PM CEMS installed, certified, and operated in accordance with Section 63.10010(i). Initial compliance is achieved if the arithmetic average of 30‐boiler operating days of quality‐assured CEMS data, expressed in units of the standard (see Section 63.10007(e)), meets the applicable SO2, PM, HCl, or HF emissions limit in Table 2 to subp. UUUUU. Use Equation 19‐19 of Method 19 in appendix A‐7 to part 60 to calculate the 30‐boiler operating day average emissions rate. (Note: For this calculation, the term Ehj in Equation 19‐19 must be in the same units of measure as the applicable HCl or HF emission limit in Table 2 to subp. UUUUU). [40 CFR 63.10005(d)(1)&(2), Minn. R. 7011.0563]

COMG 7 43

(2) If the Permittee demonstrates compliance for EQUI82, EQUI83, EQUI100, and EQUI85 with the applicable emission limits for total non‐mercury HAP metals, individual non‐mercury HAP metals, total HAP metals, individual HAP metals, or filterable PM listed in Table 2 to subp. UUUUU using initial performance testing and continuous monitoring with PM CPMS:

(i) The Permittee must demonstrate initial compliance no later than the applicable date specified in Section 63.9984(f) for EQUI82, EQUI83, EQUI100, and EQUI85.(ii) The Permittee must demonstrate continuous compliance with the PM CPMS site‐specific operating limit that corresponds to the results of the performance test demonstrating compliance with the emission limit with which the Permittee has chosen to comply.

(iii) The Permittee must repeat the performance test annually for the selected pollutant emissions limit and reassess and adjust the site‐specific operating limit in accordance with the results of the performance test. [40 CFR 63.10005(d)(1)&(2), Minn. R. 7011.0563]

COMG 7 44

(3) If for EQUI82, EQUI83, EQUI100, and EQUI85 the Permittee is either required to or elects to demonstrate initial compliance with the applicable Hg emission limit in Table 2 of subp. UUUUU using Hg CEMS or sorbent trap monitoring systems, initial compliance must be demonstrated no later than the applicable date specified in Section 63.9984(f) for EQUI82, EQUI83, EQUI100, and EQUI85. Initial compliance is achieved if the arithmetic average of 30‐ (or 90‐) boiler operating days of quality‐assured CEMS (or sorbent trap monitoring system) data, expressed in units of the standard (see section 6.2 of appendix A to subp. UUUUU), meets the applicable Hg emission limit in Table 2 to subp. UUUUU. [40 CFR 63.10005(d)(3), Minn. R. 7011.0563]

COMG 7 45

Tune‐ups. EQUI82, EQUI83, EQUI100, and EQUI85 are subject to the work practice standards in Table 3 of subp. UUUUU. As part of the Permittee's initial compliance demonstration, the Permittee must conduct a performance tune‐up of the EGU according to Section 63.10021(e). [40 CFR 63.10005(e), Minn. R. 7011.0563]

COMG 7 46

(f) For an existing EGU without a neural network, a tune‐up, following the procedures in Section 63.10021(e), must occur within 6 months (180 days) after April 16, 2015. For an existing EGU with a neural network, a tune‐up must occur within 18 months (545 days) after April 16, 2016. If a tune‐up occurs prior to April 16, 2015, the Permittee must keep records showing that the tune‐up met all rule requirements. EQUI82, EQUI83, EQUI100, and EQUI85 are each equipped with a neural network. [40 CFR 63.10005(f), Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

COMG 7 47

Low emitting EGUs. The provisions of Section 63.10005(h) apply to pollutants with emissions limits from existing EGUs. The Permittee may pursue this compliance option unless prohibited pursuant to Section 63.10000(c)(1)(i) (which states the Permittee may not pursue this option if the Permittee's existing EGU is equipped with an acid gas scrubber and has a main stack and bypass stack exhaust configuration).

(1) An EGU may qualify for low emitting EGU (LEE) status for Hg, HCl, HF, filterable PM, total non‐Hg HAP metals, or individual non‐Hg HAP metals (or total HAP metals or individual HAP metals, for liquid oil‐fired EGUs) if the Permittee collects performance test data that meet the requirements of Section 63.10005(h), and if those data demonstrate:

(i) For all pollutants except Hg, performance test emissions results less than 50 percent of the applicable emissions limits in Table 2 to subp. UUUUU for all required testing for 3 consecutive years; or(ii) For Hg emissions from an existing EGU, either: (A) Average emissions less than 10 percent of the applicable Hg emissions limit in Table 2 to subp. UUUUU (expressed either in units of lb/TBtu or lb/GWh); or (B) Potential Hg mass emissions of 29.0 or fewer pounds per year and compliance with the applicable Hg emission limit in Table 2 to subp. UUUUU (expressed either in units of lb/TBtu or lb/GWh). [40 CFR 63.10005(h)(1), Minn. R. 7011.0563]

COMG 7 48

(2) For all pollutants except Hg, the Permittee must conduct all required performance tests described in Section 63.10007 to demonstrate that a unit qualifies for LEE status.(i) When conducting emissions testing to demonstrate LEE status, the Permittee must increase the minimum sample volume specified in Table 2 nominally by a factor of two.(ii) Follow the instructions in Section 63.10007(e) and Table 5 to subp. UUUUU to convert the test data to the units of the applicable standard. [40 CFR 63.10005(h)(2), Minn. R. 7011.0563]

COMG 7 49

(3) For Hg, the Permittee must conduct a 30‐ (or 90‐) boiler operating day performance test using Method 30B in appendix A‐8 to part 60 to determine whether a unit qualifies for LEE status. Locate the Method 30B sampling probe tip at a point within 10 percent of the duct area centered about the duct's centroid at a location that meets Method 1 in appendix A‐1 to part 60 and conduct at least three nominally equal length test runs over the 30‐ (or 90‐) boiler operating day test period. The Permittee may use a pair of sorbent traps to sample the stack gas for a period consistent with that given in section 5.2.1 of appendix A to subp. UUUUU. Collect Hg emissions data continuously over the entire test period (except when changing sorbent traps or performing required reference method QA procedures). As an alternative to constant rate sampling per Method 30B, the Permittee may use propor onal sampling per sec on 8.2.2 of Performance Specifica on 12 B in appendix B to part 60.(i) Depending on whether the Permittee intends to assess LEE status for Hg in terms of the lb/TBtu or lb/GWh emission limit in Table 2 to subp. UUUUU or in terms of the annual Hg mass emissions limit of 29.0 lb/year, the Permittee will have to collect some or all of the following data during the 30‐boiler operating day test period (see Sec on 63.10005(h)(3)(iii)):(A) Diluent gas (CO2 or O2) data, using either Method 3A in appendix A‐3 to part 60 or a diluent gas monitor that has been cer fied according to part 75.(B) Stack gas flow rate data, using either Method 2, 2F, or 2G in appendices A‐1 and A‐2 to part 60, or a flow rate monitor that has been cer fied according to part 75.(C) Stack gas moisture content data, using either Method 4 in appendix A‐1 to part 60, or a moisture monitoring system that has been certified according to part 75. Alternatively, an appropriate fuel‐specific default moisture value from Section 75.11(b) may be used in the calculations or you may petition the Administrator under Sec on 75.66 for use of a default moisture value for non‐coal‐fired units.(D) Hourly gross output data (megawatts), from facility records. [40 CFR 63.10005(h)(3)(i), Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

COMG 7 50

(ii) If the Permittee uses CEMS to measure CO2 (or O2) concentration, and/or flow rate, and/or moisture, record hourly average values of each parameter throughout the 30‐boiler operating day test period. If the Permittee opts to use EPA reference methods rather than CEMS for any parameter, the Permittee must perform at least one representative test run on each operating day of the test period, using the applicable reference method. [40 CFR 63.10005(h)(3)(ii), Minn. R. 7011.0563]

COMG 7 51

(iii) Calculate the average Hg concentration, in micrograms/m3 (dry basis), for the 30‐boiler operating day performance test, as the arithmetic average of all Method 30B sorbent trap results. Also calculate, as applicable, the average values of CO2 or O2 concentration, stack gas flow rate, stack gas moisture content, and gross output for the test period. Then:(A) To express the test results in units of lb/TBtu, follow the procedures in Section 63.10007(e). Use the average Hg concentra on and diluent gas values in the calcula ons.

(B) To express the test results in units of lb/GWh, use Equations A‐3 and A‐4 in section 6.2.2 of appendix A to subp. UUUUU, replacing the hourly values "Ch", "Qh", "Bws" and "(MW)h" with the average values of these parameters from the performance test. [40 CFR 63.10005(h)(3)(iii)(A) & (B), Minn. R. 7011.0563]

COMG 7 52

(C) To calculate pounds of Hg per year, use one of the following methods:

(1) Multiply the average lb/TBtu Hg emission rate (determined according to Section 63.10005(h)(3)(iii)(A)) by the maximum potential annual heat input to the unit (TBtu), which is equal to the maximum rated unit heat input (TBtu/hr) times 8,760 hours. If the maximum rated heat input value is expressed in units of MMBtu/hr, mul ply it by 10^‐6 to convert it to TBtu/hr; or(2) Multiply the average lb/GWh Hg emission rate (determined according to Section 63.10005(h)(3)(iii)(B)) by the maximum potential annual electricity generation (GWh), which is equal to the maximum rated electrical output of the unit (GW) times 8,760 hours. If the maximum rated electrical output value is expressed in units of MW, multiply it by 10^‐3 to convert it to GW. [40 CFR 63.10005(h)(3)(iii)(C), Minn. R. 7011.0563]

COMG 7 53

(4) For EQUI82, EQUI83, and EQUI100 (a group of affected units that vent to common stack STRU13), the Permittee may either assess LEE status for the units individually by performing a separate emission test of each unit in the duct leading from the unit to the common stack, or the Permittee may perform a single emission test in the common stack. If the Permittee chooses the common stack testing option, the units in the configuration qualify for LEE status if:(i) The emission rate measured at the common stack is less than 50 percent (10 percent for Hg) of the applicable emission limit in Table 2 to subp. UUUUU; or(ii) For Hg from an existing EGU, the applicable Hg emission limit in Table 2 to subp. UUUUU is met and the potential annual mass emissions, calculated according to Section 63.10005(h)(3)(iii) (with some modifications), are less than or equal to 29.0 pounds times the number of units sharing the common stack. The Permittee shall base its calculations on the combined heat input capacity of all units sharing the stack (i.e., either the combined maximum rated value or, if applicable, a lower combined value restricted by permit conditions or operating hours). Section 63.10005(h)(4) does not apply to EQUI85, and will no longer apply to EQUI100 upon permanent shutdown of EQUI82 and EQUI83 (which will occur on or before December 31, 2018). [40 CFR 63.10005(h)(4), Minn. R. 7011.0563]

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COMG 7 54

(5) For EQUI82, EQUI82, and EQUI100 (affected units with a multiple stack or duct configuration in which the exhaust stacks or ducts are downstream of all emission control devices), the Permittee must perform a separate emission test in each stack or duct. The unit qualifies for LEE status if:(i) The emission rate, based on all test runs performed at all of the stacks or ducts, is less than 50 percent (10 percent for Hg) of the applicable emission limit in Table 2 to subp. UUUUU; or(ii) For Hg from an existing EGU, the applicable Hg emission limit in Table 2 to this subpart is met and the potential annual mass emissions, calculated according to Section 63.10005(h)(3)(iii), are less than or equal to 29.0 pounds. The Permittee shall use the average Hg emission rate from Section 63.10005(h)(5)(i) in its calculations. Section 63.10005(h)(5) does not apply to EQUI85, and will no longer apply to EQUI100 upon permanent shutdown of EQUI82 and EQUI83 (which will occur on or before December 31, 2018). [40 CFR 63.10005(h)(5), Minn. R. 7011.0563]

COMG 7 55

Startup and shutdown for coal‐fired units. The Permittee must follow the requirements given in Table 3 to subp. UUUUU. [40 CFR 63.10005(j), Minn. R. 7011.0563]

COMG 7 56

The Permittee must submit a Notification of Compliance Status summarizing the results of its initial compliance demonstration, as provided in Section 63.10030. [40 CFR 63.10005(k), Minn. R. 7011.0563]

COMG 7 57

For coal‐fired EGUs using PM CPMS to monitor continuous performance with an applicable emission limit as provided for under Section 63.10000(c), the Permittee must conduct all applicable performance tests according to Table 5 of pt. 63, subp. UUUUU and Section 63.10007 at least every year. [40 CFR 63.10006(a), Minn. R. 7011.0563]

COMG 7 58

For affected units meeting the LEE requirements of Section 63.10005(h), the Permittee must repeat the performance test once every 3 years (once every year for Hg) according to Table 5 to subp. UUUUU and Section 63.10007. Should subsequent emissions testing results show the unit does not meet the LEE eligibility requirements, LEE status is lost. If this should occur: (1) For all pollutant emission limits except for Hg, the Permittee must conduct emissions testing quarterly, except as otherwise provided in Sec on 63.10021(d)(1). (2) For Hg, the Permittee must install, certify, maintain, and operate a Hg CEMS or a sorbent trap monitoring system in accordance with appendix A to subp. UUUUU, within 6 calendar months of losing LEE eligibility. Until the Hg CEMS or sorbent trap monitoring system is installed, certified, and operating, the Permittee must conduct Hg emissions testing quarterly, except as otherwise provided in Section 63.10021(d)(1). The Permittee must have 3 calendar years of testing and CEMS or sorbent trap monitoring system data that satisfy the LEE emissions criteria to reestablish LEE status. [40 CFR 63.10006(b), Minn. R. 7011.0563]

COMG 7 59

Except where Sections 63.10006(a) or (b) apply, or where the Permittee installs, certifies, and operates a PM CEMS to demonstrate compliance with a filterable PM emissions limit, for coal‐fired EGUs the Permittee must conduct all applicable periodic emissions tests for filterable PM, individual, or total HAP metals emissions according to Table 5 to subp. UUUUU, Section 63.10007, and Section 63.10000(c), except as otherwise provided in Section 63.10021(d)(1). [40 CFR 63.10006(c), Minn. R. 7011.0563]

COMG 7 60

Except where Section 63.10006(b) applies, for coal‐fired EGUs that do not use either an HCl CEMS to monitor compliance with the HCl limit or an SO2 CEMS to monitor compliance with the alternate equivalent SO2 emission limit, the Permittee must conduct all applicable periodic HCl emissions tests according to Table 5 to subp. UUUUU and Section 63.10007 at least quarterly, except as otherwise provided in Section 63.10021(d)(1). [40 CFR 63.10006(d), Minn. R. 7011.0563]

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COMG 7 61

(f) Time between performance tests. (1) Notwithstanding the provisions of Section 63.10021(d)(1), the requirements listed in Section 63.10006(g) and (h), and the requirements of Section 63.10006(f)(3), the Permittee must complete performance tests for EQUI82, EQUI83, EQUI100, and EQUI85 as follows: (i) At least 45 calendar days, measured from the test's end date, must separate performance tests conducted every quarter; (ii) For annual testing:(A) At least 320 calendar days, measured from the test's end date, must separate performance tests; (B) At least 320 calendar days, measured from the test's end date, must separate annual sorbent trap mercury testing for 30‐boiler operating day LEE tests; (C) At least 230 calendar days, measured from the test's end date, must separate annual sorbent trap mercury testing for 90‐boiler operating day LEE tests; and (iii) At least 1,050 calendar days, measured from the test's end date, must separate performance tests conducted every 3 years. [40 CFR 63.10006(f), Minn. R. 7011.0563]

COMG 7 61

(2) For units demonstrating compliance through quarterly emission testing, the Permittee must conduct a performance test in the 4th quarter of a calendar year if the Permittee skipped performance tests for EQUI82, EQUI83, EQUI100, and/or EQUI85, as applicable, in the first 3 quarters of the calendar year. (3) If EQUI82, EQUI83, EQUI100, and/or EQUI85 miss a performance test deadline due to being inoperative and if 168 or more boiler operating hours occur in the next test period, the Permittee must complete an additional performance test in that period as follows: (i) At least 15 calendar days must separate two performance tests conducted in the same quarter. (ii) At least 107 calendar days must separate two performance tests conducted in the same calendar year. (iii) At least 350 calendar days must separate two performance tests conducted in the same 3 year period. [40 CFR 63.10006(f), Minn. R. 7011.0563]

COMG 7 62

If the Permittee elects to demonstrate compliance using emissions averaging under Section 63.10009, the Permittee must continue to conduct performance stack tests at the appropriate frequency given in Section 63.10006(c) through (f). [40 CFR 63.10006(g), Minn. R. 7011.0563]

COMG 7 63

If a performance test on a non‐mercury LEE shows emissions in excess of 50 percent of the emission limit and if the Permittee chooses to reapply for LEE status, the Permittee must conduct performance tests at the appropriate frequency given in Section 63.10006(c) through (e) for that pollutant until all performance tests over a consecutive 3‐year period show compliance with the LEE criteria. [40 CFR 63.10006(h), Minn. R. 7011.0563]

COMG 7 64

If the Permittee is required to meet an applicable tune‐up work practice standard, the Permittee must conduct a performance tune‐up according to Sec on 63.10021(e). (1) For EGUs not employing neural network combustion optimization during normal operation, each performance tune‐up specified in Section 63.10021(e) must be no more than 36 calendar months after the previous performance tune‐up. (2) For EGUs employing neural network combustion optimization systems during normal operation, each performance tune‐up specified in Section 63.10021(e) must be no more than 48 calendar months after the previous performance tune‐up. EQUI82, EQUI83, EQUI100, and EQUI85 are each equipped with a neural network. [40 CFR 63.10006(i), Minn. R. 7011.0563]

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COMG 7 65

Except as otherwise provided in Section 63.10007, the Permittee must conduct all required performance tests according to Section 63.7(d), (e), (f), and (h). The Permittee must also develop a site‐specific test plan according to the requirements in Section 63.7(c). (1) If the Permittee uses CEMS (Hg, HCl, SO2, or other) to determine compliance with a 30‐ (or, if applicable, 90‐) boiler operating day rolling average emission limit, the Permittee must collect quality‐ assured CEMS data for all EQUI82, EQUI83, EQUI100, and EQUI85 operating conditions, including startup and shutdown (see Section 63.10011(g) and Table 3 to subp. UUUUU), except as otherwise provided in Section 63.10020(b). Emission rates determined during startup periods and shutdown periods (as defined in Section 63.10042) are not to be included in the compliance determinations, except as otherwise provided in Sections 63.10000(c)(1)(vi)(B) and 63.10005(a)(2)(iii). (2) If the Permittee conducts performance testing with test methods in lieu of continuous monitoring, operate EQUI82, EQUI83, EQUI100, and EQUI85 at maximum normal operating load conditions during each periodic (e.g., quarterly) performance test. Maximum normal operating load will be generally between 90 and 110 percent of design capacity but should be representative of site specific normal operations during each test run. (3) For establishing operating limits with particulate matter continuous parametric monitoring system (PM CPMS) to demonstrate compliance with a PM or non Hg metals emissions limit, operate EQUI82, EQUI83, EQUI100, and EQUI85 at maximum normal operating load conditions during the performance test period. Maximum normal operating load will be generally between 90 and 110 percent of design capacity but should be representative of site specific normal operations during each test run. [40 CFR 63.10007(a), Minn. R. 7011.0563]

COMG 7 66

The Permittee must conduct each performance test (including traditional 3‐run stack tests, 30‐boiler operating day tests based on CEMS data (or sorbent trap monitoring system data), and 30‐boiler operating day Hg emission tests for LEE qualification) according to the requirements in Table 5 to subp. UUUUU. [40 CFR 63.10007(b), 40 CFR pt. 63, subp. UUUUU (Table 5), Minn. R. 7011.0563]

COMG 7 67

If the Permittee chooses the filterable PM method to comply with the PM emission limit and demonstrate continuous performance using a PM CPMS as provided for in Section 63.10000(c), the Permittee must also establish an operating limit according to Section 63.10011(b), Section 63.10023, and Tables 4 and 6 to subp. UUUUU. If the Permittee desires to have operating limits that correspond to loads other than maximum normal operating load, the Permittee must conduct testing at those other loads to determine the additional operating limits. [40 CFR 63.10007(c), Minn. R. 7011.0563]

COMG 7 68

Except for a 30‐boiler operating day performance test based on CEMS (or sorbent trap monitoring system) data, where the concept of test runs does not apply, the Permittee must conduct a minimum of three separate test runs for each performance test, as specified in Section 63.7(e)(3). Each test run must comply with the minimum applicable sampling time or volume specified in Table 2 to subp. UUUUU. Sections 63.10005(d) and (h), respectively, provide special instructions for conducting performance tests based on CEMS or sorbent trap monitoring systems, and for conducting emission tests for LEE qualification. [40 CFR 63.10007(d), Minn. R. 7011.0563]

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COMG 7 69

To use the results of performance testing to determine compliance with the applicable emission limits in Table 2 to subp. UUUUU, proceed as follows:

(1) Except for a 30‐boiler operating day performance test based on CEMS (or sorbent trap monitoring system) data, if measurement results for any pollutant are reported as below the method detection level (e.g., laboratory analytical results for one or more sample components are below the method defined analytical detection level), the Permittee must use the method detection level as the measured emissions level for that pollutant in calculating compliance. The measured result for a multiple component analysis (e.g., analytical values for multiple Method 29 fractions both for individual HAP metals and for total HAP metals) may include a combination of method detection level data and analytical data reported above the method detection level. [40 CFR 63.10007(e)(1), Minn. R. 7011.0563]

COMG 7 70

(2) If the limits are expressed in lb/MMBtu or lb/TBtu, the Permittee must use the F‐factor methodology and equations in sections 12.2 and 12.3 of EPA Method 19 in appendix A‐7 to part 60 of this chapter. In cases where an appropriate F‐factor is not listed in Table 19‐2 of Method 19, the Permittee may use F‐factors from Table 1 in section 3.3.5 of appendix F to part 75, or F‐factors derived using the procedures in section 3.3.6 of appendix to part 75. Use the following factors to convert the pollutant concentrations measured during the initial performance tests to units of lb/scf, for use in the applicable Method 19 equations: (i) Multiply SO2 ppm by 1.66 x 1E‐7; (ii) Multiply HCl ppm by 9.43 x 1E‐8; (iii) Multiply HF ppm by 5.18 x 1E‐8; (iv) Multiply HAP metals concentrations (mg/dscm) by 6.24 x 1E‐8; and (v) Multiply Hg concentrations (ug/scm) by 6.24 x 1E‐11. [40 CFR 63.10007(e)(2), Minn. R. 7011.0563]

COMG 7 71

(3) To determine compliance with emission limits expressed in lb/MWh or lb/GWh, the Permittee must first calculate the pollutant mass emission rate during the performance test, in units of lb/h. For Hg, if a CEMS or sorbent trap monitoring system is used, use Equation A‐2 or A‐3 in appendix A to subp. UUUUU (as applicable). In all other cases, use an equation that has the general form of Equation A‐2 or A‐3, replacing the value of K with 1.66E‐7 lb/scf‐ppm for SO2, 9.43E‐8 lb/scf‐ppm for HCl (if an HCl CEMS is used), 5.18E‐8 lb/scf‐ppm for HF (if an HF CEMS is used), or 6.24E‐8 lb‐scm/mg‐scf for HAP metals and for HCl and HF (when performance stack testing is used), and defining Ch as the average SO2, HCl, or HF concentration in ppm, or the average HAP metals concentration in mg/dscm. This calculation requires stack gas volumetric flow rate (scfh) and (in some cases) moisture content data (see Sections 63.10005(h)(3) and 63.10010). Then, if the applicable emission limit is in units of lb/GWh, use Equation A‐4 in appendix A to subp. UUUUU to calculate the pollutant emission rate in lb/GWh. In this calculation, define (M)h as the calculated pollutant mass emission rate for the performance test (lb/h), and define (MW)h as the average electrical load during the performance test (megawatts). If the applicable emission limit is in lb/MWh rather than lb/GWh, omit the 1E+3 term from Equation A‐4 to determine the pollutant emission rate in lb/MWh. [40 CFR 63.10007(e)(3), Minn. R. 7011.0563]

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COMG 7 72

(f) If the Permittee elects to (or is required to) use CEMS to continuously monitor Hg, HCl, HF, SO2, or PM emissions (or, if applicable, sorbent trap monitoring systems to continuously collect Hg emissions data), the following default values are available for use in the emission rate calculations during startup periods or shutdown periods (as defined in Section 63.10042). For the purposes of subp. UUUUU, these default values are not considered to be subs tute data.

(1) Diluent cap values. If the Permittee uses CEMS (or, if applicable, sorbent trap monitoring systems) to comply with a heat input‐based emission rate limit, the Permittee may use the following diluent cap values for a startup or shutdown hour in which the measured CO2 concentration is below the cap value or the measured O2 concentra on is above the cap value:(ii) For all non‐IGCC EGUs, the Permi ee may use 5% for CO2 or 14% for O2.

(2) Default gross output. If the Permittee uses CEMS to continuously monitor Hg, HCl, HF, SO2, or PM emissions (or, if applicable, sorbent trap monitoring systems to continuously collect Hg emissions data), the following default value is available for use in the emission rate calculations during startup periods or shutdown periods (as defined in Section 63.10042). For the purposes of this subpart, this default value is not considered to be substitute data. For a startup or shutdown hour in which there is heat input to an affected EGU but zero gross output, the Permittee must calculate the pollutant emission rate using a value equivalent to 5% of the maximum sustainable gross output, expressed in megawatts, as defined in section 6.5.2.1(a)(1) of appendix A to part 75. This default gross output is either the nameplate capacity of the EGU or the highest gross output observed in at least four representative quarters of EGU operation. For a monitored common stack, the default gross output is used only when all EGUs are operating (i.e., combusting fuel) are in startup or shutdown mode, and have zero electrical generation. Under those conditions, a default gross output equal to 5% of the combined maximum sustainable gross output of the EGUs that are operating but have a total of zero gross output must be used to calculate the hourly gross output‐based pollutant emissions rate. [40 CFR 63.10007(f), Minn. R. 7011.0563]

COMG 7 73

Upon request, the Permittee shall make available to the EPA Administrator such records as may be necessary to determine whether the performance tests have been done according to the requirements of Section 63.10007. [40 CFR 63.10007(g), Minn. R. 7011.0563]

COMG 7 74

Using Emissions Averaging ‐ General Eligibility.

1) The Permittee may use emissions averaging as described in Section 63.10009(a)(2) as an alternative to meeting the requirements of Section 63.9991 for filterable PM, SO2, HF, HCl, non‐Hg HAP metals, or Hg on an EGU‐specific basis if: (i) The Permittee has more than one existing EGU in the same subcategory located at one or more contiguous properties, belonging to a single major industrial grouping, which are under common control of the same person (or persons under common control); and (ii) The Permittee uses CEMS (or sorbent trap monitoring systems for determining Hg emissions) or quarterly emissions testing for demonstrating compliance. [40 CFR 63.10009(a)(1), Minn. R. 7011.0563]

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COMG 7 75

(2) The Permittee may demonstrate compliance by emissions averaging among the existing EGUs in the same subcategory, if the Permittee's averaged Hg emissions for EGUs in the "unit designed for coal greater than or equal to 8,300 Btu/lb" subcategory are equal to or less than 1.2 lb/TBtu or 1.3E‐2 lb/GWh on a 30‐boiler operating day basis or if the Permittee's averaged emissions of individual, other pollutants from other subcategories of such EGUs are equal to or less than the applicable emissions limit in Table 2 of subp. UUUUU, according to the procedures in Section 63.10009. Note that except for the alternate Hg emissions limit from EGUs in the "unit designed for coal greater than or equal to 8,300 Btu/lb" subcategory, the averaging time for emissions averaging for pollutants is 30 days (rolling daily) using data from CEMS or a combination of data from CEMS and manual performance (LEE) testing. The averaging time for emissions averaging for the alternate Hg limit (equal to or less than 1.0 lb/TBtu or 1.1E‐2 lb/GWh) from EGUs in the "unit designed for coal greater than or equal to 8,300 Btu/lb" subcategory is 90‐boiler operating days (rolling daily) using data from CEMS, sorbent trap monitoring, or a combination of monitoring data and data from manual performance (LEE) testing. For the purposes of Section 63.10009(a), 30‐ (or 90‐) group boiler operating days is defined as a period during which at least one unit in the emissions averaging group operates on each of the 30 or 90 days. The Permittee must calculate the weighted average emissions rate for the group in accordance with the procedures in Section 63.10009(a) using the data from all units in the group including any that operate fewer than 30 (or 90) days during the preceding 30 (or 90) group boiler days. [40 CFR 63.10009(a)(2), Minn. R. 7011.0563]

COMG 7 76

(2)(i) The Permittee may choose to have its EGU emissions averaging group meet either the heat input basis (MMBtu or TBtu, as appropriate for the pollutant) or gross output basis (MWh or GWh, as appropriate for the pollutant). (ii) the Permittee may not mix bases within its EGU emissions averaging group. (iii) The Permittee may use emissions averaging for affected units in different subcategories if the units vent to the atmosphere through a common stack (see Section 63.10009(m)). [40 CFR 63.10009(a)(2)(i)‐(iii), Minn. R. 7011.0563]

COMG 7 77

Equations. The Permittee shall use the equations at Section 63.10009(b) and located in Appendix E of this permit when performing calcula ons for its EGU emissions averaging group.

(1) Group eligibility equa ons. Use Equa ons 1a and 1b in Appendix E.

(2) Weighted 30‐boiler operating day rolling average emissions rate equations for pollutants other than Hg. Use equa on 2a or 2b in Appendix E to calculate the 30 day rolling average emissions daily.

(3) Weighted 90‐boiler operating day rolling average emissions rate equations for Hg emissions from EGUs in the "coal‐fired unit not low rank virgin coal" subcategory. Use equation 3a or 3b in Appendix E to calculate the 90‐day rolling average emissions daily. [40 CFR 63.10009(b), Minn. R. 7011.0563]

COMG 7 78

Separate stack requirements. For a group of two or more existing EGUs in the same subcategory that each vent to a separate stack, the Permittee may average filterable PM, SO2, HF, HCl, non‐Hg HAP metals, or Hg emissions to demonstrate compliance with the limits in Table 2 to subp. UUUUUU if the Permittee satisfies the requirements in Sec on 63.10009(d) through (j). This requirement currently only applies to EQUI85 (which vents to STRU14). This requirement will apply to EQUI100 (which along with EQUI82 and EQUI83 currently vents to STRU13) after shutdown of EQUI82 and EQUI83 which will occur no later than December 31, 2018. [40 CFR 63.10009(c), Minn. R. 7011.0563]

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COMG 7 79

For each exis ng EGU in the averaging group:

(1) The emissions rate achieved during the initial performance test for the HAP being averaged must not exceed the emissions level that was being achieved 180 days after April 16, 2015, or the date on which emissions testing done to support the Permittee's emissions averaging plan is complete (if the Administrator does not require submission and approval of the Permittee's emissions averaging plan), or the date the Permittee begins emissions averaging, whichever is earlier; or

(2) The control technology employed during the initial performance test must not be less than the design efficiency of the emissions control technology employed 180 days after April 16, 2015 or the date the Permittee begins emissions averaging, whichever is earlier. [40 CFR 63.10009(d), Minn. R. 7011.0563]

COMG 7 80

The weighted‐average emissions rate from the existing EGUs participating in the emissions averaging option must be in compliance with the limits in Table 2 to subp. UUUUU at all times following the compliance date specified 180 days after April 16, 2015, or the date on which the Permittee completes the emissions measurements used to support its emissions averaging plan (if the Administrator does not require submission and approval of the Permittee's emissions averaging plan), or the date that the Permittee begins emissions averaging, whichever is earlier. [40 CFR 63.10009(e), Minn. R. 7011.0563]

COMG 7 81

Emissions averaging group eligibility demonstration. The Permittee must demonstrate the ability for the EGUs included in the emissions averaging group to demonstrate initial compliance according to Section 63.10009(f)(1) or (2) using the maximum rated heat input or gross output over a 30‐ (or 90‐) boiler operating day period of each EGU and the results of the initial performance tests. For this demonstration and prior to the Permittee's preparation of its emissions averaging plan, the Permittee must conduct required emissions monitoring for 30‐ (or 90‐) days of boiler operation and any required manual performance testing to calculate maximum weighted average emissions rate in accordance with Section 63.10009. If, before the start of the Permittee's initial compliance demonstration, the Administrator becomes aware that the Permittee intends to use emissions averaging for that demonstration, or if the Permittee's initial Notification of Compliance Status (NOCS) indicates the Permittee's intention to implement emissions averaging at a future date, the Administrator may require the Permittee to submit its proposed emissions averaging plan and supporting data for approval. If the Administrator requires approval of the Permittee's plan, the Permittee may not begin using emissions averaging until the Administrator approves the Permittee's plan. [40 CFR 63.10009(f), Minn. R. 7011.0563]

COMG 7 82

(1) The Permittee must use Equation 1a in Section 63.10009(b) to demonstrate that the maximum weighted average emissions rates of filterable PM, HF, SO2, HCl, non‐Hg HAP metals, or Hg emissions from the existing units participating in the emissions averaging option do not exceed the emissions limits in Table 2 to subp. UUUUU. (2) If the Permittee is not capable of monitoring heat input or gross output, and the EGU generates steam for purposes other than generating electricity, the Permittee may use Equation 1b in Section 63.10009(b) as an alternative to using Equation 1a of Section 63.10009(b) to demonstrate that the maximum weighted average emissions rates of filterable PM, HF, SO2, HCl, non‐Hg HAP metals, or Hg emissions from the existing units participating in the emissions averaging group do not exceed the emission limits in Table 2 to subp. UUUUU. [40 CFR 63.10009(f)(1)&(2), Minn. R. 7011.0563]

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COMG 7 83

The Permittee must determine the weighted average emissions rate in units of the applicable emissions limit on a 30 day rolling average (90 day rolling average for Hg) basis according to Section 63.10009(g)(1). The first averaging period begins on 30 (or 90 for Hg) days after February 16, 2015 or the date the Permittee begins emissions averaging, whichever is earlier. (1) The Permittee must use Equation 2a or 3a of Section 63.10009(b) to calculate the weighted average emissions rate using the actual heat input or gross output for each existing unit participating in the emissions averaging option. [40 CFR 63.10009(g)(1), Minn. R. 7011.0563]

COMG 7 84

CEMS (or sorbent trap monitoring) use. If an EGU in the Permittee's emissions averaging group uses CEMS (or a sorbent trap monitor for Hg emissions) to demonstrate compliance, the Permittee must use those data to determine the 30 (or 90) group boiler operating day rolling average emissions rate. [40 CFR 63.10009(h), Minn. R. 7011.0563]

COMG 7 85

Emissions testing. If the Permittee uses manual emissions testing to demonstrate compliance for one or more EGUs in the Permittee's emissions averaging group, the Permittee must use the results from the most recent performance test to determine the 30 (or 90) day rolling average. The Permittee may use CEMS or sorbent trap data in combination with data from the most recent manual performance test in calculating the 30 (or 90) group boiler operating day rolling average emissions rate. [40 CFR 63.10009(i), Minn. R. 7011.0563]

COMG 7 86

Emissions averaging plan. The Permittee must develop an implementation plan for emissions averaging according to the following procedures and requirements in Sec on 63.10009(j)(1) and (2).

(1) The Permittee must include the information contained in Section 63.10009(j)(1)(i) through (v) in its implementa on plan for all the emissions units included in an emissions averaging: (i) The identification of all existing EGUs in the emissions averaging group, including for each either the applicable HAP emission level or the control technology installed as of 180 days after February 16, 2015, or the date on which the Permittee completes the emissions measurements used to support its emissions averaging plan (if the Administrator does not require submission and approval of the Permittee's emissions averaging plan), or the date the Permittee begins emissions averaging, whichever is earlier; and the date on which the Permi ee is reques ng emissions averaging to commence; (ii) The process weighting parameter (heat input, gross output, or steam generated) that will be monitored for each averaging group; (iii) The specific control technology or pollution prevention measure to be used for each emission EGU in the averaging group and the date of its installation or application. If the pollution prevention measure reduces or eliminates emissions from mul ple EGUs, the Permi ee must iden fy each EGU; (iv) The means of measurement (e.g., CEMS, sorbent trap monitoring, manual performance test) of filterable PM, SO2, HF, HCl, individual or total non‐Hg HAP metals, or Hg emissions in accordance with the requirements in Sec on 63.10007 and to be used in the emissions averaging calcula ons; and (v) A demonstration that emissions averaging can produce compliance with each of the applicable emission limit(s) in accordance with Section 63.10009(b)(1). [40 CFR 63.10009(j)(1), Minn. R. 7011.0563]

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COMG 7 87

(2) If as described in Section 63.10009(f), the Administrator requests the Permittee to submit the averaging plan for review and approval, the Permittee must receive approval before initiating emissions averaging.(i) The Administrator shall use following criteria in reviewing and approving or disapproving the plan: (A) Whether the content of the plan includes all of the information specified in Section 63.10009(j)(1); and (B) Whether the plan presents information sufficient to determine that compliance will be achieved and maintained. (ii) The Administrator shall not approve an emissions averaging implementation plan containing any of the following provisions: (A) Any averaging between emissions of different pollutants or between units located at different facilities; or (B) The inclusion of any emissions unit other than an existing unit in the same subcategory. [40 CFR 63.10009(j)(2), Minn. R. 7011.0563]

COMG 7 88

Common stack requirements. For EQUI82, EQUI83, and EQUI100 (existing affected units venting through a single common stack STRU13), the Permittee may average emissions to demonstrate compliance with the limits in Table 2 to subp. UUUUU if the Permi ee sa sfies the requirements in Sec on 63.10009(l) or (m).

Section 63.10009(k) does not apply to EQUI85, and will no longer apply to EQUI100 upon permanent shutdown of EQUI82 and EQUI83 (which will occur on or before December 31, 2018). [40 CFR 63.10009(k), Minn. R. 7011.0563]

COMG 7 89

For all other groups of units subject to Section 63.10009(k), the Permittee may elect to conduct manual performance tests according to procedures specified in Section 63.10007 in the common stack. If emissions from affected units included in the emissions averaging and from other units not included in the emissions averaging (e.g., in a different subcategory) or other nonaffected units all vent to the common stack, the Permittee must shut down the units not included in the emissions averaging and the nonaffected units or vent their emissions to a different stack during the performance test. Alternatively, the Permittee may conduct a performance test of the combined emissions in the common stack with all units operating and show that the combined emissions meet the most stringent emissions limit. The Permittee may also use a CEMS or sorbent trap monitoring to apply this latter alternative to demonstrate that the combined emissions comply with the most stringent emissions limit on a continuous basis. [40 CFR 63.10009(m), Minn. R. 7011.0563]

COMG 7 90

Combination requirements. The common stack (STRU13) of a group of two or more existing EGUs (EQUI82, EQUI83, and EQUI100) in the same subcategory subject to Section 63.10009(k) may be treated as a single stack for purposes of Section 63.10009(c) and included in an emissions averaging group subject to Section 63.10009(c). [40 CFR 63.10009(n), Minn. R. 7011.0563]

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COMG 7 91

Flue gases from the affected units under subp. UUUUU exhaust to the atmosphere through a variety of different configurations, including but not limited to individual stacks, a common stack configuration or a main stack plus a bypass stack. For the CEMS, PM CPMS, and sorbent trap monitoring systems used to provide data under subp. UUUUU, the continuous monitoring system installation requirements for these exhaust configurations are as follows:

(1) Single unit‐single stack configurations. For EQUI85 (an affected unit that exhausts to the atmosphere through a single, dedicated stack (STRU14)), the Permittee shall either install the required CEMS, PM CPMS, and sorbent trap monitoring systems in the stack or at a location in the ductwork downstream of all emissions control devices, where the pollutant and diluents concentrations are representative of the emissions that exit to the atmosphere. EQUI100 shall be subject to these same requirements upon permanent shutdown/retirement of EQUI82 and EQUI83 which occurs no later than December 31, 2018. Prior to the shutdown, EQUI82 and EQUI83 are affected units utilizing a common stack (STRU13) with another affected unit, EQUI100. [40 CFR 63.10010(a)(1), Minn. R. 7011.0563]

COMG 7 92

(2) Unit utilizing common stack with other affected unit(s). When an affected unit (EQUI82, EQUI83, and EQUI100) utilizes a common stack (STRU13) with one or more other affected units, but no non‐affected units, the Permi ee shall either: (i) Install the required CEMS, PM CPMS, and sorbent trap monitoring systems in the duct leading to the common stack from each unit; or(ii) Install the required CEMS, PM CPMS, and sorbent trap monitoring systems in the common stack.

There are three units that vent to STRU13: EQUI82, EQUI83, and EQUI100. These three boilers are affected units (subject to pt. 63, subp. UUUUU) and vent emissions through common stack STRU13. This venting configuration continues until EQUI82 and EQUI83 are permanently shutdown (no later than December 31, 2018). Prior to the shutdown, Section 63.10010(a)(2) applies to EQUI82, EQUI83, and EQUI100. After the shutdown, EQUI100 will be the only unit venting to STRU13, at which time Section 63.10010(a)(1) applies to EQUI100, and Section 63.10010(a)(2) no longer applies to EQUI100. [40 CFR 63.10010(a)(2), Minn. R. 7011.0563]

COMG 7 93

If the Permittee uses an oxygen (O2) or carbon dioxide (CO2) CEMS to convert measured pollutant concentrations to the units of the applicable emissions limit, the O2 or CO2 concentrations shall be monitored at a location that represents emissions to the atmosphere, i.e., at the outlet of the EGU, downstream of all emission control devices. The Permittee must install, certify, maintain, and operate the CEMS according to part 75 of this chapter. Use only quality‐assured O2 or CO2 data in the emissions calculations; do not use part 75 substitute data values. [40 CFR 63.10010(b), Minn. R. 7011.0563]

COMG 7 94

If the Permittee is required to use a stack gas flow rate monitor, either for routine operation of a sorbent trap monitoring system or to convert pollutant concentrations to units of an electrical output‐based emission standard in Table 2 to subp. UUUUU, the Permittee must install, certify, operate, and maintain the monitoring system and conduct on‐going quality‐assurance testing of the system according to part 75 of this chapter. Use only unadjusted, quality‐assured flow rate data in the emissions calculations. Do not apply bias adjustment factors to the flow rate data and do not use substitute flow rate data in the calculations. [40 CFR 63.10010(c), Minn. R. 7011.0563]

COMG 7 95

If the Permittee uses an HCl and/or HF CEMS, the Permittee must install, certify, operate, maintain, and quality‐assure the data from the monitoring system in accordance with appendix B to subp. UUUUU. Calculate and record a 30‐boiler operating day rolling average HCl or HF emission rate in the units of the standard, updated after each new boiler operating day. Each 30‐boiler operating day rolling average emission rate is the average of all the valid hourly HCl or HF emission rates in the preceding 30 boiler operating days (see section 9.4 of appendix B to subp. UUUUU). [40 CFR 63.10010(e), Minn. R. 7011.0563]

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COMG 7 96

(1) If the Permittee uses an SO2 CEMS, the Permittee must install the monitor at the outlet of the EGU, downstream of all emission control devices, and must certify, operate, and maintain the CEMS according to part 75.

(2) For on‐going QA, the SO2 CEMS must meet the applicable daily, quarterly, and semiannual or annual requirements in sections 2.1 through 2.3 of appendix B to part 75, with the following addition: The Permittee must perform the linearity checks required in section 2.2 of appendix B to part 75 if the SO2 CEMS has a span value of 30 ppm or less. [40 CFR 63.10010(f)(1)&(2), Minn. R. 7011.0563]

COMG 7 97

(3) Calculate and record a 30‐boiler operating day rolling average SO2 emission rate in the units of the standard, updated after each new boiler operating day. Each 30‐boiler operating day rolling average emission rate is the average of all of the valid hourly SO2 emission rates in the 30 boiler opera ng day period.

(4) Use only unadjusted, quality‐assured SO2 concentration values in the emissions calculations; do not apply bias adjustment factors to the part 75 SO2 data and do not use part 75 substitute data values. For startup or shutdown hours (as defined in Section 63.10042) the default gross output and the diluent cap are available for use in the hourly SO2 emission rate calculations, as described in Section 63.10007(f). Use a flag to identify each startup or shutdown hour and report a special code if the diluent cap or default gross output is used to calculate the SO2 emission rate for any of these hours. [40 CFR 63.10010(f)(3)&(4), Minn. R. 7011.0563]

COMG 7 98

If the Permittee uses a Hg CEMS or a sorbent trap monitoring system, the Permittee must install, certify, operate, maintain and quality‐assure the data from the monitoring system in accordance with appendix A to subp. UUUUU. The Permittee must calculate and record a 30‐ (or, if alternate emissions averaging is used, 90‐) boiler operating day rolling average Hg emission rate, in units of the standard, updated after each new boiler operating day. Each 30‐ (or, if alternate emissions averaging is used, 90‐) boiler operating day rolling average emission rate, calculated according to section 6.2 of appendix A to subp. UUUUU, is the average of all of the valid hourly Hg emission rates in the preceding 30‐ (or, if alternate emissions averaging is used, a 90‐) boiler operating days. Section 7.1.4.3 of appendix A to subp. UUUUU explains how to reduce sorbent trap monitoring system data to an hourly basis. [40 CFR 63.10010(g), Minn. R. 7011.0563]

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COMG 7 99

(h) If the Permittee uses a PM CPMS to demonstrate continuous compliance with an operating limit, the Permittee must install, calibrate, maintain, and operate the PM CPMS and record the output of the system as specified in Section 63.10010(h)(1) through (5).

(1) The Permittee shall install, calibrate, operate, and maintain the PM CPMS according to the procedures in the Permittee's approved site‐specific monitoring plan developed in accordance with Section 63.10000(d), and meet the requirements Section 63.10010(h)(1)(i) through (iii).(i) The operating principle of the PM CPMS must be based on in‐stack or extractive light scatter, light scintillation, beta attenuation, or mass accumulation detection of the exhaust gas or representative sample. The reportable measurement output from the PM CPMS may be expressed as milliamps, stack concentration, or other raw data signal.(ii) The PM CPMS must have a cycle time (i.e., period required to complete sampling, measurement, and reporting for each measurement) no longer than 60 minutes.

(iii) The PM CPMS must be capable, at a minimum, of detecting and responding to particulate matter concentrations of 0.5 mg/acm.

(2) For an existing unit, complete the initial performance evaluation no later than October 13, 2015.

(3) Collect PM CPMS hourly average output data for all boiler operating hours except as indicated in Section 63.10010(h)(5). Express the PM CPMS output as milliamps, PM concentration, or other raw data signal value.

(4) Calculate the arithmetic 30‐boiler operating day rolling average of all of the hourly average PM CPMS output collected during all nonexempt boiler operating hours data (e.g., milliamps, PM concentration, raw data signal). (5) The Permittee must collect data using the PM CPMS at all times the process unit is operating and at the intervals specified in Section 63.10010(h)(1)(ii), except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments), and any

COMG 7 100

(6) The Permittee must use all the data collected during all boiler operating hours in assessing the compliance with the Permittee's operating limit except:(i) Any data collected during periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, or required monitoring system quality assurance or quality control activities that temporarily interrupt the measurement of output data from the PM CPMS. The Permittee must report any monitoring system malfunctions or out of control periods in the Permittee's annual deviation reports. The Permittee must report any monitoring system quality assurance or quality control activities per the requirements of Section 63.10031(b);(ii) Any data collected during periods when the monitoring system is out of control as specified in the Permittee's site‐specific monitoring plan, repairs associated with periods when the monitoring system is out of control, or required monitoring system quality assurance or quality control activities conducted during out‐of‐control periods. The Permittee must report any such periods in the Permittee's annual deviation report;(iii) Any data recorded during periods of startup or shutdown. (7) The Permittee must record and make available upon request results of PM CPMS system performance audits, as well as the dates and duration of periods from when the PM CPMS is out of control until completion of the corrective actions necessary to return the PM CPMS to operation consistent with the Permittee's site‐specific monitoring plan. [40 CFR 63.10010(h)(6)&(7), Minn. R. 7011.0563]

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COMG 7 101

If the Permittee chooses to comply with the PM filterable emissions limit in lieu of metal HAP limits, the Permittee may choose to install, certify, operate, and maintain a PM CEMS and record the output of the PM CEMS as specified in Section 63.10010(i)(1) through (5). (The Permittee's October 2015 (Units 1, 2, and 3) and October 2016 (Unit 4) Notices of Compliance Status (located in Appendix H of this permit) indicate the Permittee has chosen to comply with the filterable PM limit and determine compliance through the use of PM CEMS on STRU13 and STRU14.) The compliance limit will be expressed as a 30‐boiler operating day rolling average of the numerical emissions limit value applicable for the Permittee's unit in Table 2 to subp. UUUUU.

(1) The Permittee shall install and certify the PM CEMS according to the procedures and requirements in Performance Specification 11—Specifications and Test Procedures for Particulate Matter Continuous Emission Monitoring Systems at Stationary Sources in Appendix B to part 60, using Method 5 at Appendix A‐3 to part 60 and ensuring that the front half filter temperature shall be 160 degrees +/‐14 degrees C (320 degrees +/‐25 degrees F). The reportable measurement output from the PM CEMS must be expressed in units of the applicable emissions limit (e.g., lb/MMBtu, lb/MWh). [40 CFR 63.10010(i)(1), Minn. R. 7011.0563]

COMG 7 102

(2) The Permittee shall operate and maintain the PM CEMS according to the procedures and requirements in Procedure 2—Quality Assurance Requirements for Particulate Matter Continuous Emission Monitoring Systems at Sta onary Sources in Appendix F to part 60 of this chapter.

(i) The Permi ee must conduct the rela ve response audit (RRA) for the PM CEMS at least once annually.

(ii) The Permittee must conduct the relative correlation audit (RCA) for the PM CEMS at least once every 3 years.

The Permittee may conduct an RCA instead of an RRA during the period when the RRA is required as stated at Part 60 Appendix F section 10.3(5). [40 CFR 63.10010(i)(2), Minn. R. 7011.0563]

COMG 7 103

(3) Collect PM CEMS hourly average output data for all boiler operating hours except as indicated in Section 63.10010(i).

(4) Calculate the arithmetic 30‐boiler operating day rolling average of all of the hourly average PM CEMS output data collected during all nonexempt boiler operating hours. [40 CFR 63.10010(i)(3)&(4), Minn. R. 7011.0563]

COMG 7 104

(5) The Permittee must collect data using the PM CEMS at all times the process unit is operating and at the intervals specified in Section 63.10010(a), except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities. (i) The Permittee must use all the data collected during all boiler operating hours in assessing the compliance with the applicable operating limit except: (A) Any data collected during monitoring system malfunctions, repairs associated with monitoring system malfunctions, or required monitoring system quality assurance or control activities conducted during monitoring system malfunctions in calculations and report any such periods in the Permittee's annual deviation report; (B) Any data collected during periods when the monitoring system is out of control as specified in the Permittee's site‐specific monitoring plan, repairs associated with periods when the monitoring system is out of control, or required monitoring system quality assurance or control activities conducted during out of control periods in calculations used to report emissions or operating levels and report any such periods in the Permittee's annual deviation report; (C) Any data recorded during periods of startup or shutdown. [40 CFR 63.10010(i)(5)(i), Minn. R. 7011.0563]

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COMG 7 105

(ii) The Permittee must record and make available upon request results of PM CEMS system performance audits, dates and duration of periods when the PM CEMS is out of control to completion of the corrective actions necessary to return the PM CEMS to operation consistent with the Permittee's site‐specific monitoring plan. [40 CFR 63.10010(i)(5)(ii), Minn. R. 7011.0563]

COMG 7 106

The Permittee may choose to comply with the metal HAP emissions limits using CEMS approved in accordance with Section 63.7(f) as an alternative to the performance test method specified in this rule. If approved to use a HAP metals CEMS, the compliance limit will be expressed as a 30‐boiler operating day rolling average of the numerical emissions limit value applicable for the Permittee's unit in table 2. If approved, the Permittee may choose to install, certify, operate, and maintain a HAP metals CEMS and record the output of the HAP metals CEMS as specified in Section 63.10010(j)(1) through (4). (1)(i) The Permittee shall install, calibrate, operate, and maintain the HAP metals CEMS according to its CMS quality control program, as described in Section 63.8(d)(2). The reportable measurement output from the HAP metals CEMS must be expressed in units of the applicable emissions limit (e.g., lb/MMBtu, lb/MWh) and in the form of a 30‐boiler operating day rolling average.(ii) The Permittee shall operate and maintain its HAP metals CEMS according to the procedures and criteria in your site specific performance evaluation and quality control program plan required in Section 63.8(d). (2) The Permittee shall collect HAP metals CEMS hourly average output data for all boiler operating hours except as indicated in Section 63.10010(j)(4). (3) The Permittee shall calculate the arithmetic 30‐boiler operating day rolling average of all of the hourly average HAP metals CEMS output data collected during all nonexempt boiler operating hours data. [40 CFR 63.10010(j)(1)‐(3), Minn. R. 7011.0563]

COMG 7 107

(4) The Permittee must collect data using the HAP metals CEMS at all times the process unit is operating and at the intervals specified in Section 63.10010(a), except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities.(i) The Permittee must use all the data collected during all boiler operating hours in assessing the compliance with its emission limit except:(A) Any data collected during periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, or required monitoring system quality assurance or quality control activities that temporarily interrupt the measurement of emissions (e.g., calibrations, certain audits). The Permittee must report any monitoring system malfunctions or out of control periods in its annual deviation reports. The Permittee must report any monitoring system quality assurance or quality control activities per the requirements of Section 63.10031(b);(B) Any data collected during periods when the monitoring system is out of control as specified in the Permittee's site‐specific monitoring plan, repairs associated with periods when the monitoring system is out of control, or required monitoring system quality assurance or quality control activities conducted during out‐of‐control periods. The Permittee must report any monitoring system malfunctions or out of control periods in its annual deviation reports. The Permittee must report any monitoring system quality assurance or quality control activities per the requirements of Section 63.10031(b);(C) Any data recorded during periods of startup or shutdown.(ii) The Permittee must record and make available upon request results of HAP metals CEMS system performance audits, dates and duration of periods when the HAP metals CEMS is out of control to completion of the corrective actions necessary to return the HAP metals CEMS to operation consistent with its site‐specific performance evaluation and quality control program plan. [40 CFR 63.10010(j)(4), Minn. R. 7011.0563]

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COMG 7 109

(a) The Permittee must demonstrate initial compliance with each applicable emissions limit by conducting performance testing. (b) If the Permittee is subject to an operating limit in Table 4 to subp. UUUUU, the Permittee demonstrates initial compliance with HAP metals or filterable PM emission limit(s) through performance stack tests and the Permittee elects to use a PM CPMS to demonstrate continuous performance, the Permittee must also establish a site‐specific operating limit, in accordance with Section 63.10007 and Table 6 to subp. UUUUU. The Permittee may use only the parametric data recorded during successful performance tests (i.e., tests that demonstrate compliance with the applicable emissions limits) to establish an operating limit. [40 CFR 63.10011(a)&(b), Minn. R. 7011.0563]

COMG 7 110

(1) If the Permittee uses CEMS or sorbent trap monitoring systems to measure a HAP (e.g., Hg or HCl) directly, the initial performance test shall consist of a 30‐boiler operating day (or, for certain coal‐fired, existing EGUs that use emissions averaging for Hg, a 90‐boiler operating day) rolling average emissions rate obtained with a certified CEMS or sorbent trap system, expressed in units of the standard. If the monitoring system is certified prior to the applicable compliance date, the initial averaging period shall either begin with: The first boiler operating day on or after the compliance date; or 30 (or, if applicable, 90) boiler operating days prior to that date, as described in Section 63.10005(b). In all cases, the initial 30‐ or 90‐boiler operating day averaging period must be completed on or before the date that compliance must be demonstrated, in accordance with Section 63.9984(f). Initial compliance is demonstrated if the results of the performance test meet the applicable emission limit in Table 2 to subp. UUUUU. (2) For an EGU that uses a CEMS to measure SO2 or PM emissions for initial compliance, the initial performance test shall consist of a 30‐boiler operating day average emission rate obtained with certified CEMS, expressed in units of the standard. If the monitoring system is certified prior to the applicable compliance date, the initial averaging period shall either begin with: The first boiler operating day on or after the compliance date; or 30 boiler operating days prior to that date, as described in Section 63.10005(b). In all cases, the initial 30‐ boiler operating day averaging period must be completed on or before the date that compliance must be demonstrated, in accordance with Section 63.9984(f). Initial compliance is demonstrated if the results of the performance test meet the applicable SO2 or PM emission limit in Table 2 to subp. UUUUU. [40 CFR 63.10011(c)(1)&(2), Minn. R. 7011.0563]

COMG 7 111

For candidate LEE units, use the results of the performance testing described in Section 63.10005(h) to determine initial compliance with the applicable emission limit(s) in Table 2 to subp. UUUUU and to determine whether the unit qualifies for LEE status. [40 CFR 63.10011(d), Minn. R. 7011.0563]

COMG 7 112

The Permittee must submit a Notification of Compliance Status containing the results of the initial compliance demonstration, in accordance with Section 63.10030(e). [40 CFR 63.10011(e), Minn. R. 7011.0563]

COMG 7 113

(1) The Permittee must determine the fuel whose combustion produces the least uncontrolled emissions, i.e., the cleanest fuel, either natural gas or distillate oil, that is available on site or accessible nearby for use during periods of startup or shutdown. (2) The Permittee's cleanest fuel, either natural gas or distillate oil, for use during periods of startup or shutdown determination may take safety considerations into account. [40 CFR 63.10011(f)(1)&(2), Minn. R. 7011.0563]

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COMG 7 114

The Permittee must follow the startup or shutdown requirements as given in Table 3 to subp. UUUUU for each coal‐fired, liquid oil‐fired, or solid oil‐derived fuel‐fired EGU. (1) The Permittee may use the diluent cap and default gross output values, as described in Section 63.10007(f), during startup periods or shutdown periods. (2) The Permittee must operate all CMS, collect data, calculate pollutant emission rates, and record data during startup periods or shutdown periods. (3) The Permittee must report the information as required in Section 63.10031. [40 CFR 63.10011(g)(1)‐(3), Minn. R. 7011.0563]

COMG 7 117

The Permittee must monitor and collect data according to Section 63.10020 and the site‐specific monitoring plan required by Section 63.10000(d). [40 CFR 63.10020(a), Minn. R. 7011.0563]

COMG 7 118

The Permittee must operate the monitoring system and collect data at all required intervals at all times that the affected EGU is operating, except for periods of monitoring system malfunctions or out‐of‐control periods (see Section 63.8(c)(7)), and required monitoring system quality assurance or quality control activities, including, as applicable, calibration checks and required zero and span adjustments. The Permittee is required to affect monitoring system repairs in response to monitoring system malfunctions and to return the monitoring system to operation as expeditiously as practicable. [40 CFR 63.10020(b), Minn. R. 7011.0563]

COMG 7 119

The Permittee may not use data recorded during EGU startup or shutdown in calculations used to report emissions, except as otherwise provided in Sections 63.10000(c)(1)(vi)(B) and 63.10005(a)(2)(iii). In addition, data recorded during monitoring system malfunctions or monitoring system out‐of‐control periods, repairs associated with monitoring system malfunctions or monitoring system out‐of‐control periods, or required monitoring system quality assurance or control activities may not be used in calculations used to report emissions or operating levels. The Permittee must use all of the quality‐assured data collected during all other periods in assessing the operation of the control device and associated control system. [40 CFR 63.10020(c), Minn. R. 7011.0563]

COMG 7 120

Except for periods of monitoring system malfunctions or monitoring system out‐of‐control periods, repairs associated with monitoring system malfunctions or monitoring system out‐of‐control periods, and required monitoring system quality assurance or quality control activities including, as applicable, calibration checks and required zero and span adjustments), failure to collect required data is a deviation from the monitoring requirements. [40 CFR 63.10020(d), Minn. R. 7011.0563]

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COMG 7 122

(3) For PM or non‐mercury HAP metals work practice monitoring during startup periods, the Permittee must monitor and collect data according to Section 63.10020 and the site‐specific monitoring plan required by Section 63.10010(l).(i) Except for an EGU that uses PM CEMS or PM CPMS to demonstrate compliance with the PM emissions limit, or that has LEE status for filterable PM or total non‐Hg HAP metals for non‐ liquid oil‐fired EGUs (or HAP metals emissions for liquid oil‐fired EGUs), or individual non‐mercury metals CEMS, the Permittee must: (A) Record temperature and combustion air flow or calculated flow as determined from combustion equations of post‐combustion (exhaust) gas, as well as amperage of forced draft fan(s), upstream of the filterable PM control devices during each hour of startup. (B) Record temperature and flow of exhaust gas, as well as amperage of any induced draft fan(s), downstream of the filterable PM control devices during each hour of startup. (C) For an EGU with an electrostatic precipitator, record the number of fields in service, as well as each field's secondary voltage and secondary current during each hour of startup. (D) For an EGU with a fabric filter, record the number of compartments in service, as well as the differential pressure across the baghouse during each hour of startup. (E) For an EGU with a wet scrubber needed for filterable PM control, record the scrubber liquid to flue gas ratio and the pressure drop across the scrubber during each hour of startup. The Permittee uses EQUI108 (PM CEMS on Unit 4/EQUI85/STRU14), and EQUI107 (PM CEMS on common stack STRU13 for Units 1, 2, and 3). [40 CFR 63.10020(e)(3), Minn. R. 7011.0563]

COMG 7 123

The Permittee must demonstrate continuous compliance with each applicable emissions limit, operating limit, and work practice standard in Tables 1 through 4 to subp. UUUUU, according to the monitoring specified in Tables 6 and 7 to subp. UUUUU and Section 63.10021(b) through (g). [40 CFR 63.10021(a), Minn. R. 7011.0563]

COMG 7 124

Except as otherwise provided in Section 63.10020(c), if the Permittee uses a CEMS to measure SO2, PM, HCl, HF, or Hg emissions, or uses a sorbent trap monitoring system to measure Hg emissions, the Permittee must demonstrate continuous compliance by using all quality‐assured hourly data recorded by the CEMS (or sorbent trap monitoring system) and the other required monitoring systems (e.g., flow rate, CO2, O2, or moisture systems) to calculate the arithmetic average emissions rate in units of the standard on a continuous 30‐boiler operating day (or, if alternate emissions averaging is used for Hg, 90‐boiler operating day) rolling average basis, updated at the end of each new boiler operating day. Use Equation 8 in Appendix E of this permit to determine the 30‐ (or, if applicable, 90‐) boiler operating day rolling average. [40 CFR 63.10021(b), Minn. R. 7011.0563]

COMG 7 125

If the Permittee uses a PM CPMS data to measure compliance with an operating limit in Table 4 to subp. UUUUU, the Permittee must record the PM CPMS output data for all periods when the process is operating and the PM CPMS is not out‐of‐control. The Permittee must demonstrate continuous compliance by using all quality‐assured hourly average data collected by the PM CPMS for all operating hours to calculate the arithmetic average operating parameter in units of the operating limit (e.g., milliamps, PM concentration, raw data signal) on a 30 operating day rolling average basis, updated at the end of each new boiler operating day. Use Equation 9 in Appendix E of this permit to determine the 30 boiler operating day average. [40 CFR 63.10021(c), Minn. R. 7011.0563]

COMG 7 126

If the Permittee uses quarterly performance testing to demonstrate compliance with one or more applicable emissions limits in Table 2 to subp. UUUUU, the Permittee (1) May skip performance testing in those quarters during which less than 168 boiler operating hours occur, except that a performance test must be conducted at least once every calendar year, and (2) Must conduct the performance test as defined in Table 5 to subp. UUUUU and calculate the results of the testing in units of the applicable emissions standard. [40 CFR 63.10021(d)(1)&(2), Minn. R. 7011.0563]

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COMG 7 127

(e) The Permittee must conduct periodic performance tune‐ups of its EGU(s), as specified in Section 63.10021(e)(1) through (9). For the first tune‐up, the Permittee may perform the burner inspection any time prior to the tune‐up or the Permittee may delay the first burner inspection until the next scheduled EGU outage provided the Permittee meets the requirements of Section 63.10005. Subsequently, the Permittee must perform an inspection of the burner at least once every 36 calendar months unless the Permittee's EGU employs neural network combustion optimization during normal operations in which case the Permittee must perform an inspection of the burner and combustion controls at least once every 48 calendar months. If the Permittee's EGU is offline when a deadline to perform the tune‐up passes, the Permittee shall perform the tune‐up work practice requirements within 30 days after the re‐start of the affected unit. (1) As applicable, inspect the burner and combustion controls, and clean or replace any components of the burner or combustion controls as necessary upon initiation of the work practice program and at least once every required inspection period. Repair of a burner or combustion control component requiring special order parts may be scheduled as follows: (i) Burner or combustion control component parts needing replacement that affect the ability to optimize NOX and CO must be installed within 3 calendar months after the burner inspection, (ii) Burner or combustion control component parts that do not affect the ability to optimize NOX and CO may be installed on a schedule determined by the operator; [40 CFR 63.10021(e)(1), Minn. R. 7011.0563]

COMG 7 128

(2) As applicable, inspect the flame pattern and make any adjustments to the burner or combustion controls necessary to optimize the flame pattern. The adjustment should be consistent with the manufacturer's specifications, if available, or in accordance with best combustion engineering practice for that burner type; (3) As applicable, observe the damper operations as a function of mill and/or cyclone loadings, cyclone and pulverizer coal feeder loadings, or other pulverizer and coal mill performance parameters, making adjustments and effecting repair to dampers, controls, mills, pulverizers, cyclones, and sensors; (4) As applicable, evaluate windbox pressures and air proportions, making adjustments and effecting repair to dampers, actuators, controls, and sensors; (5) Inspect the system controlling the air‐to‐fuel ratio and ensure that it is correctly calibrated and functioning properly. Such inspection may include calibrating excess O2 probes and/or sensors, adjusting overfire air systems, changing software parameters, and calibrating associated actuators and dampers to ensure that the systems are operated as designed. Any component out of calibration, in or near failure, or in a state that is likely to negate combustion optimization efforts prior to the next tune‐up, should be corrected or repaired as necessary; [40 CFR 63.10021(e)(2)‐(5), Minn. R. 7011.0563]

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COMG 7 129

(6) Optimize combustion to minimize generation of CO and NOX. This optimization should be consistent with the manufacturer's specifications, if available, or best combustion engineering practice for the applicable burner type. NOX optimization includes burners, overfire air controls, concentric firing system improvements, neural network or combustion efficiency software, control systems calibrations, adjusting combustion zone temperature profiles, and add‐on controls such as SCR and SNCR; CO optimization includes burners, overfire air controls, concentric firing system improvements, neural network or combustion efficiency software, control systems calibra ons, and adjus ng combus on zone temperature profiles;

(7) While operating at full load or the predominantly operated load, measure the concentration in the effluent stream of CO and NOX in ppm, by volume, and oxygen in volume percent, before and after the tune‐up 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). The Permittee may use portable CO, NOX and O2 monitors for this measurement. EGU's employing neural network optimization systems need only provide a single pre‐ and post‐tune‐up value rather than continual values before and after each optimization adjustment made by the system; [40 CFR 63.10021(e)(6)&(7), Minn. R. 7011.0563]

COMG 7 130

(8) Maintain on‐site and submit, if requested by the Administrator, an annual report containing the information in Sec on 63.10021(e)(1) through (e)(9) including:(i) The concentrations of CO and NOX in the effluent stream in ppm by volume, and oxygen in volume percent, measured before and a er an adjustment of the EGU combus on systems;

(ii) A descrip on of any correc ve ac ons taken as a part of the combus on adjustment; and (iii) The type(s) and amount(s) of fuel used over the 12 calendar months prior to an adjustment, but only if the unit was physically and legally capable of using more than one type of fuel during that period; and

(9) Report the dates of the initial and subsequent tune‐ups in hard copy, as specified in Section 63.10031(f)(5), through June 30, 2018. On or after July 1, 2018, report the date of all tune‐ups electronically, in accordance with Section 63.10031(f). The tune‐up report date is the date when tune‐up requirements in Section 63.10021(e)(6) and (7) are completed. [40 CFR 63.10021(e)(8)&(9), Minn. R. 7011.0563]

COMG 7 131

The Permittee must submit the reports required under Section 63.10031 and, if applicable, the reports required under appendices A and B to subp. UUUUU. The electronic reports required by appendices A and B to subp. UUUUU must be sent to the Administrator electronically in a format prescribed by the Administrator, as provided in Section 63.10031. CEMS data (except for PM CEMS and any approved alternative monitoring using a HAP metals CEMS) shall be submitted using EPA's Emissions Collection and Monitoring Plan System (ECMPS) Client Tool. Other data, including PM CEMS data, HAP metals CEMS data, and CEMS performance test detail reports, shall be submitted in the file format generated through use of EPA's Electronic Reporting Tool, the Compliance and Emissions Data Reporting Interface, or alternate electronic file format, all as provided for under Section 63.10031. [40 CFR 63.10021(f), Minn. R. 7011.0563]

COMG 7 132

The Permittee must report each instance in which it did not meet an applicable emissions limit or operating limit in Tables 1 through 4 to subp. UUUUU or failed to conduct a required tune‐up. These instances are deviations from the requirements of subp. UUUUU. These deviations must be reported according to Section 63.10031. [40 CFR 63.10021(g), Minn. R. 7011.0563]

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COMG 7 133

The Permittee must follow the startup or shutdown requirements as given in Table 3 to subp. UUUUU for each coal‐fired EGU. (1) The Permittee may use the diluent cap and default gross output values, as described in Section 63.10007(f), during startup periods or shutdown periods. (2) The Permittee must operate all CMS, collect data, calculate pollutant emission rates, and record data during startup periods or shutdown periods. (3) The Permittee must report the information as required in Section 63.10031. (4) The Permittee may choose to submit an alternative non‐opacity emission standard, in accordance with the requirements contained in Section 63.10011(g)(4). Until promulgation in the Federal Register of the final alternative non‐opacity emission standard, the Permittee shall comply with paragraph (1) of the definition of "startup" in Section 63.10042. [40 CFR 63.10021(h), Minn. R. 7011.0563]

COMG 7 134

(i) The Permittee must provide reports as specified in Section 63.10031 concerning activities and periods of startup and shutdown. [40 CFR 63.10021(i), Minn. R. 7011.0563]

COMG 7 135

(a) Following the compliance date, the Permittee must demonstrate compliance with subp. UUUUU on a continuous basis by meeting the requirements of Section 63.10022(a)(1) through (4). (1) For each 30‐ (or 90‐) day rolling average period, demonstrate compliance with the average weighted emissions limit for the existing units participating in the emissions averaging option as determined in Section 63.10009(f) and (g); (2) For each existing unit participating in the emissions averaging option that is equipped with PM CPMS, maintain the average parameter value at or below the operating limit established during the most recent performance test; (3) For each existing unit participating in the emissions averaging option venting to a common stack configuration containing affected units from other subcategories, maintain the appropriate operating limit for each unit as specified in Table 4 to subp. UUUUU that applies. (4) For each existing EGU participating in the emissions averaging option, operate in accordance with the startup or shutdown work practice requirements given in Table 3 to subp. UUUUU. [40 CFR 63.10022(a)(1)‐(4), Minn. R. 7011.0563]

COMG 7 136

(b) Any instance where the Permittee fails to comply with the continuous monitoring requirements in Section 63.10022(a)(1) through (3) is a deviation. [40 CFR 63.10022(b), Minn. R. 7011.0563]

COMG 7 137

(a) During the initial performance test or any such subsequent performance test that demonstrates compliance with the filterable PM, individual non‐mercury HAP metals, or total non‐mercury HAP metals limit in Table 2, record all hourly average output values (e.g., milliamps, stack concentration, or other raw data signal) from the PM CPMS for the periods corresponding to the test runs (e.g., nine 1‐hour average PM CPMS output values for three 3‐hour test runs). [40 CFR 63.10023(a), Minn. R. 7011.0563]

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COMG 7 138

(b) The Permittee shall determine its operating limit as provided in Section 63.10023(b)(2). The Permittee must verify an existing or establish a new operating limit after each repeated performance test.

(2) The Permittee shall determine its operating limit as follows:(i) If the Permittee's PM performance test demonstrates the Permittee's PM emissions do not exceed 75 percent of the Permittee's emissions limit, the Permittee will use the average PM CPMS value recorded during the PM compliance test, the milliamp equivalent of zero output from the Permittee's PM CPMS, and the average PM result of the Permittee's compliance test to establish the Permittee's operating limit. Calculate the operating limit by establishing a relationship of PM CPMS signal to PM concentration using the PM CPMS instrument zero, the average PM CPMS values corresponding to the three compliance test runs, and the average PM concentration from the Method 5 compliance test with the procedures in Section 63.10023(b)(2)(i)(A) through (D).(A) The Permittee shall determine the PM CPMS instrument zero output with one of the following procedures.(1) Zero point data for in‐situ instruments should be obtained by removing the instrument from the stack and monitoring ambient air on a test bench.(2) Zero point data for extractive instruments should be obtained by removing the extractive probe from the stack and drawing in clean ambient air.(3) The zero point can also can be obtained by performing manual reference method measurements when the flue gas is free of PM emissions or contains very low PM concentrations (e.g., when the Permittee's process is not operating, but the fans are operating or the Permittee's source is combusting only natural gas) and plotting these with the compliance data to find the zero intercept.(4) If none of the steps in paragraphs (A)(1) through (3) of Section 63.10021(b)(2)(i) are possible, the Permittee must use a zero output value provided by the manufacturer. [40 CFR 63.10023(b)(2)(i)(A), Minn. R. 7011.0563]

COMG 7 139

(B) The Permittee shall determine its PM CPMS instrument average (x) in milliamps, and the average of its corresponding three PM compliance test runs (y), using equa on 10 in Appendix E of this permit. (C) With the Permittee's PM CPMS instrument zero expressed in milliamps, the Permittee's three run average PM CPMS milliamp value, and the Permittee's three run average PM emissions value (in lb/MWh) from the Permittee's compliance runs, determine a relationship of PM lb/MWh per milliamp with equation 11 in Appendix E of this permit. (D) The Permittee shall determine its source specific 30‐day rolling average operating limit using the PM lb/MWh per milliamp value from equation 11 in equation 12 in Appendix E of this permit. This sets the Permittee's operating limit at the PM CPMS output value corresponding to 75 percent of the Permittee's emission limit. [40 CFR 63.10023(b)(2)(i)(B)‐(D), Minn. R. 7011.0563]

COMG 7 140

(ii) If the Permittee's PM compliance test demonstrates PM emissions exceed 75 percent of the Permittee's emissions limit, the Permittee will use the average PM CPMS value recorded during the PM compliance test demonstra ng compliance with the PM limit to establish the Permi ee's opera ng limit.

(A) The Permittee shall determine its operating limit by averaging the PM CPMS milliamp output corresponding to its three PM performance test runs that demonstrate compliance with the emission limit using equation 13 in Appendix E of this permit. [40 CFR 63.10023(b)(2)(ii), Minn. R. 7011.0563]

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COMG 7 141

(iii) The Permittee's PM CPMS must provide a 4‐20 milliamp output and the establishment of its relationship to manual reference method measurements must be determined in units of milliamps.

(iv) The Permittee's PM CPMS operating range must be capable of reading PM concentrations from zero to a level equivalent to two times its allowable emission limit. If the Permittee's PM CPMS is an auto‐ranging instrument capable of multiple scales, the primary range of the instrument must be capable of reading PM concentration from zero to a level equivalent to two times the Permittee's allowable emission limit.

(v) During the initial performance test or any such subsequent performance test that demonstrates compliance with the PM limit, record and average all milliamp output values from the PM CPMS for the periods corresponding to the compliance test runs.(vi) For PM performance test reports used to set a PM CPMS operating limit, the electronic submission of the test report must also include the make and model of the PM CPMS instrument, serial number of the instrument, analytical principle of the instrument (e.g. beta attenuation), span of the instruments primary analytical range, milliamp value equivalent to the instrument zero output, technique by which this zero value was determined, and the average milliamp signal corresponding to each PM compliance test run. [40 CFR 63.10023(b)(2)(iii)‐(vi), Minn. R. 7011.0563]

COMG 7 143

(a) The Permittee must submit all of the applicable notifications in Sections 63.7(b) and (c), 63.8(e), (f)(4) and (6), and 63.9(b) through (h) by the dates specified. (b) As specified in Section 63.9(b)(2), if the Permittee starts up the EGU that is an affected source before April 16, 2012, the Permittee must submit an Initial Notification not later than 120 days after April 16, 2012. [40 CFR 63.10030(a)&(b), Minn. R. 7011.0563]

COMG 7 144

(d) When the Permittee is required to conduct a performance test, the Permittee must submit a Notification of Intent to conduct a performance test at least 30 days before the performance test is scheduled to begin. [40 CFR 63.10030(d), Minn. R. 7011.0563]

COMG 7 145

(e) When the Permittee is required to conduct an initial compliance demonstration as specified in Section 63.10011(a), the Permittee must submit a Notification of Compliance Status according to Section 63.9(h)(2)(ii). The Notification of Compliance Status report must contain all the information specified in Section 63.10030(e)(1) through (8), as applicable. (1) A description of the affected source(s), including identification of the subcategory of the source, the design capacity of the source, a description of the add‐on controls used on the source, description of the fuel(s) burned, including whether the fuel(s) were determined by you or EPA through a petition process to be a non‐waste under 40 CFR 241.3, whether the fuel(s) were processed from discarded non‐hazardous secondary materials within the meaning of 40 CFR 241.3, and justification for the selection of fuel(s) burned during the performance test. (2) Summary of the results of all performance tests and fuel analyses and calculations conducted to demonstrate initial compliance including all established operating limits. [40 CFR 63.10030(e)(1)&(2), Minn. R. 7011.0563]

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COMG 7 146

(3) Identification of whether the Permittee plans to demonstrate compliance with each applicable emission limit through performance testing; fuel moisture analyses; performance testing with operating limits (e.g., use of PM CPMS); CEMS; or a sorbent trap monitoring system. (4) Identification of whether the Permittee plans to demonstrate compliance by emissions averaging. (5) A signed certification that the Permittee has met all applicable emission limits and work practice standards. (6) If the Permittee had a deviation from any emission limit, work practice standard, or operating limit, the Permittee must also submit a brief description of the deviation, the duration of the deviation, emissions point identification, and the cause of the deviation in the Notification of Compliance Status report. [40 CFR 63.10030(e)(3)‐(6), Minn. R. 7011.0563]

COMG 7 147

(7) In addition to the information required in Section 63.9(h)(2), the Permittee's notification of compliance status must include the following: (i) A summary of the results of the annual performance tests and documentation of any operating limits that were reestablished during this test, if applicable. If the Permittee is conducting stack tests once every 3 years consistent with Section 63.10005(h)(1)(i), the date of each stack test conducted during the previous 3 years, a comparison of emission level the Permittee achieved in each stack test conducted during the previous 3 years to the 50 percent emission limit threshold required in Section 63.10006(i), and a statement as to whether there have been any operational changes since the last stack test that could increase emissions. (ii) Certifications of compliance, as applicable, and must be signed by a responsible official stating: (A) "This EGU complies with the requirements in Section 63.10021(a) to demonstrate continuous compliance." and (B) "No secondary materials that are solid waste were combusted in any affected unit.". [40 CFR 63.10030(e)(7)(i)&(ii), Minn. R. 7011.0563]

COMG 7 148

(iii) For each of the Permittee's existing EGUs, identification of each emissions limit as specified in Table 2 to subp. UUUUU with which the Permittee plans to comply. (A) The Permittee may switch from a mass per heat input to a mass per gross output limit (or vice‐versa), provided that: (1) The Permittee submits a request that identifies for each EGU or EGU emissions averaging group involved in the proposed switch both the current and proposed emission limit; (2) The Permittee's request arrives to the Administrator at least 30 calendar days prior to the date that the switch is proposed to occur; (3) The Permittee's request demonstrates through performance stack test results completed within 30 days prior to the Permittee's submission, compliance for each EGU or EGU emissions averaging group with both the mass per heat input and mass per gross output limits; (4) The Permittee revises and submits all other applicable plans, e.g., monitoring and emissions averaging, with your request; and (5) The Permittee maintains records of all information regarding its choice of emission limits. (B) The Permittee begins to use the revised emission limits starting in the next reporting period, after receipt of written acknowledgement from the Administrator of the switch. (C) From submission of the Permittee's request until start of the next reporting period after receipt of written acknowledgement from the Administrator of the switch, the Permittee demonstrates compliance with both the mass per heat input and mass per gross output emission limits for each pollutant for each EGU or EGU emissions averaging group. [40 CFR 63.10030(e)(7)(iii), Minn. R. 7011.0563]

COMG 7 149

(8) Identification of whether the Permittee plans to rely on paragraph (1) or (2) of the definition of "startup" in Section 63.10042. [40 CFR 63.10030(e)(8), Minn. R. 7011.0563]

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COMG 7 150

(iii) The Permittee may switch from paragraph (1) of the definition of "startup" in Section 63.10042 to paragraph (2) of the defini on of "startup" (or vice‐versa), provided that:(A) The Permittee submits a request that identifies for each EGU or EGU emissions averaging group involved in the proposed switch both the current definition of "startup" relied on and the proposed definition the Permi ee plans to rely on;(B) The Permittee's request arrives to the Administrator at least 30 calendar days prior to the date that the switch is proposed to occur;(C) The Permittee revises and submits all other applicable plans, e.g., monitoring and emissions averaging, with its submission;

(D) The Permi ee maintains records of all informa on regarding its choice of the defini on of "startup"; and(E) The Permittee begins to use the revised definition of "startup" in the next reporting period after receipt of written acknowledgement from the Administrator of the switch. [40 CFR 63.10030(e)(8)(iii), Minn. R. 7011.0563]

COMG 7 151

The Permittee must submit the notifications in Section 63.10000(h)(2) and (i)(2) that may apply to the Permittee by the dates specified. [40 CFR 63.10030(f), Minn. R. 7011.0563]

COMG 7 152

The Permittee must submit each applicable report in Table 8 to subp. UUUUU. If the Permittee is required to (or elects to) continuously monitor Hg and/or HCl and/or HF emissions, the Permittee must also submit the electronic reports required under appendix A and/or appendix B to subp. UUUUU, at the specified frequency. [40 CFR 63.10031(a), Minn. R. 7011.0563]

COMG 7 153

(b) Unless the Administrator has approved a different schedule for submission of reports under Section 63.10(a), the Permittee must submit each report by the date in Table 8 to subp. UUUUU and according to the requirements in Section 63.10031(b)(1) through (5). (1) The first compliance report must cover the period beginning on the compliance date that is specified for the Permittee's affected source in Section 63.9984 and ending on June 30 or December 31, whichever date is the first date that occurs at least 180 days after the compliance date that is specified for the Permittee's source in Section 63.9984. (2) The first compliance report must be postmarked or submitted electronically no later than July 31 or January 31, whichever date is the first date following the end of the first calendar half after the compliance date that is specified for the Permittee's source in Section 63.9984. [40 CFR 63.10031(b)(1)&(2), Minn. R. 7011.0563]

COMG 7 154

(3) Each subsequent compliance report must cover the semiannual reporting period from January 1 through June 30 or the semiannual reporting period from July 1 through December 31. (4) Each subsequent compliance report must be postmarked or submitted electronically no later than July 31 or January 31, whichever date is the first date following the end of the semiannual reporting period. (5) For each affected source that is subject to permitting regulations pursuant to part 70 or part 71 of this chapter, and if the permitting authority has established dates for submitting semiannual reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), the Permittee may submit the first and subsequent compliance reports according to the dates the permitting authority has established instead of according to the dates in Section 63.10031(b)(1) through (4). [40 CFR 63.10031(b)(3)‐(5), Minn. R. 7011.0563]

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COMG 7 155

(c) The compliance report must contain the information required in Section 63.10031(c)(1) through (9). (1) The information required by the summary report located in Section 63.10(e)(3)(vi). (2) The total fuel use by each affected source subject to an emission limit, for each calendar month within the semiannual reporting period, including, but not limited to, a description of the fuel, whether the fuel has received a non‐waste determination by EPA or your basis for concluding that the fuel is not a waste, and the total fuel usage amount with units of measure. (3) Indicate whether the Permittee burned new types of fuel during the reporting period. If the Permittee did burn new types of fuel the Permittee must include the date of the performance test where that fuel was in use. (4) Include the date of the most recent tune‐up for each EGU. The date of the tune‐up is the date the tune‐up provisions specified in Section 63.10021(e)(6) and (7) were completed. [40 CFR 63.10031(c)(1)‐(4), Minn. R. 7011.0563]

COMG 7 157

(6) The Permittee must report emergency bypass information annually from EGUs with LEE status. (7) A summary of the results of the annual performance tests and documentation of any operating limits that were reestablished during the test, if applicable. If the Permittee is conducting stack tests once every 3 years to maintain LEE status, consistent with Section 63.10006(b), the date of each stack test conducted during the previous 3 years, a comparison of emission level the Permittee achieved in each stack test conducted during the previous 3 years to the 50 percent emission limit threshold required in Section 63.10005(h)(1)(i), and a statement as to whether there have been any operational changes since the last stack test that could increase emissions. (8) A certification. (9) If the Permittee has a deviation from any emission limit, work practice standard, or operating limit, it must also submit a brief description of the deviation, the duration of the deviation, emissions point identification, and the cause of the deviation. [40 CFR 63.10031(c)(6)‐(9), Minn. R. 7011.0563]

COMG 7 158

For each excess emissions occurring at an affected source where the Permittee is using a CMS to comply with that emission limit or operating limit, the Permittee must include the information required in Section 63.10(e)(3)(v) in the compliance report specified in Section 63.10031(c). [40 CFR 63.10031(d), Minn. R. 7011.0563]

COMG 7 159

Each affected source that has obtained a Title V operating permit pursuant to part 70 or part 71 of this chapter must report all deviations as defined in this subpart in the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A). If an affected source submits a compliance report pursuant to Table 8 to subp. UUUUU along with, or as part of, the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), and the compliance report includes all required information concerning deviations from any emission limit, operating limit, or work practice requirement in subp. UUUUU, submission of the compliance report satisfies any obligation to report the same deviations in the semiannual monitoring report. Submission of a compliance report does not otherwise affect any obligation the affected source may have to report deviations from permit requirements to the permit authority. [40 CFR 63.10031(e), Minn. R. 7011.0563]

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COMG 7 160

On or after July 1, 2018, within 60 days after the date of completing each performance test, the Permittee must submit the performance test reports required by subp. UUUUU to the EPA's WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through the EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). Performance test data must be submitted in the file format generated through use of EPA's Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html). Only data collected using those test methods on the ERT Web site are subject to this requirement for submitting reports electronically to WebFIRE. If the Permittee claims that some of the information being submitted for performance tests is confidential business information (CBI), the Permittee must submit a complete ERT file including information claimed to be CBI on a compact disk or other commonly used electronic storage media (including, but not limited to, flash drives) to EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404‐02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be submitted to EPA via CDX as described earlier in Section 63.10031(f). At the discretion of the delegated authority, the Permittee must also submit these reports, including the confidential business information, to the delegated authority in the format specified by the delegated authority. [40 CFR 63.10031(f), Minn. R. 7011.0563]

COMG 7 161

(1) On or after July 1, 2018, within 60 days after the date of completing each CEMS (SO2, PM, HCl, HF, and Hg) performance evaluation test, as defined in Section 63.2 and required by subp. UUUUU, the Permittee must submit the relative accuracy test audit (RATA) data (or, for PM CEMS, RCA and RRA data) required by subp. UUUUU to EPA's WebFIRE database by using CEDRI that is accessed through EPA's CDX (www.epa.gov/cdx). The RATA data shall be submitted in the file format generated through use of EPA's Electronic Reporting Tool (ERT) (http://www.epa.gov/ttn/chief/ert/index.html). Only RATA data compounds listed on the ERT Web site are subject to this requirement. If the Permittee claims that some of the information being submitted for RATAs is confidential business information (CBI), the Permittee shall submit a complete ERT file including information claimed to be CBI on a compact disk or other commonly used electronic storage media (including, but not limited to, flash drives) by registered letter to EPA and the same ERT file with the CBI omitted to EPA via CDX as described earlier in this paragraph. The compact disk or other commonly used electronic storage media shall be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404‐02, 4930 Old Page Rd., Durham, NC 27703. At the discretion of the delegated authority, the Permittee shall also submit these RATAs to the delegated authority in the format specified by the delegated authority. The Permittee shall submit calibration error testing, drift checks, and other information required in the performance evalua on as described in Sec on 63.2 and as required in this chapter.

(1) On or after July 1, 2018, within 60 days after the date of completing each CEMS (SO2, PM, HCl, HF, and Hg) performance evaluation test, as defined in Section 63.2 and required by subp. UUUUU, the Permittee must submit the relative accuracy test audit (RATA) data (or, for PM CEMS, RCA and RRA data) required by subp. UUUUU to EPA's WebFIRE database by using CEDRI that is accessed through EPA's CDX (www.epa.gov/cdx). [40 CFR 63.10031(f)(1), Minn. R. 7011.0563]

COMG 7 162

(2) On or after July 1, 2018, for a PM CEMS, PM CPMS, or approved alternative monitoring using a HAP metals CEMS, within 60 days after the reporting periods ending on March 31st, June 30th, September 30th, and December 31st, the Permittee must submit quarterly reports to the EPA's WebFIRE database by using the CEDRI that is accessed through the EPA's CDX (www.epa.gov/cdx). The Permittee must use the appropriate electronic reporting form in CEDRI or provide an alternate electronic file consistent with EPA's reporting form output format. For each reporting period, the quarterly reports must include all of the calculated 30‐boiler operating day rolling average values derived from the CEMS and PM CPMS. [40 CFR 63.10031(f)(2), Minn. R. 7011.0563]

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COMG 7 163

(3) Reports for an SO2 CEMS, a Hg CEMS or sorbent trap monitoring system, an HCl or HF CEMS, and any supporting monitors for such systems (such as a diluent or moisture monitor) shall be submitted using the ECMPS Client Tool, as provided for in Appendices A and B to subp. UUUUU and Sec on 63.10021(f).

(4) On or after July 1, 2018, submit the compliance reports required under paragraphs (c) and (d) of Section 63.10031(f) and the notification of compliance status required under Section 63.10030(e) to the EPA's WebFIRE database by using the CEDRI that is accessed through the EPA's CDX (www.epa.gov/cdx). The Permittee must use the appropriate electronic reporting form in CEDRI or provide an alternate electronic file consistent with EPA's repor ng form output format.

(5) All reports required by subp. UUUUU not subject to the requirements in Section 63.10031(f) introductory text and Section 63.10031(f)(1) through (f)(4) must be sent to the Administrator at the appropriate address listed in Section 63.13. If acceptable to both the Administrator and the Permittee, these reports may be submitted on electronic media. The Administrator retains the right to require submittal of reports subject to 63.10031(f) introductory text and (f)(1) through (4) in paper format. [40 CFR 63.10031(f)(3)‐(5), Minn. R. 7011.0563]

COMG 7 164

(6) Prior to July 1, 2018, all reports subject to electronic submittal in Section 63.10031(f) introductory text, (f)(1), (2), and (4) shall be submitted to the EPA at the frequency specified in those paragraphs in electronic portable document format (PDF) using the ECMPS Client Tool. Each PDF version of a submitted report must include sufficient information to assess compliance and to demonstrate that the testing was done properly. The following data elements must be entered into the ECMPS Client Tool at the me of submission of each PDF file: (i) The facility name, physical address, mailing address (if different from the physical address), and county; (ii) The ORIS code (or equivalent ID number assigned by EPA's Clean Air Markets Division (CAMD)) and the Facility Registry System (FRS) ID; (iii) The EGU (or EGUs) to which the report applies. Report the EGU IDs as they appear in the CAMD Business System; (iv) If any of the EGUs in Section 63.10031(f)(6)(iii) share a common stack, indicate which EGUs share the stack. If emissions data are monitored and reported at the common stack according to part 75, report the ID number of the common stack as it is represented in the electronic monitoring plan required under Sec on 75.53; [40 CFR 63.10031(f)(6), Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

COMG 7 164

(Cont. from above)(v) If any of the EGUs described in Section 63.10031(f)(6)(iii) are in an averaging plan under Section 63.10009, indicate which EGUs are in the plan and whether it is a 30‐ or 90‐day averaging plan;

(vi) The identification of each emission point to which the report applies. An "emission point" is a point at which source effluent is released to the atmosphere, and is either a dedicated stack that serves one of the EGUs identified in Section 63.10031(f)(6)(iii) or a common stack that serves two or more of those EGUs. To identify an emission point, associate it with the EGU or stack ID in the CAMD Business system or the electronic monitoring plan (e.g., "Unit 2 stack," "common stack CS001," or "multiple stack MS001");

(vii) The rule citation (e.g., Section 63.10031(f)(1), Section 63.10031(f)(2), etc.) for which the report is showing compliance;

(viii) The pollutant(s) being addressed in the report;

(ix) The reporting period being covered by the report (if applicable);

(x) The relevant test method that was performed for a performance test (if applicable);

(xi) The date the performance test was conducted (if applicable); and

(xii) The responsible official's name, title, and phone number. [40 CFR 63.10031(f)(6), Minn. R. 7011.0563]

COMG 7 165

If the Permittee's affected facility had a malfunction during the reporting period, the compliance report must include the number, duration, and a brief description for each type of malfunction which occurred during the reporting period and which caused or may have caused any applicable emission limitation to be exceeded. [40 CFR 63.10031(g), Minn. R. 7011.0563]

COMG 7 166

(a) The Permittee must keep records according to Section 63.10032(a)(1) and (2). If the Permittee is required to (or elects to) continuously monitor Hg and/or HCl and/or HF emissions, the Permittee must also keep the records required under appendix A and/or appendix B to subp. UUUUU. (1) A copy of each notification and report the Permittee submitted to comply with subp. UUUUU, including all documentation supporting any Initial Notification or Notification of Compliance Status or semiannual compliance report the Permi ee submi ed, according to the requirements in Sec on 63.10(b)(2)(xiv). (2) Records of performance stack tests, fuel analyses, or other compliance demonstrations and performance evaluations, as required in Section 63.10(b)(2)(viii). [40 CFR 63.10032(a), Minn. R. 7011.0563]

COMG 7 167

(b) For each CEMS and CPMS, the Permittee must keep records according to Section 63.10032(b)(1) through (4). (1) Records described in Section 63.10(b)(2)(vi) through (xi). (2) Previous (i.e., superseded) versions of the performance evaluation plan as required in Section 63.8(d)(3). (3) Request for alternatives to relative accuracy test for CEMS as required in Section 63.8(f)(6)(i). (4) Records of the date and time that each deviation started and stopped, and whether the deviation occurred during a period of startup, shutdown, or malfunction or during another period. [40 CFR 63.10032(b)(1)‐(4), Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

COMG 7 168

The Permittee must keep the records required in Table 7 to subp. UUUUU including records of all monitoring data and calculated averages for applicable PM CPMS operating limits to show continuous compliance with each applicable emission limit and operating limit. [40 CFR 63.10032(c), Minn. R. 7011.0563]

COMG 7 169

(d) For each EGU subject to an emission limit, the Permittee must also keep the records in Section 63.10032(d)(1) through (3).

(1) The Permittee must keep records of monthly fuel use by each EGU, including the type(s) of fuel and amount(s) used.

(2) If the Permittee combusts non‐hazardous secondary materials that have been determined not to be solid waste pursuant to 40 CFR 241.3(b)(1), the Permittee must keep a record which documents how the secondary material meets each of the legitimacy criteria. If the Permittee combusts a fuel that has been processed from a discarded non‐hazardous secondary material pursuant to 40 CFR 241.3(b)(2), the Permittee must keep records as to how the operations that produced the fuel satisfies the definition of processing in 40 CFR 241.2. If the fuel received a non‐waste determination pursuant to the petition process submitted under 40 CFR 241.3(c), the Permi ee must keep a record which documents how the fuel sa sfies the requirements of the pe on process.

(3) For an EGU that qualifies as an LEE under Section 63.10005(h), the Permittee must keep annual records that document that its emissions in the previous stack test(s) continue to qualify the unit for LEE status for an applicable pollutant, and document that there was no change in source operations including fuel composition and operation of air pollution control equipment that would cause emissions of the pollutant to increase within the past year. [40 CFR 63.10032(d), Minn. R. 7011.0563]

COMG 7 170

If the Permittee elects to average emissions consistent with Section 63.10009, the Permittee must additionally keep a copy of the emissions averaging implementation plan required in Section 63.10009(g), all calculations required under Section 63.10009, including daily records of heat input or steam generation, as applicable, and monitoring records consistent with Section 63.10022. [40 CFR 63.10032(e), Minn. R. 7011.0563]

COMG 7 171

(f) Regarding startup periods or shutdown periods:

(1) If the Permittee chooses to rely on paragraph (1) of the definition of "startup" in Section 63.10042 for its EGU, the Permittee must keep records of the occurrence and duration of each startup or shutdown. [40 CFR 63.10032(f)(1), Minn. R. 7011.0563]

COMG 7 172

The Permittee must keep records of the occurrence and duration of each malfunction of an operation (i.e., process equipment) or the air pollution control and monitoring equipment. [40 CFR 63.10032(g), Minn. R. 7011.0563]

COMG 7 173

The Permittee must keep records of actions taken during periods of malfunction to minimize emissions in accordance with Section 63.10000(b), including corrective actions to restore malfunctioning process and air pollution control and monitoring equipment to its normal or usual manner of operation. [40 CFR 63.10032(h), Minn. R. 7011.0563]

COMG 7 174

The Permittee must keep records of the type(s) and amount(s) of fuel used during each startup or shutdown. [40 CFR 63.10032(i), Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

COMG 7 175

(a) The Permittee's records must be in a form suitable and readily available for expeditious review, according to Section 63.10(b)(1). (b) As specified in Section 63.10(b)(1), the Permittee must keep each record for 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. (c) The Permittee must keep each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to Section 63.10(b)(1). The Permittee can keep the records off site for the remaining 3 years. [40 CFR 63.10033(a)‐(c), Minn. R. 7011.0563]

COMG 7 176

Terms used in Part 63, Subpart UUUUU are defined in the Clean Air Act, in 40 CFR Section 63.2 (the General Provisions), and in 40 CFR Section 63.10042. [40 CFR 63.10042, Minn. R. 7011.0563]

COMG 7 177

PART 63, SUBPART A GENERAL PROVISIONS

Table 9 to subp. UUUUU shows which parts of the General Provisions in Sections 63.1 through 63.15 apply to the Permittee. [40 CFR 63.10040, Minn. R. 7011.0563]

COMG 7 178

PART 63, SUBPART A GENERAL PROVISIONS

The General Provisions requirements listed below are most of the applicable requirements from pt. 63, subp. A. However, additional requirements at pt. 63, subp. A may also apply to the facility EGUs, and it is the responsibility of the Permittee to meet all applicable requirements. [Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 7 179

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; (2) The use of gaseous diluents to achieve compliance with a relevant standard for visible emissions. [40 CFR 63.4(b), Minn. R. 7011.7000]

COMG 7 180

After the February 16, 2012 effective date of pt. 63, subp. UUUUU, equipment added (or a process change) to an affected source that is within the scope of the definition of affected source under subp. UUUUU must be considered part of the affected source and subject to all provisions of subp. UUUUU. [40 CFR 63.5(b)(6), Minn. R. 7011.7000]

COMG 7 181

Methods for determining compliance. (i) The Administrator will determine compliance with nonopacity emission standards in pt. 63, subp. UUUUU based on the results of performance tests conducted according to the procedures in Section 63.7, unless otherwise specified in pt. 63, subp. UUUUU. (ii) The Administrator will determine compliance with nonopacity emission standards in pt. 63, subp. UUUUU by evaluation of the Permittee's conformance with operation and maintenance requirements, including the evaluation of monitoring data as specified in pt. 63, subp. UUUUU. (iii) If an affected source conducts performance testing at startup to obtain an operating permit in the State in which the source is located, the results of such testing may be used to demonstrate compliance with a relevant standard if— (A) The performance test was conducted within a reasonable amount of time before the initial performance test required by pt. 63, subp. UUUUU; (B) The performance test was conducted under representative operating conditions for the source; (C) The performance test was conducted and the resulting data were reduced using EPA‐approved test methods and procedures, as specified in Section 63.7(e), except requirements at Section 63.7(e)(1) are replaced by requirements at Section 63.10007; and (D) The performance test was appropriately quality‐assured, as specified in Section 63.7(c). (iv) The Administrator will determine compliance with design, equipment, work practice, or operational emission standards in this part by review of records, inspection of the source, and other procedures specified in pt. 63, subp. UUUUU. (v) The Administrator will determine compliance with design, equipment, work practice, or operational emission standards in pt. 63 by evaluation of the Permittee's conformance with operation and maintenance requirements, as specified in pt. 63, subp. UUUUU. [40 CFR 63.6(f)(2), Minn. R. 7011.7000]

Subject

Item ID

Sequence

Number Requirement

COMG 7 182

Finding of compliance. The Administrator will make a finding concerning the Permittee's affected source's compliance with a non‐opacity emission standard, as specified in Section 63.6(f)(2), upon obtaining all the compliance information required by pt. 63, subp. UUUUU (including the written reports of performance test results, monitoring results, and other information, if applicable). [40 CFR 63.6(f)(3), Minn. R. 7011.7000]

COMG 7 183

The Permittee may establish the use of an alternative non‐opacity emission standard by following the procedure specified in 40 CFR Section 63.6(g). [40 CFR 63.6(g), Minn. R. 7011.7000]

COMG 7 184

Except as provided in Section 63.7(a)(4), and unless a waiver of performance testing is obtained under Section 63.7 or the conditions of Section 63.7(c)(3)(ii)(B) apply, the Permittee must perform tests required by pt. 63, subp. UUUUU no later than 180 days after April 16, 2015. This requirement was completed and the Notice of Compliance Status was submitted to the EPA Emissions Collection and Monitoring Plan System on October 13, 2015. [40 CFR 63.7(a)(2), Minn. R. 7017.2015]

COMG 7 185

Notification of performance test. (1) The Permittee must notify the Administrator in writing of its intention to conduct a performance test at least 60 calendar days before the performance test is initially scheduled to begin to allow the Administrator, upon request, to review an approve the site‐specific test plan required under Section 63.7(c) and to have an observer present during the test. (2) In the event the Permittee is unable to conduct the performance test on the date specified in the notification requirement specified in Section 63.7(b)(1) due to unforeseeable circumstances beyond the Permittee's control, the Permittee must notify the Administrator as soon as practicable and without delay prior to the scheduled performance test date and specify the date when the performance test is rescheduled. This notification of delay in conducting the performance test shall not relieve the Permittee of legal responsibility for compliance with any other applicable provisions of pt. 63 or with any other applicable Federal, State, or local requirement, nor will it prevent the Administrator from implementing or enforcing this part or taking any other action under the Act. [40 CFR 63.7(b)(1)&(2), Minn. R. 7017.2015]

COMG 7 186

Submission of site‐specific test plan. Before conducting a required performance test, the Permittee shall develop and, if requested by the Commissioner or the Administrator, shall submit a site‐specific test plan for approval in accordance with the requirements of 40 CFR Section 63.7(c)(2). [40 CFR 63.7(c)(2), Minn. R. 7017.2015]

COMG 7 187

Approval of site‐specific test plan. The Administrator will notify the Permittee of approval or intention to deny approval of the site‐specific test plan (if review of the site‐specific test plan is requested) within 30 calendar days after receipt of the original plan and within 30 calendar days after receipt of any supplementary information. Test plan disapproval or lack of approval/disapproval is subject to additional requirements at Section 63.7(c)(3). [40 CFR 63.7(c)(3), Minn. R. 7017.2015]

COMG 7 188

Performance testing facilities. The Permittee, at the request of the Commissioner or the Administrator, shall provide performance testing facilities as specified in 40 CFR Section 63.7(d). [40 CFR 63.7(d), Minn. R. 7017.2015]

COMG 7 189

Conduct of performance tests. 1) Performance tests shall be conducted under conditions specified by the Administrator based on representative performance of the affected source. Operations during periods of startup, shutdown, and malfunction shall not constitute representative conditions for the purpose of a performance test. 2) Performance tests shall be conducted and data shall be reduced in accordance with the test methods and procedures set forth in 40 CFR Section 63.7(e), in each relevant standard, and, if required, in applicable appendices of 40 CFR parts 51, 60, 61. The Commissioner has delegation to approve a minor or intermediate modification (if validated by Method 301) to a reference method or specified monitoring procedure as allowed for in 40 CFR Section 63.7(e)(2)(i) and (ii). [40 CFR 63.7(e)(1)&(2), Minn. R. 7017.2015]

COMG 7 190

Unless otherwise specified in a relevant standard or test method, each performance test shall consist of three separate runs using the applicable test method. Each run shall be conducted for the time and under the conditions specified in the relevant standard. For the purpose of determining compliance with a relevant standard, the arithmetic mean of the results of the three runs shall apply, unless otherwise approved in accordance with provisions of Section 63.7(e)(3). [40 CFR 63.7(e)(3), Minn. R. 7017.2015]

Subject

Item ID

Sequence

Number Requirement

COMG 7 191

Data analysis, recordkeeping, and reporting. Unless otherwise specified in a relevant standard or test method, or as otherwise approved by the Commissioner or Administrator in writing, results of a performance test shall include the analysis of samples, determination of emissions, and raw data. A performance test is “completed” when field sample collection is terminated. The Permittee shall report the results of the performance test to the Commissioner or Administrator before the close of business on the 60th day following the completion of the performance test, unless specified otherwise in a relevant standard or as approved otherwise in writing. The results of the performance test shall be submitted as part of the notification of compliance status required under Section 63.9(h) to the appropriate permitting authority. [40 CFR 63.7(g), Minn. R. 7017.2015]

COMG 7 192

Waiver of performance tests. Until a waiver of a performance testing requirement has been granted by the Commissioner or the Administrator under Section 63.7(h), the Permittee remains subject to the requirements of Section 63.7(h). Additional procedures and requirements for performance test waivers are specified in Section 63.7(h). [40 CFR 63.7(h), Minn. R. 7017.2015]

COMG 7 193

For the purposes of pt. 63, all CMS required under relevant standards shall be subject to the provisions of Section 63.8 upon promulgation of performance specifications for CMS as specified in the relevant standard or otherwise by the Administrator. [40 CFR 63.8(a)(2), Minn. R. 7017.1010]

COMG 7 194

Conduct of monitoring. (1) Monitoring shall be conducted as set forth in Section 63.8 and the relevant standard(s) unless the Administrator approves otherwise according to Section 63.8(b)(1). [40 CFR 63.8(b)(1), Minn. R. 7017.1010]

COMG 7 195

Operation and maintenance of continuous monitoring systems. (1) The Permittee shall maintain and operate each CMS as specified in Section 63.8, or in a relevant standard, and in a manner consistent with good air pollution control practices. (ii) The Permittee must keep the necessary parts for routine repairs of the affected CMS equipment readily available. (2)(i) All CMS must be installed such that representative measures of emissions or process parameters from the affected source are obtained. In addition, CEMS must be located according to procedures contained in the applicable performance specification(s). (ii) Unless subp. UUUUU states otherwise, the Permittee must ensure the read out (that portion of the CMS that provides a visual display or record), or other indication of operation, from any CMS required for compliance with the emission standard is readily accessible on site for operational control or inspection by the operator of the equipment. (3) All CMS shall be installed, operational, and the data verified as specified in subp. UUUUU either prior to or in conjunction with conducting performance tests under Section 63.7. Verification of operational status shall, at a minimum, include completion of the manufacturer's written specifications or recommendations for installation, operation, and calibration of the system. (4) Except for system breakdowns, out‐of‐control periods, repairs, maintenance periods, calibration checks, and zero (low‐level) and high‐level calibration drift adjustments, all CMS, including COMS and CEMS, shall be in continuous operation and shall meet minimum frequency of operation requirements as follows: (i) All COMS shall complete a minimum of one cycle of sampling and analyzing for each successive 10‐second period and one cycle of data recording for each successive 6‐minute period. (ii) All CEMS for measuring emissions other than opacity shall complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15‐minute period. (5) Unless otherwise approved by the Administrator, minimum procedures for COMS shall include a method for producing a simulated zero opacity condition and an upscale (high‐level) opacity condition using a certified neutral density filter or other related technique to produce a known obscuration of the light beam. Such procedures shall provide a system check of all the analyzer's internal optical surfaces and all electronic circuitry, including the lamp and photodetector assembly normally used in the measurement of opacity. [40 CFR 63.8(c)(1)‐(5), Minn. R. 7017.1010]

Subject

Item ID

Sequence

Number Requirement

COMG 7 196

For a CMS that is not a CPMS, which is installed in accordance with the provisions of this part and the applicable CMS performance specification(s), the Permittee must check the zero (low‐level) and high‐level calibration drifts at least once daily in accordance with the written procedure specified in the performance evaluation plan developed under Section 63.8(e)(3)(i) and (ii). The zero (low‐level) and high‐level calibration drifts must be adjusted, at a minimum, whenever the 24‐hour zero (low‐level) drift exceeds two times the limits of the applicable performance specification(s) specified in the relevant standard. The system shall allow the amount of excess zero (low‐level) and high‐level drift measured at the 24‐hour interval checks to be recorded and quantified whenever specified. The CPMS must be calibrated prior to use for the purposes of complying with this section. The CPMS must be checked daily for indication that the system is responding. If the CPMS system includes an internal system check, results must be recorded and checked daily for proper operation. [40 CFR 63.8(c)(6), Minn. R. 7017.1010]

COMG 7 197

(i) A CMS is out of control if— (A) The zero (low‐level), mid‐level (if applicable), or high‐level calibration drift (CD) exceeds two times the applicable CD specification in the applicable performance specification or in the relevant standard; or (B) The CMS fails a performance test audit (e.g., cylinder gas audit), relative accuracy audit, relative accuracy test audit, or linearity test audit. (ii) When the CMS is out of control, the Permittee shall take the necessary corrective action and shall repeat all necessary tests which indicate that the system is out of control. The Permittee shall take corrective action and conduct retesting until the performance requirements are below the applicable limits. The beginning of the out‐of‐control period is the hour the Permittee conducts a performance check (e.g., calibration drift) that indicates an exceedance of the performance requirements established under pt. 63. The end of the out‐of‐control period is the hour following the completion of corrective action and successful demonstration that the system is within the allowable limits. During the period the CMS is out of control, recorded data shall not be used in data averages and calculations, or to meet any data availability requirement established under pt. 63. [40 CFR 63.8(c)(7), Minn. R. 7017.1010]

COMG 7 198

For a CMS that is out of control as defined in Section 63.8(c)(7), the Permittee shall submit all information concerning out‐of‐control periods, including start and end dates and hours and descriptions of corrective actions taken, in the excess emissions and continuous monitoring system performance report required in Section 63.10(e)(3). [40 CFR 63.8(c)(8), Minn. R. 7017.1010]

COMG 7 199

Quality control program. (1) The results of the quality control program required in Section 63.8(d) will be considered by the Administrator when he/she determines the validity of monitoring data. (2) When the Permittee in the operation of an affected source is required to use a CMS and is subject to the monitoring requirements of Section 63.8(d) and a relevant standard, the Permittee shall develop and implement a CMS quality control program. As part of the quality control program, the Permittee shall develop and submit to the Administrator for approval upon request a site‐specific performance evaluation test plan for the CMS performance evaluation required in Section 63.8(e)(3)(i), according to the procedures specified in Section 63.8(e). In addition, each quality control program shall include, at a minimum, a written protocol that describes procedures for each of the following operations: (i) Initial and any subsequent calibration of the CMS; (ii) Determination and adjustment of the calibration drift of the CMS; (iii) Preventive maintenance of the CMS, including spare parts inventory; (iv) Data recording, calculations, and reporting; (v) Accuracy audit procedures, including sampling and analysis methods; and (vi) Program of corrective action for a malfunctioning CMS. (3) The Permittee shall keep these written procedures on record for the life of the affected source or until the affected source is no longer subject to the provisions of this part, to be made available for inspection, upon request, by the Administrator. If the performance evaluation plan is revised, the Permittee shall keep previous (i.e., superseded) versions of the performance evaluation plan on record to be made available for inspection, upon request, by the Administrator, for a period of 5 years after each revision to the plan. [40 CFR 63.8(d), Minn. R. 7017.1010]

Subject

Item ID

Sequence

Number Requirement

COMG 7 200

Performance evaluation of continuous monitoring systems—(1) General. When required by a relevant standard, and at any other time the Administrator may require under section 114 of the Act, the Permittee shall conduct a performance evaluation of the CMS on the monitored source. Such performance evaluation shall be conducted according to the applicable specifications and procedures described in Section 63.8 or in pt. 63, subp. UUUUU. (2) Notification of performance evaluation. The Permittee shall notify the Administrator in writing of the date of the performance evaluation simultaneously with the notification of the performance test date required under Section 63.7(b) or at least 60 days prior to the date the performance evaluation is scheduled to begin if no performance test is required. [40 CFR 63.8(e)(1)&(2), Minn. R. 7017.1010]

COMG 7 201

(i) Submission of site‐specific performance evaluation test plan. Before conducting a required CMS performance evaluation, the Permittee shall develop and submit a site‐specific performance evaluation test plan to the Administrator for approval upon request. The performance evaluation test plan shall include the evaluation program objectives, an evaluation program summary, the performance evaluation schedule, data quality objectives, and both an internal and external QA program. Data quality objectives are the pre‐evaluation expectations of precision, accuracy, and completeness of data. (ii) The internal QA program shall include, at a minimum, the activities planned by routine operators and analysts to provide an assessment of CMS performance. The external QA program shall include, at a minimum, systems audits that include the opportunity for on‐site evaluation by the Administrator of instrument calibration, data validation, sample logging, and documentation of quality control data and field maintenance activities. (iii) The Permittee source shall submit the site‐specific performance evaluation test plan to the Administrator (if requested) at least 60 days before the performance test or performance evaluation is scheduled to begin, or on a mutually agreed upon date, and review and approval of the performance evaluation test plan by the Administrator will occur with the review and approval of the site‐specific test plan (if review of the site‐specific test plan is requested). (iv) The Administrator may request additional relevant information after the submittal of a site‐specific performance evaluation test plan. [40 CFR 63.8(e)(3)(i)‐(iv), Minn. R. 7017.1010]

COMG 7 202

(v) In the event that the Administrator fails to approve or disapprove the site‐specific performance evaluation test plan within the time period specified in Section 63.7(c)(3), the following conditions shall apply: (A) If the Permittee intends to demonstrate compliance using the monitoring method(s) specified in pt. 63, subp. UUUUU, the Permittee shall conduct the performance evaluation within the time specified in pt. 63, subp. A using the specified method(s); (B) If the Permittee intends to demonstrate compliance by using an alternative to a monitoring method specified in subp. UUUUU, the Permittee shall refrain from conducting the performance evaluation until the Administrator approves the use of the alternative method. If the Administrator does not approve the use of the alternative method within 30 days before the performance evaluation is scheduled to begin, the performance evaluation deadlines specified in Section 63.8(e)(4) may be extended such that the Permittee shall conduct the performance evaluation within 60 calendar days after the Administrator approves the use of the alternative method. Notwithstanding the requirements in the preceding two sentences, the Permittee may proceed to conduct the performance evaluation as required in this section (without the Administrator's prior approval of the site‐specific performance evaluation test plan) if he/she subsequently chooses to use the specified monitoring method(s) instead of an alternative. [40 CFR 63.8(e)(3)(v), Minn. R. 7017.1010]

COMG 7 203

(vi) Neither the submission of a site‐specific performance evaluation test plan for approval, nor the Administrator's approval or disapproval of a plan, nor the Administrator's failure to approve or disapprove a plan in a timely manner shall— (A) Relieve the Permittee of legal responsibility for compliance with any applicable provisions of part 63 or with any other applicable Federal, State, or local requirement; or (B) Prevent the Administrator from implementing or enforcing part 63 or taking any other action under the Act. [40 CFR 63.8(e)(3)(vi), Minn. R. 7017.1010]

Subject

Item ID

Sequence

Number Requirement

COMG 7 204

Conduct of performance evaluation and performance evaluation dates. The Permittee shall conduct a performance evaluation of a required CMS during any performance test required under Section 63.7 in accordance with the applicable performance specification as specified in subp. UUUUU. If a performance test is not required, or the requirement for a performance test has been waived under Section 63.7(h), the Permittee shall conduct the performance evaluation not later than 180 days after the appropriate compliance date for the affected source, as specified in Section 63.7(a), or as otherwise specified in subp. UUUUU. [40 CFR 63.8(e)(4), Minn. R. 7017.1010]

COMG 7 205

Reporting performance evaluation results. (i) The Permittee shall furnish the Administrator a copy of a written report of the results of the performance evaluation simultaneously with the results of the performance test required under Section 63.7 or within 60 days of completion of the performance evaluation if no test is required, unless otherwise specified in pt. 63, subp. UUUUU. The Administrator may request that the Permittee submit the raw data from a performance evaluation in the report of the performance evaluation results. [40 CFR 63.8(e)(5)(i), Minn. R. 7017.1010]

COMG 7 206

Use of an alternative monitoring method. Until permission to use an alternative monitoring procedure has been granted by the Administrator under 40 CFR Sections 63.8(f)(1)‐(6), as appropriate, the Permittee remains subject to the requirements of 40 CFR Section 63.8 and pt. 63, subp. UUUUU. Alternative monitoring requests and approvals shall meet the requirements of Section 63.8(f)(1)‐(6). [40 CFR 63.8(f), Minn. R. 7017.1010]

COMG 7 207

Reduction of monitoring data. The Permittee must reduce monitoring data as specified in 40 CFR Section 63.8(g)(1)‐(5). [40 CFR 63.8(g), Minn. R. 7017.1010]

COMG 7 208

Initial notifications. (2) The Permittee shall notify the Administrator in writing that the source is subject to subp. UUUUU. The notification, which shall be submitted not later than 120 calendar days after the February 16, 2012 effective date of subp. UUUUU (or within 120 calendar days after the source becomes subject to subp. UUUUU), shall provide the following information: (i) The name and address of the Permittee; (ii) The address (i.e., physical location) of the affected source; (iii) An identification of the relevant standard (subp. UUUUU), or other requirement, that is the basis of the notification and the source's compliance date; (iv) A brief description of the nature, size, design, and method of operation of the source and an identification of the types of emission points within the affected source subject to subp. UUUUU and types of hazardous air pollutants emitted; and (v) A statement of whether the affected source is a major source or an area source. [40 CFR 63.9(b)(2), Minn. R. 7019.0100]

COMG 7 209

Notification of performance test. The Permittee shall notify the Administrator in writing of its intention to conduct a performance test at least 60 calendar days before the performance test is scheduled to begin to allow the Administrator to review and approve the site‐specific test plan required under Section 63.7(c), if requested by the Administrator, and to have an observer present during the test. [40 CFR 63.9(e), Minn. R. 7019.0100]

COMG 7 210

Additional notification requirements for sources with continuous monitoring systems. For any CMS required by subp. UUUUU, the Permittee shall furnish the Administrator written notification as follows: (1) A notification of the date the CMS performance evaluation under Section 63.8(e) is scheduled to begin, submitted simultaneously with the notification of the performance test date required under Section 63.7(b). If no performance test is required, or if the requirement to conduct a performance test has been waived for an affected source under Section 63.7(h), the Permittee shall notify the Administrator in writing of the date of the performance evaluation at least 60 calendar days before the evaluation is scheduled to begin; and, (3) A notification that the criterion necessary to continue use of an alternative to relative accuracy testing, as provided by Section 63.8(f)(6), has been exceeded. The notification shall be delivered or postmarked not later than 10 days after the occurrence of such exceedance, and it shall include a description of the nature and cause of the increased emissions. [40 CFR 63.9(g)(1)&(3), Minn. R. 7019.0100]

Subject

Item ID

Sequence

Number Requirement

COMG 7 211

Notification of compliance status. Each time a notification of compliance status is required under 40 CFR pt. 63, subp. A, the Permittee shall submit to the Commissioner a notification of compliance status containing the information required by 40 CFR Section 63.9(h), signed by the responsible official who shall certify its accuracy, attesting to whether the source has complied with the relevant standard. The notification must be sent by the 60th day following the completion of the relevant compliance demonstration activity specified in pt. 63, subp. UUUUU. Notifications may be combined as long as the due date requirement for each notification is met. [40 CFR 63.9(h), Minn. R. 7019.0100]

COMG 7 212

Change in information already provided. Any change in the information already provided under Section 63.9 shall be provided to the Administrator in writing within 15 calendar days after the change. [40 CFR 63.9(j), Minn. R. 7019.0100]

COMG 7 213

The Permittee shall submit reports to the Commissioner and shall send a copy of each report to the Administrator. [40 CFR 63.10(a), Minn. R. 7019.0100]

COMG 7 214

General recordkeeping requirements. (1) The Permittee shall maintain files of all information (including all reports and notifications) required by pt. 63 recorded in a form suitable and readily available for expeditious inspection and review. The files shall be retained for at least 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. At a minimum, the most recent 2 years of data shall be retained on site. The remaining 3 years of data may be retained off site. Such files may be maintained on microfilm, on a computer, on computer floppy disks, on magnetic tape disks, or on microfiche. [40 CFR 63.10(b), Minn. R. 7019.0100, subp. 2(B)]

COMG 7 215

(2) The Permittee shall maintain relevant records for such source of— (iii) All required maintenance performed on the air pollution control and monitoring equipment; (vi) Each period during which a CMS is malfunctioning or inoperative (including out‐of‐control periods); (vii) All required measurements needed to demonstrate compliance with a relevant standard (including, but not limited to, 15‐minute averages of CMS data, raw performance testing measurements, and raw performance evaluation measurements, that support data that the source is required to report); (A) This paragraph applies to the Permittee if it is required to install a continuous emissions monitoring system (CEMS) where the CEMS installed is automated, and where the calculated data averages do not exclude periods of CEMS breakdown or malfunction. An automated CEMS records and reduces the measured data to the form of the pollutant emission standard through the use of a computerized data acquisition system. In lieu of maintaining a file of all CEMS subhourly measurements as required under Section 63.10(b)(2)(vii), the Permittee shall retain the most recent consecutive three averaging periods of subhourly measurements and a file that contains a hard copy of the data acquisition system algorithm used to reduce the measured data into the reportable form of the standard. (B) This paragraph applies to the Permittee if it is required to install a CEMS where the measured data is manually reduced to obtain the reportable form of the standard, and where the calculated data averages do not exclude periods of CEMS breakdown or malfunction. In lieu of maintaining a file of all CEMS subhourly measurements as required under Section 63.10(b)(2)(vii), the Permittee shall retain all subhourly measurements for the most recent reporting period. The subhourly measurements shall be retained for 120 days from the date of the most recent summary or excess emission report submitted to the Administrator. (C) The Administrator or delegated authority, upon notification to the source, may require the Permittee to maintain all measurements as required by Section 63.10(b)(2)(vii), if the Administrator or the delegated authority determines these records are required to more accurately assess the compliance status of the affected source. [40 CFR 63.10(b)(2)(iii), (vi), & (vii), Minn. R. 7019.0100, subp. 2(B)]

Subject

Item ID

Sequence

Number Requirement

COMG 7 216

The Permittee shall maintain relevant records for the affected source of— (viii) All results of performance tests and CMS performance evaluations; (ix) All measurements as may be necessary to determine the conditions of performance tests and performance evaluations; (x) All CMS calibration checks; (xi) All adjustments and maintenance performed on CMS; (xii) Any information demonstrating whether a source is meeting the requirements for a waiver of recordkeeping or reporting requirements under this part, if the source has been granted a waiver under Section 60.10(f); (xiii) All emission levels relative to the criterion for obtaining permission to use an alternative to the relative accuracy test, if the source has been granted such permission under Section 63.8(f)(6); and (xiv) All documentation supporting initial notifications and notifications of compliance status under Section 63.9. [40 CFR 63.10(b)(2)(viii)‐(xiv), Minn. R. 7019.0100, subp. 2(B)]

COMG 7 217

Additional recordkeeping requirements for sources with continuous monitoring systems. In addition to complying with the requirements specified in Section 63.10(b)(1) and (b)(2), the Permittee shall maintain records for the affected source of— (1) All required CMS measurements (including monitoring data recorded during unavoidable CMS breakdowns and out‐of‐control periods); (2)‐(4) [Reserved] (5) The date and time identifying each period during which the CMS was inoperative except for zero (low‐level) and high‐level checks; (6) The date and time identifying each period during which the CMS was out of control, as defined in Section 63.8(c)(7); (7) The specific identification (i.e., the date and time of commencement and completion) of each period of excess emissions and parameter monitoring exceedances, as defined in the relevant standard(s), that occurs during startups, shutdowns, and malfunctions of the affected source; (8) The specific identification (i.e., the date and time of commencement and completion) of each time period of excess emissions and parameter monitoring exceedances, as defined in the relevant standard(s), that occurs during periods other than startups, shutdowns, and malfunctions of the affected source; (9) [Reserved] (12) The nature of the repairs or adjustments to the CMS that was inoperative or out of control; (13) The total process operating time during the reporting period; and (14) All procedures that are part of a quality control program developed and implemented for CMS under Section 63.8(d). [40 CFR 63.10(c)(1)‐(9), 40 CFR 63.10(c)(12)‐(14), Minn. R. 7019.0100]

COMG 7 218

General reporting requirements. (1) Notwithstanding the requirements in Section 63.10(d) and (e), and except as provided in Section 63.16, the Permittee shall submit reports to the Administrator in accordance with the reporting requirements in pt. 63, subp. UUUUU. (2) Reporting results of performance tests. The Permittee shall report the results of a required performance test to the appropriate permitting authority. The Permittee shall report the results of the performance test to the Administrator (or the State with an approved permit program) before the close of business on the 60th day following the completion of the performance test, unless specified otherwise in pt. 63, subp. UUUUU or as approved otherwise in writing by the Administrator. The results of the performance test shall be submitted as part of the notification of compliance status required under Section 63.9(h). [40 CFR 63.10(d)(1)&(2), Minn. R. 7019.0100]

COMG 7 219

Reporting results of continuous monitoring system performance evaluations. (i) If the Permittee is required to install a CMS by pt. 63, subp. UUUUU, the Permittee shall furnish the Administrator a copy of a written report of the results of the CMS performance evaluation, as required under Section 63.8(e), simultaneously with the results of the performance test required under Section 63.7, unless otherwise specified in subp. UUUUU. [40 CFR 63.10(e)(2)(i), Minn. R. 7019.0100]

COMG 7 220

Excess emissions and continuous monitoring system performance report and summary report. (i) Excess emissions and parameter monitoring exceedances are defined in pt. 63, subp. UUUUU. If the Permittee is required to install a CMS by subp. UUUUU, the Permittee shall submit an excess emissions and continuous monitoring system performance report and/or a summary report to the Administrator semiannually, except when— (A) More frequent reporting is specifically required by subp. UUUUU; (B) The Administrator determines on a case‐by‐case basis that more frequent reporting is necessary to accurately assess the compliance status of the source; or (C) [Reserved] (D) The affected source is complying with the Performance Track Provisions of Section 63.16 which allows less frequent reporting. [40 CFR 63.10(e)(3)(i), Minn. R. 7019.0100]

Subject

Item ID

Sequence

Number Requirement

COMG 7 221

Request to reduce frequency of excess emissions and continuous monitoring system performance reports. Notwithstanding the frequency of reporting requirements specified in Section 63.10(e)(3)(i), the Permittee may reduce the subp. UUUUU quarterly (or more frequent if applicable) reporting of excess emissions and continuous monitoring system performance (and summary) reports to semiannual if the following conditions are met: (A) For 1 full year (e.g., 4 quarterly or 12 monthly reporting periods) the affected source's excess emissions and continuous monitoring system performance reports continually demonstrate that the source is in compliance with the relevant standard; (B) The Permittee continues to comply with all recordkeeping and monitoring requirements specified in subps. A and UUUUU; and (C) The Administrator does not object to a reduced frequency of reporting for the affected source, as provided in Section 63.10(e)(3)(iii). [40 CFR 63.10(e)(3)(ii), Minn. R. 7019.0100]

COMG 7 222

The frequency of reporting of excess emissions and continuous monitoring system performance (and summary) reports required to comply with a relevant standard may be reduced only after the Permittee notifies the Administrator in writing of its intention to make such a change and the Administrator does not object to the intended change. In deciding whether to approve a reduced frequency of reporting, the Administrator may review information concerning the source's entire previous performance history during the 5‐year recordkeeping period prior to the intended change, including performance test results, monitoring data, and evaluations of the Permittee's conformance with operation and maintenance requirements. Such information may be used by the Administrator to make a judgment about the source's potential for noncompliance in the future. If the Administrator disapproves the Permittee's request to reduce the frequency of reporting, the Administrator will notify the Permittee in writing within 45 days after receiving notice of the Permittee's intention. The notification from the Administrator to the Permittee will specify the grounds on which the disapproval is based. In the absence of a notice of disapproval within 45 days, approval is automatically granted. [40 CFR 63.10(e)(3)(iii), Minn. R. 7019.0100]

COMG 7 223

As soon as CMS data indicate that the source is not in compliance with any emission limitation or operating parameter specified in subp. UUUUU, the frequency of reporting shall revert to the frequency specified in subp. UUUUU, and the Permittee shall submit an excess emissions and continuous monitoring system performance (and summary) report for the noncomplying emission points at the next appropriate reporting period following the noncomplying event. After demonstrating ongoing compliance with the relevant standard for another full year, the Permittee may again request approval from the Administrator to reduce the frequency of reporting for subp. UUUUU, as provided for in Section 63.10(e)(3)(ii) and (e)(3)(iii). [40 CFR 63.10(e)(3)(iv), Minn. R. 7019.0100]

COMG 7 224

Content and submittal dates for excess emissions and monitoring system performance reports. All required excess emissions and monitoring system performance reports and all summary reports shall be delivered or postmarked by the 30th day following the end of each calendar half or quarter, as appropriate. Written reports of excess emissions or exceedances of process or control system parameters shall include all the information required in Section 63.10(c)(5) through (c)(13), in Sections 63.8(c)(7) and 63.8(c)(8), and in subp. UUUUU, and they shall contain the name, title, and signature of the responsible official who is certifying the accuracy of the report. When no excess emissions or exceedances of a parameter have occurred, or a CMS has not been inoperative, out of control, repaired, or adjusted, such information shall be stated in the report. [40 CFR 63.10(e)(3)(v), Minn. R. 7019.0100]

Subject

Item ID

Sequence

Number Requirement

COMG 7 225

Summary report. As required under Section 63.10(e)(3)(vii) and (e)(3)(viii), one summary report shall be submitted for the hazardous air pollutants monitored at each affected source (unless subp. UUUUU specifies that more than one summary report is required, e.g., one summary report for each hazardous air pollutant monitored). The summary report shall be entitled "Summary Report—Gaseous and Opacity Excess Emission and Continuous Monitoring System Performance" and shall contain the following information: (A) The company name and address of the affected source; (B) An identification of each hazardous air pollutant monitored at the affected source; (C) The beginning and ending dates of the reporting period; (D) A brief description of the process units; (E) The emission and operating parameter limitations specified in subp. UUUUU; (F) The monitoring equipment manufacturer(s) and model number(s); (G) The date of the latest CMS certification or audit; (H) The total operating time of the affected source during the reporting period; (I) An emission data summary (or similar summary if the Permittee monitors control system parameters), including the total duration of excess emissions during the reporting period (recorded in hours), the total duration of excess emissions expressed as a percent of the total source operating time during that reporting period, and a breakdown of the total duration of excess emissions during the reporting period into those that are due to startup/shutdown, control equipment problems, process problems, other known causes, and other unknown causes; (J) A CMS performance summary (or similar summary if the Permittee monitors control system parameters), including the total CMS downtime during the reporting period (recorded in hours), the total duration of CMS downtime expressed as a percent of the total source operating time during that reporting period, and a breakdown of the total CMS downtime during the reporting period into periods that are due to monitoring equipment malfunctions, nonmonitoring equipment malfunctions, quality assurance/quality control calibrations, other known causes, and other unknown causes; (K) A description of any changes in CMS, processes, or controls since the last reporting period; (L) The name, title, and signature of the responsible official who is certifying the accuracy of the report; and (M) The date of the report. [40 CFR 63.10(e)(3)(vi), Minn. R. 7019.0100]

COMG 7 226

(vii) If the total duration of excess emissions or process or control system parameter exceedances for the reporting period is less than 1 percent of the total operating time for the reporting period, and CMS downtime for the reporting period is less than 5 percent of the total operating time for the reporting period, only the summary report shall be submitted, and the full excess emissions and continuous monitoring system performance report need not be submitted unless required by the Administrator. (viii) If the total duration of excess emissions or process or control system parameter exceedances for the reporting period is 1 percent or greater of the total operating time for the reporting period, or the total CMS downtime for the reporting period is 5 percent or greater of the total operating time for the reporting period, both the summary report and the excess emissions and continuous monitoring system performance report shall be submitted. [40 CFR 63.10(e)(3)(vii)&(viii), Minn. R. 7019.0100]

COMG 7 227

Waiver of recordkeeping or reporting requirements. The Permittee shall be subject to and follow the requirements of Section 63.10(f)(1) ‐ (6) if it desires to obtain a waiver from any applicable recordkeeping or reporting requirements. [40 CFR 63.10(f), Minn. R. 7019.0100]

COMG 8 1

COMG8 contains common Carbon Monoxide Continuous Emissions Monitoring System (CEMS) requirements from 40 CFR pts. 60 and Minn. R. ch. 7017. Additional monitoring requirements may also apply to the Facility, and it is the responsibility of the Facility to meet all applicable requirements. [Minn. R. 7007.0800, subp. 4(A), Minn. R. 7017.1020]

COMG 8 3

Emissions Monitoring: The Permittee shall use EQUI52 (the EQUI85 CO CEMS) to monitor EQUI85 carbon monoxide emissions, and EQUI71 (the EQUI100 CO CEMS) to monitor EQUI100 carbon monoxide emissions. Additional requirements applicable to EQUI52 and EQUI71 are located at subject items EQUI52 and EQUI71, respectively. [Minn. R. 7017.1006]

Subject

Item ID

Sequence

Number Requirement

COMG 8 5

Operate and maintain EQUI52 and EQUI71 according to 40 CFR pt. 60, Appendix B, Performance Standard 4 to measure all EQUI85 and EQUI100 CO emissions. The CEMS Data Acquisition System shall determine CO emission rates in units of pounds per million Btu heat input on a 30‐day rolling average. [40 CFR pt. 60, Appendix B, Minn. R. 7017.1006, Minn. R. 7017.1160, subp. 3, 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 8 6

Determina on of EQUI85 and EQUI100 hourly CO pounds per million Btu heat input Emission Rates:

The Permittee shall determine EQUI85 and EQUI100 hourly CO pounds per million Btu heat input emission rates as follows:

1. For each boiler (EQUI85 and EQUI100), separately determine CO emissions on a pounds per million Btu heat input basis for all CO ppmv data measured by EQUI52 (for EQUI85) and EQUI71 (for EQUI100), according to the following equa on:

CO lb/mmBtu = [(CO ppmv) * (CO mol wt) * (2.59E‐09) * (Fc‐factor)] * [100/(CO2 %)]

where:

CO lb/mmBtu = EQUI85/EQUI100 lb/mmBtu CO emission rateCO ppmv = CO measured by EQUI52/EQUI71 (ppmv)

CO mol wt = CO molecular weight (28.01)2.59E‐09 = combus on calcula on formula constant (lb/dscf)Fc‐Factor = subbituminous coal CO2‐based Fc‐factor, dscf CO2/million Btu heat input established by EPA (1840 dscf CO2/mmBtu heat input as stated in part 75, App. F, Sec on 3.3, Table 1)100 = percent conversion factorCO2 % = CO2 % (by volume) measured by CO2 diluent CEMS (EQUI55 is the EQUI85 CO2 diluent CEMS; EQUI50 is the EQUI100 CO2 diluent CEMS) except this value shall not be less than 5%

2. Calculate hourly CO lb/mmBtu emission rates according to the requirements of Minn. R. 7017.1160 for each boiler. [Minn. R. 7007.0800, subp. 4(B), Minn. R. 7017.1160]

COMG 8 9

Determina on of EQUI85 30‐day Rolling Average CO lb/mmBtu Emission Rates:

1. Calculate EQUI85 CO lb/mmBtu emission rates for every EQUI85 boiler operating day (as defined at Section 63.10042 except periods of startup and shutdown shall not be excluded) as the average of all EQUI85 hourly CO lb/mmBtu values for every EQUI85 boiler operating day including emissions from periods of startup and shutdown.

2. Calculate the EQUI85 30‐day CO lb/mmBtu emission rate as the average of all EQUI85 boiler operating day CO lb/mmBtu emission rates for each 30‐day period. [Minn. R. 7007.0800, subp. 4(B), Minn. R. 7017.1160]

COMG 8 10

Determina on of EQUI100 24‐hour Rolling Average CO lb/mmBtu Emission Rates:

Calculate EQUI100 24‐hour rolling average CO lb/mmBtu emission rates as the average of all EQUI100 hourly values for each 24‐hour period including emissions from periods of startup and shutdown, excluding hours of no operation. Hours of no operation are any hours when no fuel is combusted in EQUI100. [Minn. R. 7007.0800, subp. 4(B), Minn. R. 7017.1160]

COMG 8 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 8 12

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]

Subject

Item ID

Sequence

Number Requirement

COMG 8 13

Certification Test Plan: due 30 days before Certification Test. Certification Test Pretest Meeting: due 7 days before Certification Test. Certification Test Report: due 45 days after Certification Test.

The Test Plan and Test Report must be submitted in a format specified by the commissioner. [Minn. R. 7017.1060, subp. 1‐3, Minn. R. 7017.1080]

COMG 8 14

Continuous Operation: EQUI52 and EQUI71 CO 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]

COMG 8 16

CEMS Monitoring Data: All data points collected by CEMS EQUI52 and EQUI71 shall be used to calculate individual hourly CO emission averages unless another applicable requirement requires more frequent averaging. Each hourly CO average starts at the beginning of the hour and ends at the beginning of the following hour.

In order for an hour of data to be considered valid, it must contain the following minimum number of data points:

A. Four data points, equally spaced, if the emission unit operated during the en re hour;B. Two data points, at least 15 minutes apart, during periods of monitor calibra on or rou ne maintenance;

C. One data point if the emission unit operated for 15 minutes or less during the hour.

Monitoring data shall be recorded in the same units of measurement and averaging period as the facility's emission standard(s). [Minn. R. 7017.1160, subp. 1‐3]

COMG 8 33

Quality Assurance (QA) Plan: The Permittee shall develop and implement a written QA plan for each COMG8 CEMS according to the requirements of Minn. R. 7017.1170, subp. 2. The plan shall be on site and available for inspection within 30 days after monitor certification. The plan shall include the manufacturer's spare parts list for each CEMS and require that those parts be kept at the facility unless the Commissioner gives written approval to exclude specific spare parts from the list. [Minn. R. 7017.1170, subp. 2]

COMG 8 34

CEMS Daily Calibration Drift (CD) Assessment and Adjustment: The Permittee must conduct daily CD assessments and adjustments as needed according to the procedure listed in Minn. R. 7017.1170, subp. 3(A) and (B), 40 CFR Section 60.13(d)(1), or 40 CFR part 75, Appendix B, section 2.1, as amended and as applicable, for each pollutant concentration and diluent monitor, as specified at Minn. R. 7017.1170, subp. 3.

The CD assessment must be conducted on each monitor range. The span value specified in the applicable requirement or compliance document must be used to determine the zero and span calibration points. If no span value is specified in the applicable requirement or compliance document, the owner or operator must use a span value equivalent to 1.5 times the emission limit. [Minn. R. 7017.1170, subp. 3]

COMG 8 35 Relative Accuracy Test Audit (RATA) Notification: due 30 days before CEMS RATA. [Minn. R. 7017.1180, subp. 2]

Subject

Item ID

Sequence

Number Requirement

COMG 8 36

Recordkeeping: The Permittee shall maintain a file of all of the following CEMS information at the emission facility in a form suitable for inspection for at least five years from the date of each record:

1. Each one‐hour emission average recorded by the CEMS; 2. Monitor certification test reports; 3. Excess emissions reports; 4. Cylinder gas audit reports; 5. Calibration error audit reports; 6. Relative accuracy test audits; 7. Linearity check reports; 8. Results of daily calibration drift checks; 9. Log of adjustments made to the CEMS and maintenance performed on the CEMS; and, 10. All other monitoring system information required by an applicable compliance document.

The Permittee shall also keep an updated copy of the facility's CEMS quality assurance plan on site. [Minn. R. 7017.1130]

COMG 9 1

ACID RAIN PROGRAM REQUIREMENTS

Comply with the applicable Acid Rain emissions limitation for sulfur dioxide for each of the facility four affected units. As defined at Section 72.2, "Acid Rain emissions limitation" means for purposes of sulfur dioxide emissions:

(i) The tonnage equivalent of the allowances authorized to be allocated to the affected units at a source for use in a calendar year under section 404(a)(1), (a)(3), and (h) of the Act, or the basic Phase II allowance allocations authorized to be allocated to an affected unit for use in a calendar year, or the allowances authorized to be allocated to an opt‐in source under sec on 410 of the Act for use in a calendar year; (ii) As adjusted:

(A) By allowances allocated by the Administrator pursuant to section 403, section 405 (a)(2), (a)(3), (b)(2), (c)(4), (d)(3), and (h)(2), and sec on 406 of the Act;

(B) By allowances allocated by the Administrator pursuant to subpart D of part 72; and therea er (C) By allowance transfers to or from the compliance account for that source that were recorded or properly submitted for recordation by the allowance transfer deadline as provided in Section 73.35 of Chapter I, after deduc ons and other adjustments are made pursuant to Sec on 73.34(c) of this Chapter I.

Refer to EQUI82, EQUI83, EQUI100, and EQUI85 for the applicable NOx limit for each of the facility four affected units. [40 CFR 72.9(c)(1)(ii), 40 CFR 72.9(g)(4)]

COMG 9 2

Hold allowances as of the allowance transfer deadline, in the facility's compliance account. Allowances may not be less than the total annual emissions of sulfur dioxide from the previous calendar year from the facility. [40 CFR 72.9(c)(1)(i)]

COMG 9 3

If the unit 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)]

COMG 9 4

Keep the certificate of representation, all emissions monitoring information, copies of all reports, compliance certifications and related submissions and all records made or required under the Acid Rain Program on site for a period of 5 years from the date the document was created. [40 CFR 72.9(f)]

Subject

Item ID

Sequence

Number Requirement

COMG 9 6

Emissions from the stationary source cannot exceed any allowances that the source lawfully holds under federal acid rain regulations, except as allowed by Minn. R. 7007.0800, subp. 7. [Minn. R. 7007.0800, subp. 7]

COMG 9 7

IGNITER GUN REQUIREMENTS: Carbon Monoxide <= 319 tons per year 12‐month rolling sum for total COMG9 CO emissions from natural gas combustion in all igniter/warm‐up guns in EQUI82, EQUI83, EQUI85, and EQUI100 (Units 1, 2, 4, and 3, respectively). This excludes CO emissions from coal combustion and other permitted fuels. [Minn. R. 7007.0800, subp. 2(A)]

COMG 9 8

Recordkeeping: By the last day of each month calculate and record the total COMG9 CO emissions for the previous month and the previous 12‐month period (12‐month rolling sum) from the combustion of natural gas in the COMG9 boilers igniter/warmup guns. Use the AP‐42 Table 1.4‐1 natural gas CO emission factor (currently 84 lb/million cubic feet) for calculating igniter/warmup guns CO emissions from natural gas combustion. [Minn. R. 7007.0800, subp. 5]

COMG 9 9

CONSENT DECREE REQUIREMENTS

The Permittee is subject to the requirements of a Consent Decree filed as CASE 0:14‐cv‐02911‐ADM‐LIB Document 3‐1 on July 16, 2014 and signed by the Judge of the U.S. District Court for Minnesota on September 29, 2014, hereinafter referred to as the 'Consent Decree'.

Consent Decree Sulfur Dioxide limits are located in COMG1 (GP 004: Boilers 1‐4 Sulfur Dioxide Limits). Consent Decree NOx and PM emission limits and PM testing requirements are located in the relevant subject item (EQUI82, EQUI83, EQUI100, and EQUI85). PM CEMS requirements are located in the relevant subject item EQUI107 (STRU13 PM CEMS) and EQUI108 (EQUI85 PM CEMS). Appendix F of this permit contains Consent Decree definitions relevant to this permit and the facility. Other pertinent Consent Decree requirements are in COMG9. Please refer to the Consent Decree for additional definitions not in Appendix F, and any additional requirements not in this permit.

For any conflicts or discrepancies between the requirements and definitions in the Consent Decree and the requirements and definitions in this permit, the Consent Decree shall prevail. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 9 10

The Consent Decree requirements and limitations in this permit are "applicable requirements" as defined in 40 CFR 70.2. Consent Decree requirements and limitations in this permit are identified by the following citation: "CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21". [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 9 14

By no later than December 31, 2018, the Permittee shall retire, refuel, repower, or reroute EQUI82/Boswell Unit 1 and EQUI83/Boswell Unit 2.

"Reroute" means to reroute the flue gas from EQUI82 and EQUI83 through an FGD device that treats the flue gas from such units and EQUI100/Boswell Unit 3. The Permittee shall provide EPA and MPCA with written notification by no later than December 31, 2016 whether it will retire, refuel, repower, or reroute EQUI82 and/or EQUI83. The Permittee submitted a written notification dated December 19, 2016 to the USEPA and MPCA indicating EQUI82 and EQUI83 will be retired no later than December 31, 2018. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

Subject

Item ID

Sequence

Number Requirement

COMG 9 15

The Permittee shall not exceed the System‐Wide Annual Tonnage Limitation for Nitrogen Oxides <= 6700 tons per year on a calendar year basis.

The Minnesota Power System is composed of Boswell Energy Center, Laskin Energy Center, Rapids Energy Center, and Taconite Harbor Energy Center. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 9 25

Nitrogen Oxides and Sulfur Dioxide Emissions Monitoring: In determining a 30‐Day Rolling Average Emission Rate for NOx and for SO2, the Permittee shall use a Continuous Emissions Monitoring System ("CEMS") in accordance with the procedures of 40 CFR Part 75 and 40 CFR Part 60, Appendix F, Procedure 1, except that emissions data for the 30‐Day Rolling Average Emission Rate need not be bias adjusted and the missing data substitution procedures of 40 CFR Part 75 shall not apply.

For purposes of determining compliance with the NOx System‐Wide Annual Tonnage Limitation (located in this subject item COMG9) and the SO2 System‐Wide Annual Tonnage Limitation (located in subject item COMG1), the Permittee shall use CEMS in accordance with the procedures at 40 CFR Part 75. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 9 26

The Permittee shall Continuously Operate each existing PM Control Device (TREA16, TREA14, TREA9, and TREA21) on each Unit (EQUI82, EQUI83, EQUI100, and EQUI85, respectively) at the facility to maximize PM emission reductions at all times when each Unit is in operation. Except as required during correlation testing under 40 C.F.R. Part 60, Appendix B, Performance Specification 11, and Quality Assurance Requirements under Appendix F, Procedure 2, as required by this Consent Decree, Minnesota Power shall, at a minimum, ensure that to the extent practicable: 1. That each opening in the casings, ductwork, and expansion joints for each Baghouse at such Unit is inspected and repaired during the next planned Unit outage (or unplanned outage of sufficient length) to minimize air leakage, and,

2. A bag leak detection program is developed and implemented for TREA16, TREA14, TREA9, and TREA21 to ensure that leaking bags are promptly replaced. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 9 27

The Permittee shall install, correlate, maintain, and operate PM CEMS on STRU13 and on STRU14. The PM CEMS shall comprise a continuous particle mass monitor measuring filterable particulate matter concentration, directly or indirectly, on an hourly average basis and a diluent monitor or monitors used to convert the concentration to units expressed in pounds per million Btu heat input. The PM CEMS installed at each stack must be appropriate for the anticipated stack conditions and capable of measuring PM concentrations on an hourly average basis. The Permittee shall maintain, in an electronic database, the hourly average emission values of all PM CEMS in pounds per million Btu heat input. Except for periods of monitor Malfunction, maintenance, or repair, the Permittee shall operate the PM CEMS at all times when any Unit it serves is operating, including during Unit startup, shutdown, and Malfunction. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 9 28

Stack testing shall be used to determine compliance with the PM Emission Rates established by the Consent Decree, unless EPA approves after consultation with MPCA a request under Consent Decree Paragraph 127, in which case PM CEMS shall be used to demonstrate compliance with an applicable PM Emission Rate on a 3‐Hour Rolling Average Emission Rate basis. Data from the PM CEMS shall be used, at a minimum, to monitor emissions on a continuous basis. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

Subject

Item ID

Sequence

Number Requirement

COMG 9 29

The annual performance test requirement imposed on the Permittee by Consent Decree Section VI.H may be satisfied by stack tests conducted by the Permittee as may be required by its permits from the State of Minnesota (including this permit) for any year that such stack tests are required under the permits.

The Permittee may perform testing every other year for a specific COMG9 boiler (EQUI82, EQUI83, EQUI100, or EQUI85), rather than every year, provided that the two most recently completed test results for the specific COMG9 boiler conducted in accordance with the methods and procedures specified in the Consent Decree, demonstrate that the specific COMG9 boiler filterable PM emissions are equal to or less than 0.0075 pounds per million Btu heat input. The Permittee shall perform testing every year on a specific COMG9 boiler, rather than every other year, beginning in the year immediately following any test result demonstrating that the filterable PM emissions are greater than 0.0075 pounds per million Btu heat input for the specific COMG9 boiler. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 9 30

Surrender of NOx Allowances: Except as provided in the Consent Decree, beginning in calendar year 2014 and continuing each calendar year thereafter, the Permittee shall not sell, bank, trade, or transfer any NOx Allowances allocated to the Minnesota Power System for that calendar year. Beginning in calendar year 2014 and continuing each calendar year thereafter, the Permittee shall Surrender all NOx Allowances allocated to Units within the Minnesota Power System for that calendar year (other than those NOx Allowances that the Permittee needs to meet federal and/or state Clean Air Act regulatory requirements for the Minnesota Power System Units). Nothing in the Consent Decree shall prevent the Permittee from purchasing or otherwise obtaining NOx Allowances from another source to the extent otherwise allowed by law. The requirements of the Consent Decree pertaining to the Permittee's use and Surrender of NOx Allowances are permanent injunctions not subject to any termination provision of the Consent Decree. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 9 31

Super‐Compliant NOx Allowances:

Notwithstanding the Surrender of Allowances requirement, in each calendar year beginning in 2014, and continuing thereafter, the Permittee may sell, bank, use, trade, or transfer NOx Allowances made available in each calendar year solely as a result of:

(a) the installation and operation of any NOx pollution control equipment that is not otherwise required by, or necessary to maintain compliance with, any provision of the Consent Decree, and is not otherwise required by law, or the installation and operation of pollution control equipment prior to the dates required under the Consent Decree or otherwise required by law; or

(b) achievement and maintenance of an emission rate below the Calendar Year Average Emission Rate for NOx equal to the lesser of (i) ninety percent of an applicable 30‐Day Rolling Average Emission Rate for NOx, or (ii) an applicable 12‐Month Rolling Average Emission Rate for NOx, provided the Permittee is also in compliance for that calendar year with all emission limitations for NOx set forth in the Consent Decree. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

Subject

Item ID

Sequence

Number Requirement

COMG 9 32

Method for Surrender of NOx Allowances:

The Permittee shall Surrender all NOx Allowances required to be Surrendered pursuant to the requirements for Surrender of Allowances subject to Super‐Compliant Allowances in this permit, by April 30 of the immediately following calendar year. For all NOx Allowances required to be Surrendered, the Permittee shall first submit a NOx Allowance transfer request to EPA's Office of Air and Radiation's Clean Air Markets Division directing the transfer of such NOx Allowances to the EPA Enforcement Surrender Account or to any other EPA account that EPA may direct in writing. Such NOx Allowance transfer requests may be made in an electronic manner using the EPA's Clean Air Markets Division Business System or similar system provided by EPA. As part of submitting these transfer requests, the Permittee shall irrevocably authorize the transfer of these NOx Allowances and identify, by name of account and any applicable serial or other identification numbers or station names, the source and location of the NOx Allowances being Surrendered. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 9 33

Surrender of SO2 Allowances:

Except as provided in the Consent Decree, beginning in calendar year 2014 and continuing each calendar year thereafter, the Permittee shall not sell, bank, trade, or transfer any SO2 Allowances allocated to the Minnesota Power System for that calendar year.

Beginning in calendar year 2014 and continuing each calendar year thereafter, the Permittee shall Surrender all SO2 Allowances allocated to Units within the Minnesota Power System for that calendar year (other than those SO2 Allowances that the Permittee needs to meet federal and/or state Clean Air Act regulatory requirements for the Minnesota Power System Units).

Nothing in the Consent Decree shall prevent the Permittee from purchasing or otherwise obtaining SO2 Allowances from another source to the extent otherwise allowed by law.

The requirements of the Consent Decree pertaining to the Permittee's use and Surrender of SO2 Allowances are permanent injunctions not subject to any termination provision of the Consent Decree. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 9 34

Super‐Compliant SO2 Allowances:

Notwithstanding the Surrender of Allowances requirement, in each calendar year beginning in 2014, and continuing thereafter, the Permittee may sell, bank, use, trade, or transfer SO2 Allowances made available in each calendar year solely as a result of:

(a) the installation and operation of any SO2 pollution control equipment that is not otherwise required by, or necessary to maintain compliance with, any provision of the Consent Decree, and is not otherwise required by law, or the installation and operation of pollution control equipment prior to the dates required under the Consent Decree or otherwise required by law; or

(b) achievement and maintenance of an emission rate below the Calendar Year Average Emission Rate for SO2 equal to the lesser of (i) ninety percent of an applicable 30‐Day Rolling Average Emission Rate for SO2, or (ii) an applicable 12‐Month Rolling Average Emission Rate for SO2, provided the Permittee is also in compliance for that calendar year with all emission limitations for SO2 set forth in the Consent Decree. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

Subject

Item ID

Sequence

Number Requirement

COMG 9 35

Method for Surrender of SO2 Allowances:

The Permittee shall Surrender all SO2 Allowances required to be Surrendered pursuant to the requirements for Surrender of Allowances subject to Super‐Compliant Allowances in this permit, by April 30 of the immediately following calendar year. For all SO2 Allowances required to be Surrendered, the Permittee shall first submit an SO2 Allowance transfer request to EPA's Office of Air and Radiation's Clean Air Markets Division directing the transfer of such SO2 Allowances to the EPA Enforcement Surrender Account or to any other EPA account that EPA may direct in writing. Such SO2 Allowance transfer requests may be made in an electronic manner using the EPA's Clean Air Markets Division Business System or similar system provided by EPA. As part of submitting these transfer requests, the Permittee shall irrevocably authorize the transfer of these SO2 Allowances and identify, by name of account and any applicable serial or other identification numbers or station names, the source and location of the SO2 Allowances being Surrendered. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 9 36

Prohibition On Netting Credits or Offsets:

Emission reductions that result from actions to be taken by the Permittee after the (September 29, 2014) date of entry of the Consent Decree to comply with the requirements of the Consent Decree, shall not be considered as a creditable contemporaneous emission decrease for the purpose of obtaining a Netting credit or offset under the Clean Air Act's PSD and Nonattainment NSR programs. Notwithstanding the preceding sentence, and subject to the limitations provided below, the Permittee may treat up to (a) 75 tons of NOx, 75 tons of SO2, and 15 tons of PM emission reductions at EQUI100 and EQUI85 as if they were not otherwise required by the Consent Decree for purposes of Ne ng at EQUI100 and EQUI85. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 9 36

(Cont. from Above)Use of the Netting credits provided in the previous paragraph is subject to the following additional restrictions:(a) The emission reductions of NOx, SO2, and PM that the Permittee intends to utilize for Netting purposes must be contemporaneous and otherwise creditable within the meaning of the Act and the applicable SIP, and the Permittee must comply with, and be subject to, all requirements and criteria for creating contemporaneous creditable decreases as set forth in 40 CFR Section 52.21(b) and the applicable SIP, subject to the limitations of Section VIII of the Consent Decree,

(b) The Permittee must apply for, and obtain, any required major or minor NSR permits for any project in which emission reductions under the first paragraph of this requirement are used for Netting. The Permittee shall provide notice and a copy of its permit application to EPA in accordance with Section XIX (Notices) of the Consent Decree, concurrent with its permit application submission to the relevant permitting authority,

(c) The emission reductions of NOx, SO2, and PM that the Permittee intends to utilize for netting shall not be available under this requirement if such use would result in an exceedance of a PSD increment, or an interference with "reasonable further progress" toward attainment of a NAAQS in accordance with Part D of Title I of the CAA, and

(d) The Permittee must be and remain in full compliance with the provisions of the Consent Decree establishing performance, operational, maintenance, and control technology requirements at Boswell Units 3 and 4, including emission rates, system‐wide annual tonnage limitations, and the requirements pertaining to the surrender of SO2 allowances and NOx allowances. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

Subject

Item ID

Sequence

Number Requirement

COMG 9 36

(Cont. from Above)The limitations on the generation and use of netting credits and offsets set forth in the Consent Decree do not apply to emission reductions achieved by a particular Minnesota Power System Unit that are greater than those required under the Consent Decree for that particular Minnesota Power System Unit. For purposes of this paragraph, emission reductions from a Minnesota Power System Unit are greater than those required under the Consent Decree if they result from such Unit's compliance with federally‐enforceable emission limits that are more stringent than the limits imposed on the Unit under the Consent Decree and under applicable provisions of the Clean Air Act.Nothing in the Consent Decree is intended to preclude the emission reductions generated under the Consent Decree from being considered by the applicable state regulatory agency or EPA for the purpose of attainment demonstrations submitted pursuant to Section 110 of the Act, 42 U.S.C. Section 7410, or in determining impacts on National Ambient Air Quality Standards, PSD increment, or air quality related values, including visibility, in a Class I area. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

COMG 9 37

CONTROL OF MERCURY FROM ELECTRIC GENERATING UNITS

Applicability. The Permittee must comply with Minn. R. 7011.0561, except as provided under Minn. R. 7011.0561, subp. 3, for any of the its coal‐fired electric generating units that the Permittee has demonstrated has actual mercury emissions of five pounds per year or more. Minn. R. 7011.0561 is a state‐only requirement not enforceable by the administrator. [Minn. R. 7011.0561, subp. 1]

COMG 9 38

Unless the commissioner establishes an alternative mercury emissions reduction under Minn. Stat. 216B.687, the Permittee shall control Mercury >= 90 percent control efficiency from EQUI100 and EQUI85 or demonstrate that EQUI100 and EQUI85 each emit no more than 0.8 pounds of mercury per trillion British thermal units (Tbtu) of heat input.

The commissioner has established alternative mercury limits for EQUI100 and EQUI85 under Minn. Stat. Section 216B.687, subd. 2(b) and subd. 3, respectively. Refer to subject items EQUI100 and EQUI85 for such limits. Minn. R. 7011.0561 is a state‐only requirement not enforceable by the administrator. [Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7011.0561, subp. 4, Minn. R. 7011.0561, subp. 4(A)]

COMG 9 39

The Permittee must continuously monitor EQUI100 and EQUI85 mercury emissions at a representative sampling location following the outlet of the last air pollution control device. A continuous monitor is either a continuous emissions monitoring system (CEMS) for mercury or a sorbent trap monitoring system capable of monitoring mercury as described in Minn. R. 7011.0561.

(1) If the system is a CEMS for mercury, the Permittee must prepare a monitoring plan according to Minn. R. 7011.0561, subp. 6. If the system is a sorbent trap system, the Permittee must prepare a monitoring plan according to Minn. R. 7011.0561, subp. 7. The plan must be submitted within 180 days of September 29, 2014, or as established by a permit, whichever is later.

(2) If applicable federal regulations establish requirements for installation and operation of continuous monitoring of the coal‐fired EGU, the monitoring plan must describe the compliance procedures for the monitors according to the federal regula on, in addi on to the requirements of this part. Minn. R. 7011.0561 is a state‐only requirement not enforceable by the administrator. [Minn. R. 7011.0561, subp. 5]

Subject

Item ID

Sequence

Number Requirement

COMG 9 40

Monitoring Provisions

If the Permittee uses a mercury CEMS, the Permittee shall follow the requirements of Minn. R. 7011.0561, subp. 6 for installing, operating, and maintaining the CEMS.

If the Permittee uses a sorbent trap monitoring system, the Permittee shall follow the requirements of Minn. R. 7011.0561, subp. 7 for installing, operating, and maintaining the sorbent trap monitoring system.

The Permittee shall follow the procedures in Minn. R. 7011.0561, subp. 8 for determining mercury content of coal. Minn. R. 7011.0561 is a state‐only requirement not enforceable by the administrator. [Minn. R. 7011.0561, subp. 6‐8]

COMG 9 41

TEST BURNSThe Permi ee may use alterna ve fuels in EQUI82, EQUI83, EQUI100 and/or EQUI85 during test burns according to the following requirements:

1. The significant emissions increase and the net emissions increase of any criteria pollutant (regulated under 40 CFR 52.21) due to combusting alternative fuels (compared to the emissions from combusting subbituminous coal) does not exceed any emission increase threshold at 40 CFR 52.21(b)(23)(i) and (ii) during any 12‐month period. The Permittee shall verify this by calculating the difference between the emissions that will result from the test burn, as well as the emissions that would occur if subbituminous coal was combusted during the period of time when the alternative fuel was burned for each test burn, and summing these data on a pollutant‐by‐pollutant basis, for all test burns during each 12‐month period. The two‐step process specified at 40 CFR 52.21(a)(2)(iv)(a) shall be used to determine the change in emissions.

2. Permit emission limits are not exceeded. The Permi ee shall verify this during the test burn by using PM, SO2, NOx, and Hg continuous emission monitors, and a continuous opacity monitor. For emissions not continuously monitored, the Permittee shall verify limits are not exceeded by calculating emissions using AP‐42 or other available emission factors.3. Alterna ve fuels that are solid wastes, as defined in 40 CFR 258.2, shall not be burned unless determined to not be solid waste when combusted according to 40 CFR 241.3 or 40 CFR 241.4.4. Wood burned must meet the defini on of "Clean Cellulosic Biomass" at 40 CFR 241.2.5. Used oil must meet the specifica ons outlined in 40 Sec on 279.11.6. Test burns shall only be conducted to determine the feasibility of the alterna ve fuel type for the emission source, and shall be conducted only for as long as necessary to make the determination.

[40 CFR pt. 241, Minn. R. 7007.0800, subp. 2(A)&(B)]

Subject

Item ID

Sequence

Number Requirement

COMG 9 41

Cont. from Above:7. For each alternative fuel test burn, the Permittee shall keep records of:a) the date and time of the start and stop of the alternative fuel test burn, b) the quantity, type, and characteristics (heat content in Btu/lb, ash content, moisture content, contaminant content, as applicable) of the alternative fuel used during each test burn, c) if wood was combusted, the Permittee shall document the method(s) used to determine the wood met the definition of Clean Cellulosic Biomass, and the results of any analyses conducted to make such determination, d) the actual emissions that will result from each alternative fuel test burn, and e) the actual emissions that would occur if subbituminous coal was combusted during the test burn time period, f) the actual emissions increase that will occur from the test burn of the alternative fuel compared to the emissions that would occur if subbituminous coal was combusted during the test burn time period. g) the net emissions increase for each pollutant regulated under 40 CFR Section 52.21 from all test burns during the previous 12‐month period. These records shall be made no later than 24 hours after completion of each test burn except item 7c shall be calculated and recorded prior to each test burn. [40 CFR pt. 241, Minn. R. 7007.0800, subp. 2(A)&(B)]

COMG 9 42

TRANSPORT RULE REQUIREMENTS

Transport Rule (TR) NOx Annual Trading Program Requirements.

The Permittee shall comply with the TR NOx Annual Trading Program requirements contained in Appendix G. [40 CFR 97.430 ‐ 97.435]

COMG 9 43

Designated representa ve requirements.

The owners and operators shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with 40 CFR Sections 97.413 through 97.418. [40 CFR 97.406(a)]

COMG 9 44

TR NOx Emissions monitoring, repor ng, and recordkeeping requirements.

1) The owners and operators 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)]

Subject

Item ID

Sequence

Number Requirement

COMG 9 45

TR NOx Annual emissions limita on.

i) As of the allowance transfer deadline (midnight of March 1 (if it is a business day), or midnight of the first business day thereafter (if March 1 is not a business day)) for a control period in a given year, the owners and operators of each TR NOx Annual source and each TR NOx Annual unit at the source 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 owners and operators of the source and each TR NOx Annual unit at the source shall hold the TR NOx Annual allowances required for deduction under 40 CFR Section 97.424(d); and B) The owners and operators of the source and each TR NOx Annual unit at the source 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)]

COMG 9 46

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 owners and operators 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 therea er (if November 1 is not a business day), immediately a er such control period.[40 CFR 97.406(c)(2)(i)‐(v)]

Subject

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Number Requirement

COMG 9 46

Cont. from Above: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 Section 97.410(a) and the state's variability limit under 40 CFR Section 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 owners and operators fail 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 owners and operators 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 owners and operators fail 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)]

COMG 9 47

Compliance periods.

i) A TR NOx Annual unit shall be subject to the requirements under 40 CFR Section 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 cer fica on requirements under 40 CFR 97.430(b) and for each control period therea er.

ii) A TR NOx Annual unit shall be subject to the requirements under 40 CFR Section 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)]

COMG 9 48

Vintage of allowances held for compliance.

i) A TR NOx Annual allowance held for compliance with the requirements under 40 CFR Section 97.406(c)(1)(i) above for a control period in a given year must be a TR NOx Annual allowance that was allocated for 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 Section 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)]

COMG 9 49

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)]

Subject

Item ID

Sequence

Number Requirement

COMG 9 50

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)]

COMG 9 51 Property right. A TR NOx Annual allowance does not constitute a property right. [40 CFR 97.406(c)(7)]

COMG 9 52

Additional recordkeeping and reporting requirements.

1) Unless otherwise provided, the owners and operators of each TR NOx Annual source and each TR NOx Annual unit at the source 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 Section 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)]

COMG 9 53

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 owners and operators of such source and of the TR NOx Annual unit shall also apply to the owners and operators of such unit.

2) Any provision of the TR NOx Annual Trading Program that applies to a TR NOx Annual unit or the designated representative of a TR NOx Annual unit shall also apply to the owners and operators of such unit. [40 CFR 97.406(f)]

Subject

Item ID

Sequence

Number Requirement

COMG 9 54

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 owners and operators, 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 97.406(g)]

COMG 9 55

TRANSPORT RULE REQUIREMENTS

Transport Rule (TR) SO2 Group 2 Trading Program Requirements.

The Permittee shall comply with the TR SO2 Group 2 Trading Program Requirements contained in Appendix G. [40 CFR 97.730 ‐ 97.735]

COMG 9 56

Designated representative requirements.

The owners and operators 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)]

COMG 9 57

TR SO2 Group 2 Emissions monitoring, reporting, and recordkeeping requirements.

1) The owners and operators, and the designated representative, of each TR SO2 Group 2 source and each 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 Section 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 paragraph (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)]

Subject

Item ID

Sequence

Number Requirement

COMG 9 58

TR SO2 Group 2 emissions limitation.

i) As of the allowance transfer deadline (midnight of March 1 (if it is a business day), or midnight of the first business day thereafter (if March 1 is not a business day)) for a control period in a given year, the owners and operators of each TR SO2 Group 2 source and each TR SO2 Group 2 unit at the source 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 owners and operators of the source and each TR SO2 Group 2 unit at the source shall hold the TR SO2 Group 2 allowances required for deduction under 40 CFR Section 97.724(d); and B) The owners and operators of the source and each TR SO2 Group 2 unit at the source 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)]

COMG 9 59

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 owners and operators 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. [40 CFR 97.706(c)(2)(i)‐(v)]

Subject

Item ID

Sequence

Number Requirement

COMG 9 59

Cont. from Above: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 owners and operators fail 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 owners and operators 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 owners and operators 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)]

COMG 9 60

Compliance Periods.

i) A TR SO2 Group 2 unit shall be subject to the requirements under 40 CFR Section 97.706(c)(1) above for 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)]

COMG 9 61

Vintage of allowances held for compliance.

i) A TR SO2 Group 2 allowance held for compliance with the requirements under 40 CFR Section 97.706(c)(1)(i) above for a control period in a given year must be a TR SO2 Group 2 allowance that was allocated for 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 Section 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)]

COMG 9 62

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)]

Subject

Item ID

Sequence

Number Requirement

COMG 9 63

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)]

COMG 9 64

Property right.

A TR SO2 Group 2 allowance does not constitute a property right. [40 CFR 97.706(c)(7)]

COMG 9 65

Additional recordkeeping and reporting requirements.

1) Unless otherwise provided, the owners and operators of each TR SO2 Group 2 source and each TR SO2 Group p2 unit at the source 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)]

COMG 9 66

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 owners and operators of such source and of the TR SO2 Group 2 units at the source.

2) Any provision of the TR SO2 Group 2 Trading Program that applies to a TR SO2 Group 2 unit or the designated representative of a TR SO2 Group 2 unit shall also apply to the owners and operators of such unit. [40 CFR 97.706(f)]

Subject

Item ID

Sequence

Number Requirement

COMG 9 67

Effect on other authori es.

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 owners or operators, 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)]

COMG 10 1

The Permittee shall follow the Reasonable Possibility requirements of 40 CFR 52.21(r)(6) and Minn. R. ch. 7007 as listed under subject item TFAC1 of this permit for the sources affected by the 2015 coal stockpile expansion that increased throughput of coal received and handled, and added 10 portable conveyors (11 drop points) to assist in moving the coal across the stockpile. These affected sources are:

1. FUGI3 Unpaved Road Dust (Coal Stockpile Segment modified due to increased bulldozer ac vity); 2. FUGI6 Coal Stockpile & Fly Ash Pond Maintenance (Coal Stockpile Bulldozer Maintenance Segment modified due to increased bulldozer ac vity); 3. FUGI9 Coal Stockpile ‐ Wind Erosion (Ac ve Pile Segment modified due to increased footprint); 4. FUGI11 Coal Stockpile Material Handling (Existing Coal Drop Onto Pile Segment modified due to increased coal handling, and Ten New Portable Conveyors/Eleven Drop Points Segment); 5. EQUI111 Rail Unloading (DC‐7; modified due to increased coal throughput); 6. EQUI112 Lowering Well/Silos (DC‐4) & Coal Silo (modified due to increased coal throughput). [Minn. R. 7007.0800, subp. 2(A), Minn. R. 7007.0800, subps. 4‐5, Minn. R. 7007.1200, subp. 4, Minn. R. 7007.3000, Title I Condition: 40 CFR 52.21(r)(6)]

EQUI 1 1

Particulate Matter <= 0.30 grains per dry standard cubic foot of exhaust gas unless required to further reduce emissions to comply with the less stringent limit of either Minn. R. 7011.0730 or Minn. R. 7011.0735. [Minn. R. 7011.0715, subp. 1(A)]

EQUI 1 2 Opacity <= 20 percent opacity. [Minn. R. 7011.0715, subp. 1(B)]

EQUI 1 3

Vent all EQUI1 (EU011) emissions to fabric filter TREA37 (CE007). TREA37 shall meet the applicable requirements in COMG3. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 3 1



EQUI 3 3


EQUI 4 1



EQUI 4 3


EQUI 5 1


EQUI 5 2

Particulate Matter <= 0.005 grains per dry standard cubic foot. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

EQUI 5 3

PM < 10 micron <= 0.005 grains per dry standard cubic foot. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]


EQUI 5 5

Vent all EQUI5 (EU019) emissions to fabric filter TREA1 (CE016). TREA1 shall meet the applicable requirements in COMG3. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

Subject

Item ID

Sequence

Number Requirement

EQUI 6 1


EQUI 6 2


EQUI 6 3



EQUI 6 5


EQUI 7 1


EQUI 7 2


EQUI 7 3



EQUI 7 5


EQUI 23 1

The Permittee is subject to pt. 63, subp. ZZZZ because it owns and operates EQUI23 (EU033; a stationary RICE) located at a major HAP emissions source, and EQUI23 is not being tested at a stationary RICE test cell/stand. [40 CFR 63.6585, Minn. R. 7011.8150]

EQUI 23 2

EQUI23 is a stationary RICE subject to 40 CFR pt. 63, subp. ZZZZ because it has a site rating of equal to or less than 500 brake HP, is located at a major source of HAP emissions, and the Permittee commenced construction of EQUI23 on or after June 12, 2006. [40 CFR 63.6590(a)(2)(ii), Minn. R. 7011.8150]

EQUI 23 3

Stationary RICE subject to Regulations under 40 CFR Part 60:

EQUI23 is an affected source that meets the criteria in paragraph (c)(7) of Section 63.6590 (EQUI23 is a new emergency stationary compression ignition RICE because EQUI23 construction commenced on or after June 12, 2006, has a site rating of less than or equal to 500 brake HP, and is located at a major HAP source). Therefore, EQUI23 meets the requirements of pt. 63, subp. ZZZZ by meeting the requirements of 40 CFR pt. 60, subp. IIII. No further requirements apply to EQUI23 under subp. ZZZZ. [40 CFR 63.6590(c)(7), Minn. R. 7011.8150]

Subject

Item ID

Sequence

Number Requirement

EQUI 23 4

"Stationary reciprocating internal combustion engine (RICE)" means any reciprocating internal combustion engine which uses reciprocating motion to convert heat energy into mechanical work and which is not mobile. Stationary RICE differ from mobile RICE in that a stationary RICE is not a non‐road engine as defined at 40 CFR 1068.30, and is not used to propel a motor vehicle or a vehicle used solely for competition.

"Emergency stationary RICE" means any stationary reciprocating internal combustion engine that meets all of the criteria in paragraphs (1) through (3) of this definition. All emergency stationary RICE must comply with the requirements specified in Section 63.6640(f) in order to be considered emergency stationary RICE. If the engine does not comply with the requirements specified in Section 63.6640(f), then it is not considered to be an emergency stationary RICE under pt. 63, subp. ZZZZ.

(1) The stationary RICE is operated to provide electrical power or mechanical work during an emergency situation. Examples include stationary RICE used to produce power for critical networks or equipment (including power supplied to portions of a facility) when electric power from the local utility (or the normal power source, if the facility runs on its own power production) is interrupted, or stationary RICE used to pump water in the case of fire or flood, etc. (2) The stationary RICE is operated under limited circumstances for situations not included in paragraph (1) of this definition, as specified in Section 63.6640(f).(3) The stationary RICE operates as part of a financial arrangement with another entity in situations not included in paragraph (1) of this definition only as allowed in Section 63.6640(f)(2)(ii) or (iii) and Section 63.6640(f)(4)(i) or (ii).

Note that as of May 4, 2016, the U.S. Court of Appeals for the D.C. Circuit reversed and remanded paragraphs 63.6640(f)(2)(ii) and (iii) back to EPA for further action. [40 CFR 63.6675, Minn. R. 7011.8150]

EQUI 23 5

"Stationary internal combustion engine" means any internal combustion engine, except combustion turbines, that converts heat energy into mechanical work and is not mobile. Stationary ICE differ from mobile ICE in that a stationary internal combustion engine is not a nonroad engine as defined at 40 CFR 1068.30 (excluding paragraph (2)(ii) of that definition), and is not used to propel a motor vehicle, aircraft, or a vehicle used solely for competition. Stationary ICE include reciprocating ICE, rotary ICE, and other ICE, except combustion turbines. "Emergency stationary internal combustion engine" means any stationary internal combustion engine whose operation is limited to emergency situations and required testing and maintenance. Examples include stationary ICE used to produce power for critical networks or equipment (including power supplied to portions of a facility) when electric power from the local utility (or the normal power source, if the facility runs on its own power production) is interrupted, or stationary ICE used to pump water in the case of fire or flood, etc. Stationary CI ICE used to supply power to an electric grid or that supply power as part of a financial arrangement with another entity are not considered to be emergency engines. [40 CFR 60.4219, Minn. R. 7011.2305]

EQUI 23 6 Opacity <= 20 percent opacity once operating temperatures have been attained. [Minn. R. 7011.2300, subp. 1]

EQUI 23 7

Opacity <= 20 percent opacity during acceleration mode; 15 percent opacity during lugging mode; and 50 percent opacity during the peaks in either the acceleration or lugging modes. [40 CFR 60.4202(a)(2), 40 CFR 60.4205(b), 40 CFR 89.113(a), Minn. R. 7011.2305]

EQUI 23 8

Carbon Monoxide <= 3.5 grams per kilowatt‐hour. [40 CFR 60.4202(a)(2), 40 CFR 60.4205(b), 40 CFR 89.112(a), Minn. R. 7011.2305]

EQUI 23 9

NMHC+NOx <= 4.0 grams per kilowatt‐hour. [40 CFR 60.4202(a)(2), 40 CFR 60.4205(b), 40 CFR 89.112(a), Minn. R. 7011.2305]

EQUI 23 10

Particulate Matter <= 0.20 grams per kilowatt‐hour. [40 CFR 60.4202(a)(2), 40 CFR 60.4205(b), 40 CFR 89.112(a), Minn. R. 7011.2305]

Subject

Item ID

Sequence

Number Requirement

EQUI 23 11

Sulfur Dioxide <= 0.5 pounds per million Btu heat input. Combustion of fuel with a sulfur content of 0.5 percent by weight or less meets this requirement. No later than January 31, 2018, the Permittee must not allow any gases that contain sulfur dioxide in excess of 0.0015 pounds per million Btu actual heat input to be discharged into the atmosphere from the engine unless the agency establishes an alternative sulfur dioxide emission limit in an air emission permit that includes a demonstration through modeling of compliance with the sulfur dioxide standards in Minn. R. 7009.0080. [Minn. R. 7011.2300, subp. 2]

EQUI 23 12

If the Permittee conducts performance tests on EQUI23 in‐use, the Permittee must meet the NTE standards as indicated in Section 60.4212. [40 CFR 60.4205(e), Minn. R. 7011.2305]

EQUI 23 13

The Permittee must operate and maintain EQUI23 so that it achieves the emission standards as required in Sections 60.4204 and 60.4205 over the entire life of EQUI23. [40 CFR 60.4206, Minn. R. 7011.2305]

EQUI 23 14

Use diesel fuel that meets the requirements of 40 CFR Sec on 80.510(b):

(1) Sulfur content 15 ppm maximum for Non‐Road diesel fuel.

(2) Cetane index or aroma c content, as follows:

(i) A minimum cetane index of 40; or

(ii) A maximum aromatic content of 35 volume percent. [40 CFR 60.4207(b), Minn. R. 7011.2305]EQUI 23 15 Install a non‐resettable hour meter prior to EQUI23 startup. [40 CFR 60.4209(a), Minn. R. 7011.2305]

EQUI 23 16

The Permi ee must do all of the following, except as permi ed under Sec on 60.4211(g):

(1) Operate and maintain EQUI23 (and any control device) according to the manufacturer's emission‐related wri en instruc ons;

(2) Change only those emission‐related se ngs that are permi ed by the manufacturer; and

(3) Meet applicable requirements of 40 CFR pts. 89, 94 and/or 1068. [40 CFR 60.4211(a), Minn. R. 7011.2305]

EQUI 23 17

The Permittee must comply with pt. 60, subp. IIII by purchasing an engine certified to the emission standards in Section 60.4205(b), as applicable, for the same model year and maximum engine power. EQUI23 must be installed and configured according to the manufacturer's emission‐related specifications, except as permitted in Section 60.4211(g). [40 CFR 60.4211(c), Minn. R. 7011.2305]

EQUI 23 18

The Permittee must operate EQUI23 according to the requirements in Section 60.4211(f)(1) through (3). In order for EQUI23 to be considered an emergency stationary ICE under pt. 60, subp. IIII, any operation other than emergency operation, maintenance and testing, emergency demand response, and operation in non‐emergency situations for 50 hours per year, as described in Section 60.4211(f)(1) through (3) is prohibited. If the Permittee does not operate EQUI23 according to the requirements in Section 60.4211(f)(1) through (3), EQUI23 will not be considered an emergency engine under subp. IIII and must meet all requirements for non‐emergency engines. Note that as of May 4, 2016, the U.S. Court of Appeals for the D.C. Circuit reversed and remanded paragraphs 60.4211(f)(2)(ii) and (iii) back to EPA for further action. [40 CFR 60.4211(f), Minn. R. 7011.2305]

Subject

Item ID

Sequence

Number Requirement

EQUI 23 19

(1) There is no me limit on the use of EQUI23 in emergency situa ons.

(2) The Permittee may operate EQUI23 for any of the purposes specified in paragraphs (f)(2)(i) of Section 60.4211 for a maximum of 100 hours per calendar year. Any operation for non‐emergency situations as allowed by paragraph (f)(3) of Section 60.4211 counts as part of the 100 hours per calendar year allowed by Section 60.4211(f)(2).

(2)(i) EQUI23 may be operated 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 EQUI23. 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 EQUI23 beyond 100 hours per calendar year. [40 CFR 60.4211(f)(1)&(f)(2)(i), Minn. R. 7011.2305]

EQUI 23 20

(3) EQUI23 may be operated 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 and emergency demand response provided in Section 60.4211(f)(2). Except as provided in Section 60.4211(f)(3)(i), the 50 hours per calendar year for non‐emergency situations cannot be used for peak shaving or non‐emergency demand response, or to generate income for a facility to an electric grid or otherwise supply power as part of a financial arrangement with another entity.(i) The 50 hours per year for non‐emergency situations can be used to supply power as part of a financial arrangement with another entity if all of the following conditions are met:

(A) EQUI23 is dispatched by the local balancing authority or local transmission and distribution system operator;(B) The dispatch is intended to mitigate local transmission and/or distribution limitations so as to avert potential voltage collapse or line overloads that could lead to the interruption of power supply in a local area or region.(C) The dispatch follows reliability, emergency operation or similar protocols that follow specific NERC, regional, state, public utility commission or local standards or guidelines.(D) The power is provided only to the facility itself or to support the local transmission and distribution system.

(E) The Permittee identifies and records the entity that dispatches EQUI23 and the specific NERC, regional, state, public utility commission or local standards or guidelines that are being followed for dispatching EQUI23. The local balancing authority or local transmission and distribution system operator may keep these records on behalf of the Permittee. [40 CFR 60.4211(f)(3), Minn. R. 7011.2305]

EQUI 23 21

If the Permittee does not install, configure, operate, and maintain EQUI23 and control device according to the manufacturer's emission‐related written instructions, or the Permittee changes EQUI23 emission‐related settings in a way that is not permitted by the manufacturer, the Permittee must keep a maintenance plan and records of conducted maintenance and must, to the extent practicable, maintain and operate EQUI23 in a manner consistent with good air pollution control practice for minimizing emissions. In addition, the Permittee must conduct an initial performance test to demonstrate compliance with the applicable emission standards within 1 year of startup, or within 1 year after EQUI23 and control device is no longer installed, configured, operated, and maintained in accordance with the manufacturer's emission‐related written instructions, or within 1 year after the Permittee changes emission‐related settings in a way that is not permitted by the manufacturer. [40 CFR 60.4211(g)(2), Minn. R. 7011.2305]

EQUI 23 22

If the Permittee conducts performance tests (as required under Section 60.4211(g)), the tests must be completed in accordance with 40 CFR Section 60.4212(a) through 40 CFR Section 60.4212(e), as applicable. [40 CFR 60.4212, Minn. R. 7011.2305]

Subject

Item ID

Sequence

Number Requirement

EQUI 23 23

Commencing 2011, if EQUI23 does not meet the standards applicable to non‐emergency engines in the applicable model year, the Permittee must keep records of EQUI23 operation in emergency and non‐emergency service that are recorded through the non‐resettable hour meter. The Permittee must record the time of EQUI23 operation and the reason EQUI23 was in operation during that time. [40 CFR 60.4214(b), Minn. R. 7011.2305]

EQUI 23 24

The Permittee shall comply with the applicable requirements in table 8 of pt. 60, subp. III (applicable requirements of pt. 60, subp. A General Provisions in Sections 60.1 through 60.19). [40 CFR 60.4218, Minn. R. 7011.2305]

EQUI 23 25

Fuel type: Diesel fuel meeting the requirements of 40 CFR Section 80.510(c) by design. [Minn. R. 7005.0100, subp. 35a]

EQUI 23 26

Recordkeeping ‐ Fuel Type: The Permittee shall keep records of the type of fuel burned in EQUI23. [Minn. R. 7007.0800, subps. 4‐5]

EQUI 23 27

Recordkeeping ‐ Hours of Operation: The Permittee shall maintain documentation on site that EQUI23 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, for calculating potential emissions based on 500 operating hours per year. [Minn. R. 7007.0800, subps. 4‐5]

EQUI 23 28

The Permittee shall implement the best management practices in Appendix I of this permit when installing and operating EQUI23. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 28 1

The Permittee shall conduct COMS calibration error audit : Due quarterly for EQUI28/Boiler 3 COMS. Conduct the audit according to Procedure 3 of 40 CFR pt. 60, Appendix F. Quarterly performance audits will include optical alignment, calibration error, and zero compensation. Sources that achieve quality assured data for four consecutive quarters may reduce audit frequency to semi‐annually. If an audit is failed, the source must resume quarterly audits to demonstrate performance again for four consecutive quarters. [Minn. R. 7017.1215]

EQUI 29 1


EQUI 30 1


EQUI 34 1


EQUI 35 1

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 opera ng hours). No linearity check is required for a flow monitor.

Conduct a leak check in accordance with Appendix B, Section 2.2.2. Perform a leak check at least once during each QA operating quarter. [40 CFR pt. 75, App. B, Sect. 2.2.2]

Subject

Item ID

Sequence

Number Requirement

EQUI 35 2

The Permittee shall conduct CEMS relative accuracy test audit (RATA) : Due semiannually. The Permittee shall perform a RATA on all CEMS required by the Acid Rain Program once every two successive QA operating quarters (calendar quarter in which there are at least 168 unit operating hours), according to the requirements at 40 CFR pt. 75, Appendix B, Section 2.3.1. RATAs 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, App. B, Sec. 2.3.1]

EQUI 36 9

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). Conduct the linearity check in accordance with procedures in 40 CFR pt. 75, Appendix B, Sections 2.2.1 and Appendix A, Section 6.2, and the leak check in accordance with Appendix B, Section 2.2.2. Perform a leak check and a linearity check at least once during each QA operating quarter. [40 CFR pt. 75, App. B, Sect. 2.2]

EQUI 36 10


EQUI 37 9


EQUI 37 10


EQUI 38 1


EQUI 38 2


EQUI 39 1



Subject

Item ID

Sequence

Number Requirement

EQUI 39 2


EQUI 40 9


EQUI 40 10


EQUI 41 9


EQUI 41 10


EQUI 42 1


EQUI 42 2


EQUI 43 1



Subject

Item ID

Sequence

Number Requirement

EQUI 43 2


EQUI 44 9


EQUI 44 10


EQUI 45 9


EQUI 45 10


EQUI 50 1


EQUI 50 2


EQUI 51 1



Subject

Item ID

Sequence

Number Requirement

EQUI 51 2


EQUI 52 1

The Permittee shall conduct CEMS cylinder gas audit (CGA) : Due semiannually (by the end of every second quality assurance operating quarter in which there are at least 168 EQUI85 operating hours) on EQUI52 (EQUI85 CO CEMS). A CGA is not required during any quarter in which a relative accuracy test audit was performed. CGAs shall be conducted according to Minn. R. 7017.1170, subp. 4a(A).

If EQUI85 is not in operation on the CGA due date, the Permittee has a grace period of 168 EQUI85 operating hours to perform the CGA. If the CGA is not completed by the end of the 168‐operating‐hour grace period, EQUI52 data is invalid beginning with the first EQUI85 operating hour following grace period expiration. Nothing in Minn. R. 7017.1170, subp. 4a relieves the Permittee's obligation to comply with quality assurance provisions imposed by other applicable standards or compliance documents. [Minn. R. 7017.1170, subp. 4a]

EQUI 52 2

The Permittee shall conduct a relative accuracy test audit : Due annually (by the end of every fourth quality assurance operating quarter). Relative Accuracy Test Audits (RATAs) shall be conducted and RATA frequency may be reduced according to the requirements of Minn. R. 7017.1170, subp. 5a.

If EQUI85 is not in operation on the EQUI52 RATA due date, the Permittee has a grace period of 720 operating hours to perform the RATA. If the RATA is not completed by the end of the 720‐operating‐hour grace period, EQUI52 data is invalid beginning with the first EQUI85 operating hour following grace period expiration. [Minn. R. 7017.1170, subp. 5a]

EQUI 52 3

CEMS Recertification Test: The Permittee shall recertify the CEMS no later than 90 days after completion of any change described at Minn. R. 7017.1050, subp. 2 which invalidates the monitor's certification status. [Minn. R. 7017.1050]

EQUI 53 4


EQUI 53 5


EQUI 54 4


Subject

Item ID

Sequence

Number Requirement

EQUI 54 5


EQUI 55 1


EQUI 55 2


EQUI 71 1

The Permittee shall conduct CEMS cylinder gas audit (CGA) : Due semiannually (by the end of every second quality assurance operating quarter in which there are at least 168 EQUI100 operating hours) on EQUI71 (EQUI100 CO CEMS). A CGA is not required during any quarter in which a relative accuracy test audit was performed. CGAs shall be conducted according to Minn. R. 7017.1170, subp. 4a(A).

If EQUI100 is not in operation on the CGA due date, the Permittee has a grace period of 168 EQUI100 operating hours to perform the CGA. If the CGA is not completed by the end of the 168‐operating‐hour grace period, EQUI71 data is invalid beginning with the first EQUI100 operating hour following grace period expiration. Nothing in Minn. R. 7017.1170, subp. 4a relieves the Permittee's obligation to comply with quality assurance provisions imposed by other applicable standards or compliance documents. [Minn. R. 7017.1170, subp. 4a]

EQUI 71 2

The Permittee shall conduct a relative accuracy test audit : Due annually (by the end of every fourth quality assurance operating quarter). Relative Accuracy Test Audits (RATAs) shall be conducted and RATA frequency may be reduced according to the requirements of Minn. R. 7017.1170, subp. 5a.

If EQUI100 is not in operation on the EQUI71 RATA due date, the Permittee has a grace period of 720 EQUI100 operating hours to perform the RATA. If the RATA is not completed by the end of the 720‐operating‐hour grace period, EQUI71 data is invalid beginning with the first EQUI100 operating hour following grace period expiration. [Minn. R. 7017.1170, subp. 5a]

EQUI 71 3

CEMS Recertification Test: The Permittee shall recertify the CEMS no later than 90 days after completion of any change described at Minn. R. 7017.1050, subp. 2 which invalidates the monitor's certification status. [Minn. R. 7017.1050]

EQUI 81 1

The Permittee is subject to pt. 63, subp. ZZZZ because it owns and operates EQUI81 (EU023; a stationary RICE) located at a major HAP emissions source, and EQUI81 is not being tested at a stationary RICE test cell/stand. [40 CFR 63.6585, Minn. R. 7011.8150]

EQUI 81 2

EQUI81 is a new stationary RICE subject to 40 CFR pt. 63, subp. ZZZZ because it has a site rating of equal to or less than 500 brake HP, is located at a major source of HAP emissions, and the Permittee commenced construction of EQUI81 on or after June 12, 2006. [40 CFR 63.6590(a)(2)(ii), Minn. R. 7011.8150]

Subject

Item ID

Sequence

Number Requirement

EQUI 81 3

Sta onary RICE subject to Regula ons under 40 CFR Part 60:

EQUI81 is an affected source that meets the criteria in paragraph (c)(7) of Section 63.6590 (EQUI81 is a new emergency stationary compression ignition RICE because EQUI81 construction commenced on or after June 12, 2006, has a site rating of less than or equal to 500 brake HP, and is located at a major HAP source). Therefore, EQUI81 meets the requirements of pt. 63, subp. ZZZZ by meeting the requirements of 40 CFR pt. 60, subp. IIII. No further requirements apply to EQUI81 under subp. ZZZZ. [40 CFR 63.6590(c)(7), Minn. R. 7011.8150]

EQUI 81 4





EQUI 81 5

"Stationary internal combustion engine" means any internal combustion engine, except combustion turbines, that converts heat energy into mechanical work and is not mobile. Stationary ICE differ from mobile ICE in that a stationary internal combustion engine is not a nonroad engine as defined at 40 CFR 1068.30 (excluding paragraph (2)(ii) of that definition), and is not used to propel a motor vehicle, aircraft, or a vehicle used solely for compe on. Sta onary ICE include reciproca ng ICE, rotary ICE, and other ICE, except combus on turbines. "Emergency stationary internal combustion engine" means any stationary internal combustion engine whose operation is limited to emergency situations and required testing and maintenance. Examples include stationary ICE used to produce power for critical networks or equipment (including power supplied to portions of a facility) when electric power from the local utility (or the normal power source, if the facility runs on its own power production) is interrupted, or stationary ICE used to pump water in the case of fire or flood, etc. Stationary CI ICE used to supply power to an electric grid or that supply power as part of a financial arrangement with another entity are not considered to be emergency engines. [40 CFR 60.4219, Minn. R. 7011.2305]


Subject

Item ID

Sequence

Number Requirement

EQUI 81 7

Opacity <= 20 percent opacity during acceleration mode; 15 percent opacity during lugging mode; and 50 opacity percent during the peaks in either the acceleration or lugging modes. [40 CFR 60.4202(a)(2), 40 CFR 60.4205(b), 40 CFR 89.113(a), Minn. R. 7011.2305]

EQUI 81 8

Carbon Monoxide <= 3.0 grams per kilowatt‐hour. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

EQUI 81 9


EQUI 81 10


EQUI 81 11


EQUI 81 12


EQUI 81 13


EQUI 81 14


EQUI 81 15

Use diesel fuel that meets the requirements of 40 CFR Sec on 80.510(b):


(2) Cetane index or aroma c content, as follows:


(ii) A maximum aromatic content of 35 volume percent. [40 CFR 60.4207(b), Minn. R. 7011.2305]

EQUI 81 16 Install a non‐resettable hour meter prior to startup of the engine. [40 CFR 60.4209(a), Minn. R. 7011.2305]

EQUI 81 17

The Permi ee must do all of the following, except as permi ed under Sec on 60.4211(g): (1) Operate and maintain EQUI81 (and any control device) according to the manufacturer's emission‐related wri en instruc ons; (2) Change only those emission‐related se ngs that are permi ed by the manufacturer; and


EQUI 81 18

The Permittee must comply with pt. 60, subp. IIII by purchasing an engine certified to the emission standards in Section 60.4205(b), as applicable, for the same model year and maximum engine power. EQUI81 must be installed and configured according to the manufacturer's emission‐related specifications, except as permitted in Section 60.4211(g). [40 CFR 60.4211(c), Minn. R. 7011.2305]

Subject

Item ID

Sequence

Number Requirement

EQUI 81 19


EQUI 81 20




EQUI 81 21

(3) EQUI81 may be operated 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 and emergency demand response provided in Section 60.4211(f)(2). Except as provided in Section 60.4211(f)(3)(i), the 50 hours per calendar year for non‐emergency situations cannot be used for peak shaving or non‐emergency demand response, or to generate income for a facility to an electric grid or otherwise supply power as part of a financial arrangement with another en ty.

(i) The 50 hours per year for non‐emergency situa ons can be used to supply power as part of a financial arrangement with another entity if all of the following conditions are met

(A) EQUI81 is dispatched by the local balancing authority or local transmission and distribu on system operator;(B) The dispatch is intended to mi gate local transmission and/or distribu on limita ons so as to avert poten al voltage collapse or line overloads that could lead to the interrup on of power supply in a local area or region.(C) The dispatch follows reliability, emergency opera on or similar protocols that follow specific NERC, regional, state, public u lity commission or local standards or guidelines.(D) The power is provided only to the facility itself or to support the local transmission and distribu on system.

(E) The Permi ee iden fies and records the en ty that dispatches EQUI81 and the specific NERC, regional, state, public utility commission or local standards or guidelines that are being followed for dispatching EQUI81. The local balancing authority or local transmission and distribution system operator may keep these records on behalf of the Permittee. [40 CFR 60.4211(f)(3), Minn. R. 7011.2305]

Subject

Item ID

Sequence

Number Requirement

EQUI 81 22

If the Permittee does not install, configure, operate, and maintain EQUI81 and control device according to the manufacturer's emission‐related written instructions, or the Permittee changes EQUI81 emission‐related settings in a way that is not permitted by the manufacturer, the Permittee must keep a maintenance plan and records of conducted maintenance and must, to the extent practicable, maintain and operate EQUI81 in a manner consistent with good air pollution control practice for minimizing emissions. In addition, the Permittee must conduct an initial performance test to demonstrate compliance with the applicable emission standards within 1 year of startup, or within 1 year after EQUI81 and control device is no longer installed, configured, operated, and maintained in accordance with the manufacturer's emission‐related written instructions, or within 1 year after the Permittee changes emission‐related settings in a way that is not permitted by the manufacturer. [40 CFR 60.4211(g)(2), Minn. R. 7011.2305]

EQUI 81 23


EQUI 81 25

The Permittee shall comply with the applicable requirements in table 8 of pt. 60, subp. III (applicable requirements of pt. 60, subp. A General Provisions in Sections 60.1 through 60.19). [40 CFR 60.4218, Minn. R. 7011.2305]

EQUI 81 26


EQUI 81 27


EQUI 81 28


EQUI 81 28


EQUI 82 1

Particulate Matter <= 0.1 pounds per million Btu heat input 24‐hour block average. [Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

EQUI 82 2

Particulate Matter <= 0.6 pounds per million Btu heat input. Refer to COMG1 for applicable sulfur dioxide limits, and COMG7 for additional applicable emission limits. [Minn. R. 7011.0510, subp. 1]

EQUI 82 4

The Permittee shall Continuously Operate TREA16 and TREA14 at EQUI82 and EQUI83, respectively, such that the units achieve and maintain a combined emission rate of Filterable Particulate Matter <= 0.015 pounds per million Btu heat input 3‐hour average; provided that if the Permittee chooses to Reroute flue gas from EQUI82 and EQUI83, then EQUI82, EQUI83, and EQUI100 shall achieve and maintain a combined Filterable Particulate Ma er Emission Rate of no greater than 0.015 pounds per million Btu heat input based on a 3‐hour average.

The Permittee shall conduct stack tests each year on each unit or units served by a common stack in the Minnesota Power System to determine compliance with the PM Emission Rates established by the Consent Decree, unless the Permittee seeks and obtains EPA approval to forego filterable PM stack testing and instead demonstrate compliance with an applicable filterable PM Emission Rate using CEMS on a 3‐Hour Rolling Average Emission Rate basis. This requirement is repeated at 6.24.2. [CAAA of 1990, Minn. R. 7007.0100, subp 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI 82 5

Opacity <= 20 percent opacity 6‐minute average except for one 6‐minute period per hour of not more than 60 percent opacity. [Minn. R. 7011.0510, subp. 2]

Subject

Item ID

Sequence

Number Requirement

EQUI 82 6

The Permittee shall optimize combustion and Continuously Operate the Unit 1/EQUI82 ROFA (TREA12) and SNCR (TREA15) control devices such that EQUI82 achieves and maintains Nitrogen Oxides <= 0.200 pounds per million Btu heat input 30‐day rolling average.

If the Permittee chooses to Reroute EQUI82 and EQUI83 through an FGD device that treats the flue gas from such Units and EQUI100/Boswell Unit 3, the Permittee shall continue to Continuously Operate the ROFA and SNCR control devices at such Units and maintain a 30‐Day Rolling Average Emission Rate for NOx no greater than 0.200 pounds per million Btu heat input at each Unit as measured before flue gases from EQUI82 and EQUI83 combine with the flue gases from EQUI100/Boswell Unit 3.

If the Permittee chooses to Reroute the flue gas from EQUI82 and EQUI83 and demonstrates to the reasonable satisfaction of EPA and the MPCA that it is practically infeasible to obtain a representative measurement of NOx emissions for EQUI82 and/or EQUI83 consistent with 40 C.F.R. Part 60, Appendix A, Method 1 and 40 C.F.R. Part 75, Appendix A before the flue gases from EQUI82 and EQUI83 combine with the flue gases from EQUI100, then the Permittee shall continue to Continuously Operate the ROFA and SNCR control devices at such Units, and shall demonstrate that it is in compliance with the 30‐day Rolling Average Emission Rate for NOx for EQUI82 and EQUI83 by showing that the combined 30‐Day Rolling Average Emission Rate for NOx for EQUI82, EQUI83, and EQUI100 is no greater than the Heat‐Input Weighted Average Emission Rate. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI 82 7

EQUI82 Nitrogen Oxides <= 0.46 pounds per million Btu heat input calendar year average. The Permittee shall determine the annual average NOx emission rate, in pounds per million Btu heat input, using the methods and procedures specified in part 75.

Refer to COMG9 for additional Acid Rain Program requirements. [40 CFR 76.7(a)(2)&(b), Minn. R. 7011.0553]

EQUI 82 8

Permi ed Fuels: subbituminous coal, natural gas, propane, and used oil.

EQUI82 meets the definition of a coal‐fired electric utility steam generating unit at 40 CFR Section 63.10042 when EQUI82 burns coal for more than 10.0 percent of the average annual heat input during the three previous calendar years or for more than 15.0 percent of the annual heat input during any one of those calendar years.

Propane is only permitted for use in a propane‐fired 'SHOCKSystem' that cleans boiler firebox surfaces of slag and ash in EQUI82. Used oil shall meet the definition of such at 40 CFR Section 279.1 and refers only to incidental amounts of oil leaked onto coal by coal‐handling equipment.

The Permittee may also burn nonhazardous secondary materials that are not solid wastes when such materials are evaluated and authorized according to the requirements of 40 CFR pt. 241.

The Permittee is also allowed to burn alternative fuels during test burns providing the alternative fuels are traditional fuels or nonhazardous secondary materials that are not solid wastes according to the requirements of 40 CFR pt. 241, and the test burns are conducted according to the COMG9 requirements of this permit. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 82 9

Vent all EQUI82 emissions to TREA16 fabric filter for particulate matter control when EQUI82 is operating except as allowed by the Consent Decree definition of "Continuous Operation/Continuously Operate" in requirement 5.18.3. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

EQUI 82 10

Operate TREA12 (rotating opposed fired air system) and TREA15 (ROTAMIX selective non‐catalytic reduction) for EQUI82 NOx control when EQUI82 is operating. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B)]

Subject

Item ID

Sequence

Number Requirement

EQUI 82 11

The Permittee shall measure EQUI82 opacity, SO2, NOx, and CO2 emissions in accordance with 40 CFR Section 75.10. The Permittee shall measure EQUI82 SO2 and NOx emissions in accordance with Minn. R. 7017.1160, subps 1, 2, and 3. The Permi ee shall measure EQUI82 opacity in accordance with Minn. R. 7017.1200, subps 1, 2, 3, and 4.

See COMG4 for additional requirements regarding opacity monitoring, and COMG6 for additional requirements regarding SO2, NOx, CO2, and flow monitoring. [40 CFR 75.10, Minn. R. 7017.1020, Minn. R. 7017.1160, subp. 1‐3, Minn. R. 7017.1200, subp. 1‐4]

EQUI 82 12

Monitor TREA16 pressure differential for PM compliance assurance monitoring. [40 CFR 64.7, Minn. R. 7017.0200]

EQUI 82 13

Boiler Alterna ve Opera ng Condi ons for Performance Tes ng:

Alternative Operating Conditions during testing are defined as 90% to 100% of the boiler's maximum normal (continuous) operating load or the maximum permitted operating rate, whichever is lower. The basis for this number must be included in the test plan. If testing is conducted at the alternative operating condition established, an opera ng limit will not be established as a result of performance tes ng.

In no case will the new operating rate limit be higher than allowed by an existing permit condition. [Minn. R. 7017.2025, subp. 2(A), Minn. R. 7017.2025, subp. 3(B)]

EQUI 82 14

Boiler Opera ng Condi ons Not Mee ng the Alterna ve Opera ng Condi ons During Performance Tes ng:

If performance testing is not conducted at or above the established alternative operating condition, then the boiler opera ng rate will be limited on an 8‐hour block average based on the following:

(1) If the results of the performance test are greater than 80% of any applicable emission limit for which compliance is demonstrated, then boiler opera on will be limited to the tested opera ng rate.

(2) If results are less than or equal to 80% of all applicable emission limits for which compliance is demonstrated, boiler opera on will be limited to 110% of the tested opera ng rate.

In no case will the new operating rate limit be higher than allowed by an existing permit condition. [Minn. R. 7017.2025, subp. 3(B)]

EQUI 82 15

STET (Short Term Emergency and Testing) Operating hours limit:

The boiler may operate up to 40 hours per year to demonstrate the Uniform Rating of Generating Equipment (URGE) capacity and to meet emergency energy supply needs. Maintain documentation of all STET operation to demonstrate compliance with this limit. The boiler must meet emission limits during STET operation. [Minn. R. 7007.0800, subp. 2(A)&(B)]

Subject

Item ID

Sequence

Number Requirement

EQUI 82 16

STET Operation Definition that applies to Boilers that Meet or do Not Meet the Alternative Operating Condition for Performance Testing:

If performance test results demonstrate compliance at 80% or less of any applicable emission limits for any tested pollutant, STET operation is defined as operation beyond 110% of the average operating rate achieved during that performance test.

If performance test results demonstrate compliance at greater than 80% any applicable emission limit for any tested pollutant, STET operation is defined as operation beyond 100% of the average operating rate achieved during that performance test.

In no case will STET operation be higher than allowed by an existing permit condition. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 82 17

Filterable Particulate Matter The Permittee shall conduct performance test : Due after 09/16/1997 every 60 months to determine compliance with the EQUI82 Title I Condition 0.1 pounds per million Btu heat input particulate matter emission limit. All 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 5, 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. [40 CFR 64.7(a), Minn. R. 7017.2020, subp. 1, Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

EQUI 82 18

Filterable Particulate Matter : The Permittee shall conduct performance test : Due by the end of each calendar year to measure the combined EQUI82, EQUI83, and EQUI100 Filterable Particulate Matter emissions to determine compliance with the Consent Decree 0.015 pounds per million Btu heat input Filterable PM emission rate. If EQUI82, EQUI83, and/or EQUI100 are or will be Retired, Refueled, or Repowered by June 30 of the same calendar year, testing is not required for that unit. This annual performance test requirement imposed on the Permittee by Consent Decree Section VI.H may be satisfied by stack tests conducted by the Permittee as may be required by its permits from the State of Minnesota for any year that such stack tests are required under the permits.

The Permittee may perform combined EQUI82/EQUI83/EQUI100 testing every other year, rather than every year, provided that the two most recently completed test results conducted in accordance with the methods and procedures specified in the Consent Decree, demonstrate combined EQUI82/EQUI83/EQUI100 filterable PM emissions are equal to or less than 0.0075 pounds per million Btu heat input. The Permittee shall perform combined EQUI82/EQUI83/EQUI100 testing every year, rather than every other year, beginning in the year immediately following any test result demonstrating that combined EQUI82/EQUI83/EQUI100 filterable PM emissions are greater than 0.0075 pounds per million Btu heat input.Testing shall be conducted using EPA Method 5 (filterable portion only) or a PM stack testing method specified in and allowed by applicable Minnesota SIP provision(s). Following the installation and operation of Filterable PM Continuous Emissions Monitoring Systems ("CEMS") as required by Section VI.I of the Consent Decree, the Permittee may seek EPA approval pursuant to Section XIII (Review and Approval of Submittals) of the Consent Decree to forego filterable PM stack testing and instead demonstrate compliance with an applicable filterable PM Emission Rate using CEMS on a 3‐Hour Rolling Average Emission Rate basis.NOTE: The Permittee submitted a written notification dated December 19, 2016 to the USEPA and MPCA indicating EQUI82 and EQUI83 will be retired no later than December 31, 2018. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

Subject

Item ID

Sequence

Number Requirement

EQUI 82 19

Condensable Particulate Matter : The Permittee shall conduct a performance test : Due by the end of each calendar year to measure the combined EQUI82, EQUI83, and EQUI100 Condensable Particulate Matter emissions using the reference methods and procedures set forth at 40 C.F.R. Part 51, Appendix M, Method 202. If EQUI82, EQUI83, and/or EQUI100 are or will be Retired, Refueled, or Repowered by June 30 of the same calendar year, testing is not required for that unit. Each test shall consist of three separate runs performed under representative operating conditions not including periods of startup, shutdown, or Malfunction. The sampling time for each run shall be at least 60 minutes and the volume of each run shall be at least 0.85 dry standard cubic meters (30 dry standard cubic feet). The Permittee shall calculate the number of pounds of condensable PM emitted per million Btu of heat input (pound per million Btu) from the stack test results in accordance with 40 C.F.R. Section 60.8(f). The results of the PM stack test (conducted pursuant to Paragraph 129 of the Consent Decree) shall not be used for the purpose of determining compliance with the PM Emission Rates required by the Consent Decree. The results of each PM stack test shall be submitted to EPA and MPCA within 60 Days following completion of such test.

The Permittee may perform combined EQUI82/EQUI83/EQUI100 condensable PM testing every other year, rather than every year, when combined EQUI82/EQUI83/EQUI100 filterable PM emissions qualify for every other year testing. The Permittee shall resume combined EQUI82/EQUI83/EQUI100 condensable PM testing every year, rather than every other year, when combined EQUI82/EQUI83/EQUI100 filterable PM testing must be conducted every year. NOTE: The Permittee submitted a written notification dated December 19, 2016 to the USEPA and MPCA indicating EQUI82 and EQUI83 will be retired no later than December 31, 2018. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI 82 20

Hydrogen Chloride : The Permittee shall conduct a performance test : Due quarterly to determine compliance for EQUI82 Hydrogen Chloride emissions, unless the Permittee installs, operates, and maintains a Hydrogen Chloride CEMS to measure EQUI82 Hydrogen Chloride emissions. The Permittee shall use EPA Reference Method 26 or Method 26A at appendix A‐8 to part 60, Method 320 at appendix A to part 63, or ASTM 6348‐03 as specified at and according to all applicable requirements of Table 5 in part 63, subp. UUUUU.

This quarterly testing requirement also does not apply if EQUI82 is a qualifying low emitting EGU (LEE) for Hydrogen Chloride, in which case the Permittee must conduct a performance test at least once every 36 calendar months to demonstrate continued Hydrogen Chloride LEE status. [40 CFR 63.10000(c)(1)(v), 40 CFR 63.10007(b), 40 CFR pt. 63, subp. UUUUU (Table 5), Minn. R. 7011.0563]

EQUI 82 21

EQUI82 Retirement: The Permittee shall retire EQUI82 no later than December 31, 2018. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 82 22

The Permittee shall submit a notification : Due 15 calendar days after Ceasing Operation (retirement) of EQUI82. The notification shall specify the EQUI82 retirement date. [Minn. R. 7007.0800, subp. 2(A)]

EQUI 83 1

Particulate Matter <= 0.1 pounds per million Btu heat input 24‐hour block average. [Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

EQUI 83 2

Particulate Matter <= 0.6 pounds per million Btu heat input. Refer to COMG1 for applicable sulfur dioxide limits, and COMG7 for additional applicable emission limits. [Minn. R. 7011.0510, subp. 1]

Subject

Item ID

Sequence

Number Requirement

EQUI 83 3

The Permittee shall Continuously Operate TREA16 and TREA14 at EQUI82 and EQUI83, respectively, such that the units achieve and maintain a combined emission rate of Filterable Particulate Matter <= 0.015 pounds per million Btu heat input 3‐hour average; provided that if the Permittee chooses to Reroute flue gas from EQUI82 and EQUI83, then EQUI82, EQUI83, and EQUI100 shall achieve and maintain a combined Filterable Particulate Matter Emission Rate of no greater than 0.015 pounds per million Btu heat input based on a 3‐hour average.

The Permittee shall conduct stack tests each year on each unit or units served by a common stack in the Minnesota Power System to determine compliance with the PM Emission Rates established by the Consent Decree, unless the Permittee seeks and obtains EPA approval to forego filterable PM stack testing and instead demonstrate compliance with an applicable filterable PM Emission Rate using CEMS on a 3‐Hour Rolling Average Emission Rate basis. This requirement is repeated at 6.25.2. [CAAA of 1990, Minn. R. 7007.0100, subp 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI 83 4

Opacity <= 20 percent opacity 6‐minute average except for one 6‐minute period per hour of not more than 60 percent opacity. [Minn. R. 7011.0510, subp. 2]

EQUI 83 5

The Permittee shall optimize combustion and Continuously Operate the Unit 2/EQUI83 ROFA (TREA13) and SNCR (TREA11) control devices such that EQUI83 achieves and maintains Nitrogen Oxides <= 0.200 pounds per million Btu heat input 30‐day rolling average.

If the Permittee chooses to Reroute EQUI82 and EQUI83 through an FGD device that treats the flue gas from such Units and EQUI100/Boswell Unit 3, the Permittee shall continue to Continuously Operate the ROFA and SNCR control devices at such Units and maintain a 30‐Day Rolling Average Emission Rate for NOx no greater than 0.200 pounds per million Btu heat input at each Unit as measured before flue gases from EQUI82 and EQUI83 combine with the flue gases from EQUI100/Boswell Unit 3.

If the Permittee chooses to Reroute the flue gas from EQUI82 and EQUI83 and demonstrates to the reasonable satisfaction of EPA and the MPCA that it is practically infeasible to obtain a representative measurement of NOx emissions for EQUI82 and/or EQUI83 consistent with 40 C.F.R. Part 60, Appendix A, Method 1 and 40 C.F.R. Part 75, Appendix A before the flue gases from EQUI82 and EQUI83 combine with the flue gases from EQUI100, then the Permittee shall continue to Continuously Operate the ROFA and SNCR control devices at such Units, and shall demonstrate that it is in compliance with the 30‐day Rolling Average Emission Rate for NOx for EQUI82 and EQUI83 by showing that the combined 30‐Day Rolling Average Emission Rate for NOx for EQUI82, EQUI83, and EQUI100 is no greater than the Heat‐Input Weighted Average Emission Rate. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI 83 6



Subject

Item ID

Sequence

Number Requirement

EQUI 83 7






EQUI 83 8

Vent all EQUI83 emissions to TREA14 fabric filter for particulate matter control when EQUI83 is operating except as allowed by the Consent Decree definition of "Continuous Operation/Continuously Operate" in requirement 5.19.3. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

EQUI 83 9

Operate TREA13 (rotating opposed fired air system) and TREA11 (ROTAMIX selective non‐catalytic reduction) when EQUI83 is operating for EQUI83 NOx control. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 83 10

The Permittee shall measure EQUI83 opacity, SO2, NOx, and CO2 emissions in accordance with 40 CFR Section 75.10.

The Permittee shall measure EQUI83 SO2 and NOx emissions in accordance with Minn. R. 7017.1160, subps 1, 2, and 3.

The Permi ee shall measure EQUI83 opacity in accordance with Minn. R. 7017.1200, subps 1, 2, 3, and 4.


EQUI 83 11

Monitor TREA14 pressure differential for PM compliance assurance monitoring. [40 CFR 64.7, Minn. R. 7017.0200]

EQUI 83 12




Subject

Item ID

Sequence

Number Requirement

EQUI 83 13






EQUI 83 14



EQUI 83 15





EQUI 83 16

Filterable Particulate Matter : The Permittee shall conduct performance test : Due after 09/16/1997 every 60 months to determine compliance with the EQUI83 Title I Condition 0.1 pounds per million Btu heat input particulate matter emission limit. All 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 5, 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. [40 CFR 64.7(a), Minn. R. 7017.2020, subp. 1, Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

Subject

Item ID

Sequence

Number Requirement

EQUI 83 17

Filterable Particulate Matter : The Permittee shall conduct performance test : Due by the end of each calendar year to measure the combined EQUI82, EQUI83, and EQUI100 Filterable Particulate Matter emissions to determine compliance with the Consent Decree 0.015 pounds per million Btu heat input Filterable PM emission rate. If EQUI82, EQUI83, and/or EQUI100 are or will be Retired, Refueled, or Repowered by June 30 of the same calendar year, testing is not required for that unit. This annual performance test requirement imposed on the Permittee by Consent Decree Section VI.H may be satisfied by stack tests conducted by the Permittee as may be required by its permits from the State of Minnesota for any year that such stack tests are required under the permits.

The Permittee may perform combined EQUI82/EQUI83/EQUI100 testing every other year, rather than every year, provided that the two most recently completed test results conducted in accordance with the methods and procedures specified in the Consent Decree, demonstrate combined EQUI82/EQUI83/EQUI100 filterable PM emissions are equal to or less than 0.0075 pounds per million Btu heat input. The Permittee shall perform combined EQUI82/EQUI83/EQUI100 testing every year, rather than every other year, beginning in the year immediately following any test result demonstrating that combined EQUI82/EQUI83/EQUI100 filterable PM emissions are greater than 0.0075 pounds per million Btu heat input.Testing shall be conducted using EPA Method 5 (filterable portion only) or a PM stack testing method specified in and allowed by applicable Minnesota SIP provision(s). Following the installation and operation of Filterable PM Continuous Emissions Monitoring Systems ("CEMS") as required by Section VI.I of the Consent Decree, the Permittee may seek EPA approval pursuant to Section XIII (Review and Approval of Submittals) of the Consent Decree to forego filterable PM stack testing and instead demonstrate compliance with an applicable filterable PM Emission Rate using CEMS on a 3‐Hour Rolling Average Emission Rate basis.NOTE: The Permittee submitted a written notification dated December 19, 2016 to the USEPA and MPCA indicating EQUI82 and EQUI83 will be retired no later than December 31, 2018. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI 83 18

Condensable Particulate Matter : The Permittee shall conduct a performance test : Due by the end of each calendar year to measure the combined EQUI82, EQUI83, and EQUI100 Condensable Particulate Matter emissions using the reference methods and procedures set forth at 40 C.F.R. Part 51, Appendix M, Method 202. If EQUI82, EQUI83, and/or EQUI100 are or will be Retired, Refueled, or Repowered by June 30 of the same calendar year, testing is not required for that unit. Each test shall consist of three separate runs performed under representative operating conditions not including periods of startup, shutdown, or Malfunction. The sampling time for each run shall be at least 60 minutes and the volume of each run shall be at least 0.85 dry standard cubic meters (30 dry standard cubic feet). The Permittee shall calculate the number of pounds of condensable PM emitted per million Btu of heat input (pound per million Btu) from the stack test results in accordance with 40 C.F.R. Section 60.8(f). The results of the PM stack test (conducted pursuant to Paragraph 129 of the Consent Decree) shall not be used for the purpose of determining compliance with the PM Emission Rates required by the Consent Decree. The results of each PM stack test shall be submitted to EPA and MPCA within 60 Days following completion of such test.

The Permittee may perform combined EQUI82/EQUI83/EQUI100 condensable PM testing every other year, rather than every year, when combined EQUI82/EQUI83/EQUI100 filterable PM emissions qualify for every other year testing. The Permittee shall resume combined EQUI82/EQUI83/EQUI100 condensable PM testing every year, rather than every other year, when combined EQUI82/EQUI83/EQUI100 filterable PM testing must be conducted every year.

NOTE: The Permittee submitted a written notification dated December 19, 2016 to the USEPA and MPCA indicating EQUI82 and EQUI83 will be retired no later than December 31, 2018. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

Subject

Item ID

Sequence

Number Requirement

EQUI 83 19

Hydrogen Chloride : The Permittee shall conduct a performance test : Due quarterly to determine compliance for EQUI83 Hydrogen Chloride emissions, unless the Permittee installs, operates, and maintains a Hydrogen Chloride CEMS to measure EQUI83 Hydrogen Chloride emissions. The Permittee shall use EPA Reference Method 26 or Method 26A at appendix A‐8 to part 60, Method 320 at appendix A to part 63, or ASTM 6348‐03 as specified at and according to all applicable requirements of Table 5 in part 63, subp. UUUUU.


EQUI 83 20

EQUI83 Retirement: The Permittee shall retire EQUI83 no later than December 31, 2018. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 83 21

The Permittee shall submit a notification : Due 15 calendar days after Ceasing Operation (retirement) of EQUI83. The notification shall specify the EQUI83 retirement date. [Minn. R. 7007.0800, subp. 2(A)]

EQUI 85 1

EQUI85 is a Targeted Unit as defined at Minn. Stat. Section 216B.68, subd. 8 located at the Boswell Energy Center facility which is a Qualifying Facility as defined at Minn. Stat. Sec on 216B.68, subd. 6.

Minn. Stat. 216B.68 – Minn. Stat. 216B.688 is a state‐only requirement not enforceable by the administrator. [Minn. Stat. 216B.68]

EQUI 85 2

EQUI85 Filterable Particulate Matter <= 0.10 pounds per million Btu heat input. Refer to COMG1 for applicable sulfur dioxide limits, and COMG7 for additional applicable emission limits. [40 CFR 60.42(a)(1), Minn. R. 7011.0555, 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]

EQUI 85 3

The Permittee shall Continuously Operate TREA21 at EQUI85 such that EQUI85 achieves and maintains Filterable Par culate Ma er <= 0.015 pounds per million Btu heat input 3‐hour average. The Permittee shall conduct stack tests each year on each unit or units served by a common stack in the Minnesota Power System to determine compliance with the PM Emission Rates established by the Consent Decree, unless the Permittee seeks and obtains EPA approval to forego filterable PM stack testing and instead demonstrate compliance with an applicable filterable PM Emission Rate using CEMS on a 3‐Hour Rolling Average Emission Rate basis. This requirement is repeated at 6.26.2. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI 85 4

EQUI85 Filterable Particulate Matter <= 0.012 pounds per million Btu heat input. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 85 5 EQUI85 PM < 10 micron <= 0.020 pounds per million Btu heat input. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 85 6 EQUI85 PM < 2.5 micron <= 0.020 pounds per million Btu heat input. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 85 7

EQUI85 Opacity <= 20 percent opacity 6‐minute average except for one 6‐minute average per hour not to exceed 27%. [40 CFR 60.42(a)(2), Minn. R. 7011.0555]

EQUI 85 8



Subject

Item ID

Sequence

Number Requirement

EQUI 85 9

EQUI85 Nitrogen Oxides <= 0.70 pounds per million Btu heat input 3‐hour average for solid fossil fuels and <= 0.20 pounds per million Btu heat input 3‐hour average for gaseous fossil fuels. When fossil fuels are burned simultaneously in any combination, the applicable standard shall be determined by proration using the following formula: PS = [0.20x + 0.70z]/(x+z) where PS is the prorated NOx standard, x is the % heat input from gaseous fossil fuel and z is the % heat input from solid fossil fuel. [40 CFR 60.44(a)(1)&(3), 40 CFR 60.44(b), Minn. R. 7011.0555]

EQUI 85 10

The Permittee shall Continuously Operate the Low NOx Burners and OFA system (TREA6) and SNCR control device (TREA7) at EQUI85/Boswell Unit 4 such that EQUI85 achieves and maintains a Emission Rate for Nitrogen Oxides <= 0.120 pounds per million Btu heat input 30‐day rolling average. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI 85 12

The Permittee shall employee good combustion practices to limit EQUI85 Carbon Monoxide <= 0.15 pounds per million Btu heat input 30‐day rolling average including all periods of startup, shutdown, and malfunction. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

EQUI 85 14

EQUI85 Mercury <= 26.0 pounds per year 12‐month rolling sum.

The 12‐month rolling sum mercury emission rate is determined as follows:

1. By the end of each calendar day, calculate and record the total calendar day mercury emissions in units of mass (grams or pounds) per day for the previous day by summing the mass per hour emissions measured by EQUI110 for every hour in the previous calendar day during which any fuel was combusted by EQUI85;2. By the last day of each month, calculate and record the calendar month total mercury emissions in units of pounds per month for the previous month, by summing the calendar day total mercury emissions for the previous calendar month (if daily emission rates are recorded in grams per day, convert grams per day to pounds per day by dividing the grams per day value by 453.59);3. By the last day of each month, calculate and record the 12‐month rolling sum mercury emissions in pounds for the previous 12‐month period by summing the total monthly mercury emissions for the previous 12 calendar months.

Minn. Stat. 216B.68 – Minn. Stat. 216B.688 is a state‐only requirement not enforceable by the administrator. [Minn. R. 7007.0800, subp. 4&5, Minn. Stat. 216B.687, subd. 1&2]

EQUI 85 16

EQUI85 Fluorides <= 0.0084 pounds per million Btu heat input. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

EQUI 85 17






Subject

Item ID

Sequence

Number Requirement

EQUI 85 19

Operate TREA6 (low NOx burners and separated overfire air) and TREA7 (ROTAMIX selective non‐catalytic reduction) for EQUI85 NOx emissions control at all times that EQUI85 is operating. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 85 20

Vent EQUI85 emissions to TREA21 (semi‐dry flue gas desulfurization and fabric filter) for EQUI85 SO2 and PM emissions control at all times that EQUI85 is operating. [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]

EQUI 85 21

Vent EQUI85 emissions to TREA21 for EQUI85 fluorides emissions control at all times that EQUI85 is operating. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

EQUI 85 22

Vent EQUI85 emissions to TREA21 for EQUI85 HCl emissions control at all times that EQUI85 is operating. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 85 23

Operate TREA22 (activated carbon injection) and vent EQUI85 emissions to TREA22 for EQUI85 mercury emissions control at all mes except when EQUI85 combusts only natural gas.

Vent all EQUI85 emissions to TREA21 (semi‐dry flue gas desulfurization and fabric filter) for control of EQUI85 PM10 and PM2.5 emissions. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 85 24

The Permittee shall conduct coal sampling and analysis according to its May 31, 2016 plan submitted to the agency or a subsequent plan approved by the agency. The Permittee may request, in writing, cessation of coal mercury sampling and analysis after completion and submittal to the agency of the EQUI85 Mercury Reduction Analysis. (Refer to requirement 6.26.1 in this permit for the EQUI85 Mercury Reduction Analysis submittal requirement). [Minn. R. 7007.0800, subp. 2(B)]

EQUI 85 25

Mercury Control Op miza on Plan Submi al: Due 180 days before permit expira on.

As part of the agency's revision of this permit under Minn. Stat. 216B.687, subd. 3, the Permittee shall submit a plan for EQUI85 mercury control optimization for commissioner review and approval. The plan shall propose a revision of the 26.0 pound per year 12‐month rolling sum mercury limit if control equipment optimization reduces mercury emissions, or if mercury emissions monitoring accuracy improvements are made). The plan must outline the approach and options the Permittee will take to optimize EQUI85 mercury control, and shall be submitted with the application for operating permit reissuance. (This requirement has also been added to the Total Facility permit reissuance applica on requirement). Minn. Stat. 216B.68 – Minn. Stat. 216B.688 is a state‐only requirement not enforceable by the administrator. [Minn. R. 7007.0800, subp. 2(B), Minn. Stat. 216B.687, subd. 3]

EQUI 85 26

The Permittee shall conduct an EQUI85 Mercury Reduction Analysis for all EQUI85 operating conditions. The analysis must pair coal mercury sampling data with hourly EQUI110 mercury CEMS data for the same time period to determine the percent mercury reduction. Coal sampling should attempt to capture worst case coal mercury content, as well as effects of additional optimization of air pollution controls. Also, if the Permittee installs a feedback loop between EQUI110 and the TREA22 EQUI85 carbon injection system, the sampling data used in the reduction analysis should include the time period when the feedback loop is installed and operating. [Minn. R. 7007.0800, subp. 2(B)]

EQUI 85 29

The Permittee shall submit report : Due by 180 days after permit issuance. This report is the EQUI85 Mercury Reduction Analysis. [Minn. R. 7007.0800, subp. 2(B)]

Subject

Item ID

Sequence

Number Requirement

EQUI 85 31

The Permittee shall measure EQUI85 opacity, SO2, NOx, and CO2 emissions in accordance with 40 CFR Section 75.10.

The Permittee shall measure EQUI85 SO2 and NOx emissions in accordance with Minn. R. 7017.1160, subps 1, 2, and 3, and 40 CFR 60.45.

The Permittee shall measure EQUI85 opacity in accordance with Minn. R. 7017.1200, subps 1, 2, 3, and 4, and 40 CFR 60.45.

See COMG4 for additional requirements regarding opacity monitoring, and COMG6 for additional requirements regarding SO2, NOx, CO2, and flow monitoring. [40 CFR 60.45, 40 CFR 75.10, Minn. R. 7017.1020, Minn. R. 7017.1160, subp. 1‐3, Minn. R. 7017.1200, subp. 1‐4]

EQUI 85 32

Monitor TREA21 pressure differential for PM, PM10, and PM2.5 compliance assurance monitoring. [40 CFR 64.7, Minn. R. 7017.0200]

EQUI 85 33

Operate and maintain EQUI53 (the EQUI85 SO2 CEMS) to meet the requirements of CAM for EQUI85 SO2 emissions.

Operate and maintain EQUI54 (the EQUI85 NOx CEMS) to meet the requirements of CAM for EQUI85 NOx emissions. [40 CFR 64.3(d), 40 CFR 64.7, Minn. R. 7017.0200]

EQUI 85 36

EQUI85 Mercury Emissions Monitoring: Use EQUI110 (EQUI85 Hg CEMS) to measure EQUI85 Hg emissions. Addi onal Hg monitoring requirements are located under subject item EQUI110.

Minn. Stat. 216B.68 – Minn. Stat. 216B.688 is a state‐only requirement not enforceable by the administrator. [Minn. R. 7017.1006, Minn. Stat. 216B.681]

EQUI 85 37

EQUI85 Carbon Monoxide Emissions Monitoring: Operate and maintain EQUI52 (EQUI85 CO CEMS) according to 40 CFR pt. 60, Appendix B, Performance Standard 4 to measure all EQUI85 CO emissions. The CEMS Data Acquisition System shall determine CO emission rates in units of pounds per million Btu heat input on a 30‐day rolling average. Refer to subject items EQUI52 and COMG8 for additional requirements regarding CO monitoring. [40 CFR pt. 60, Appendix B, Minn. R. 7017.1006, Minn. R. 7017.1160, subp. 3, 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]

EQUI 85 38

Filterable Particulate Matter : The Permittee shall conduct performance test : Due after 08/11/2016 every 60 months to determine compliance with the EQUI85 0.012 and 0.10 pounds per million Btu heat input filterable particulate matter emission limits. The next test is due 08/11/2021 and subsequent tests shall be conducted every 60 months thereafter. The performance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 5, 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, Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

Subject

Item ID

Sequence

Number Requirement

EQUI 85 39

Filterable Particulate Matter : The Permittee shall conduct performance test : Due by the end of each calendar year to measure the EQUI85 Filterable Particulate Matter emissions to determine compliance with the Consent Decree 0.015 pounds per million Btu heat input Filterable PM emission rate. If EQUI85 is or will be Retired, Refueled, or Repowered by June 30 of the same calendar year, testing is not required for that unit. This annual performance test requirement imposed on the Permittee by Consent Decree Section VI.H may be satisfied by stack tests conducted by the Permittee as may be required by its permits from the State of Minnesota for any year that such stack tests are required under the permits.

The Permittee may perform EQUI85 testing every other year, rather than every year, provided that the two most recently completed test results conducted in accordance with the methods and procedures specified in the Consent Decree, demonstrate EQUI85 filterable PM emissions are equal to or less than 0.0075 pounds per million Btu heat input. The Permittee shall perform EQUI85 testing every year, rather than every other year, beginning in the year immediately following any test result demonstrating that EQUI85 filterable PM emissions are greater than 0.0075 pounds per million Btu heat input.

Testing shall be conducted using EPA Method 5 (filterable portion only) or a PM stack testing method specified in and allowed by applicable Minnesota SIP provision(s). Following the installation and operation of Filterable PM Continuous Emissions Monitoring Systems ("CEMS") as required by Section VI.I of the Consent Decree, the Permittee may seek EPA approval pursuant to Section XIII (Review and Approval of Submittals) of the Consent Decree to forego filterable PM stack testing and instead demonstrate compliance with an applicable filterable PM Emission Rate using CEMS on a 3‐Hour Rolling Average Emission Rate basis. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI 85 40

Condensable Particulate Matter : The Permittee shall conduct a performance test : Due by the end of each calendar year to measure the EQUI85 Condensable Particulate Matter emissions using the reference methods and procedures set forth at 40 C.F.R. Part 51, Appendix M, Method 202. If EQUI85 is or will be Retired, Refueled, or Repowered by June 30 of the same calendar year, testing is not required for that unit. Each test shall consist of three separate runs performed under representative operating conditions not including periods of startup, shutdown, or Malfunction. The sampling time for each run shall be at least 60 minutes and the volume of each run shall be at least 0.85 dry standard cubic meters (30 dry standard cubic feet). The Permittee shall calculate the number of pounds of condensable PM emitted per million Btu of heat input (pound per million Btu) from the stack test results in accordance with 40 C.F.R. Section 60.8(f). The results of the PM stack test (conducted pursuant to Paragraph 129 of the Consent Decree) shall not be used for the purpose of determining compliance with the PM Emission Rates required by the Consent Decree. The results of each PM stack test shall be submitted to EPA and MPCA within 60 Days following completion of such test.

The Permittee may perform EQUI85 condensable PM testing every other year, rather than every year, when EQUI85 filterable PM emissions qualify for every other year testing (refer to Appendix K). The Permittee shall resume EQUI85 condensable PM testing every year, rather than every other year, when EQUI85 filterable PM testing must be conducted every year. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

Subject

Item ID

Sequence

Number Requirement

EQUI 85 41

PM < 10 micron : The Permittee shall conduct performance test : Due after 10/04/2016 every 60 months to determine compliance with the EQUI85 0.020 pounds per million Btu heat input PM < 10 micron emission limit. The next test is due 10/04/2021 and subsequent tests shall be conducted every 60 months thereafter. The performance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Methods 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]

EQUI 85 42

PM < 2.5 micron : The Permittee shall conduct performance test : Due after 10/04/2016 every 60 months to determine compliance with the EQUI85 0.020 pounds per million Btu heat input PM < 2.5 micron emission limit. The next test is due 10/04/2021 and subsequent tests shall be conducted every 60 months thereafter. The performance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Methods 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]

EQUI 85 43

Fluorides : The Permittee shall conduct performance test : Due after 10/04/2016 every 60 months. The next test is due 10/04/2021 and subsequent tests shall be conducted every 60 months thereafter. The performance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 13A, 13B, 26A, 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. [40 CFR 64.3, Minn. R. 7017.2020, subp. 1, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

EQUI 85 44




Subject

Item ID

Sequence

Number Requirement

EQUI 85 45






EQUI 85 46



EQUI 85 47





EQUI 86 1


EQUI 86 2


EQUI 86 3


EQUI 86 4

PM < 2.5 micron <= 0.005 grains per dry standard cubic foot. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]


EQUI 86 6


EQUI 87 1


EQUI 87 2


Subject

Item ID

Sequence

Number Requirement

EQUI 87 3


EQUI 87 4



EQUI 87 6


EQUI 88 1


EQUI 88 2


EQUI 88 3


EQUI 88 4



EQUI 88 6


EQUI 89 1


EQUI 89 2


EQUI 89 3


EQUI 89 4



EQUI 89 6


EQUI 90 1


EQUI 90 2


EQUI 90 3


EQUI 90 4



EQUI 90 6


EQUI 91 1


EQUI 91 2


EQUI 91 3


Subject

Item ID

Sequence

Number Requirement

EQUI 91 4



EQUI 91 6


EQUI 93 1


EQUI 93 2


EQUI 93 3


EQUI 93 4



EQUI 93 6


EQUI 94 1


EQUI 94 2


EQUI 94 3


EQUI 94 4



EQUI 94 6

EQUI94 (EU032) Truck Bay doors shall be closed at all times when ash is loaded out of the silo. Failure to close the EQUI94 truck bay doors during ash loadout is a deviation that must be reported in the semiannual deviations report. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

EQUI 94 7


EQUI 97 1


EQUI 97 2


EQUI 97 3


EQUI 97 4



EQUI 97 6

Vent all captured EQUI97 (EU018) emissions to fabric filter TREA2 (CE044). TREA2 shall meet the applicable requirements in COMG3. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

EQUI 98 1


Subject

Item ID

Sequence

Number Requirement

EQUI 98 2


EQUI 98 3



EQUI 98 6


EQUI 99 1


EQUI 99 2


EQUI 99 3



EQUI 99 5


EQUI 100 1

EQUI100 is a Targeted Unit as defined at Minn. Stat. Section 216B.68, subd. 8 located at the Boswell Energy Center facility which is a Qualifying Facility as defined at Minn. Stat. Sec on 216B.68, subd. 6.

Minn. Stat. 216B.68 – Minn. Stat. 216B.688 is a state‐only requirement not enforceable by the administrator. [Minn. Stat. 216B.68]

EQUI 100 2

EQUI100 Particulate Matter <= 0.60 pounds per million Btu heat input. Refer to COMG1 for applicable sulfur dioxide limits, and COMG7 for additional applicable emission limits. [Minn. R. 7011.0510, subp. 1]

EQUI 100 3

EQUI100 Filterable Particulate Matter <= 0.014 pounds per million Btu heat input. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 100 4

The Permittee shall Continuously Operate TREA9 at EQUI100 such that EQUI100 achieves and maintains an emission rate for Filterable Particulate Matter <= 0.015 pounds per million Btu heat input 3‐hour average; provided that if the Permittee chooses to Reroute the flue gas from EQUI82 and EQUI83, then EQUI82, EQUI83, and EQUI100 shall achieve and maintain a combined Filterable Particulate Matter Emission Rate <= 0.015 pounds per million Btu heat input based on a 3‐hour average. The Permittee shall conduct stack tests each year on each unit or units served by a common stack in the Minnesota Power System to determine compliance with the PM Emission Rates established by the Consent Decree, unless the Permittee seeks and obtains EPA approval to forego filterable PM stack testing and instead demonstrate compliance with an applicable filterable PM Emission Rate using CEMS on a 3‐Hour Rolling Average Emission Rate basis. This requirement is repeated at 6.27.2. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI 100 5

EQUI100 PM < 10 micron <= 0.035 pounds per million Btu heat input filterable plus organic and inorganic condensables. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 100 6

EQUI100 Opacity <= 20 percent opacity 6‐minute average except for one six‐minute period per hour of not more than 60 percent opacity. [Minn. R. 7011.0510, subp. 2]

EQUI 100 7



Subject

Item ID

Sequence

Number Requirement

EQUI 100 8

The Permittee shall Continuously Operate the Low NOx Burners and OFA system (TREA8) and SCR control device (TREA5) at EQUI100/Boswell Unit 3 such that EQUI100 achieves and maintains an Emission Rate for Nitrogen Oxides <= 0.060 pounds per million Btu heat input 30‐day rolling average.

An SCR control device is still required if Minnesota Power elects to Refuel or Repower EQUI100 and replaces the boiler. If Minnesota Power chooses to Reroute the flue gas from EQUI82 and EQUI83, the Permittee shall continue to Continuously Operate the Low NOx Burners and OFA system (TREA8) and SCR control device (TREA5) at EQUI100 such that the Unit achieves and maintains a 30‐Day Rolling Average Emission Rate for NOx no greater than 0.060 pounds per million Btu heat input as measured before flue gases from EQUI82 and EQUI83 combine with the flue gases from EQUI100. [CAAA of 1990, Minn. R. 7007.0100, subp. 7, Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI 100 10

EQUI100 Fluorides <= 0.0018 pounds per million Btu heat input. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

EQUI 100 11

The Permittee shall employee good combustion practices to limit EQUI100 Carbon Monoxide <= 0.15 pounds per million Btu heat input on a 24‐hour rolling average. This limit applies at all times including periods of startup, shutdown, and malfunction. [Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

EQUI 100 12

EQUI100 Lead <= 0.00004 pounds per million Btu heat input. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

EQUI 100 13

EQUI100 Mercury <= 10.0 pounds per year 12‐month rolling sum.

The 12‐month rolling sum mercury emission rate is determined as follows:

1. By the end of each calendar day, calculate and record the total calendar day mercury emissions in units of mass (grams or pounds) per day for the previous day by summing the mass per hour emissions measured by EQUI109 for every hour in the previous calendar day during which any fuel was combusted by EQUI100;2. By the last day of each month, calculate and record the calendar month total mercury emissions in units of pounds per month for the previous month, by summing the calendar day total mercury emissions for the previous calendar month (if daily emission rates are recorded in grams per day, convert grams per day to pounds per day by dividing the grams per day value by 453.59);3. By the last day of each month, calculate and record the 12‐month rolling sum mercury emissions in pounds for the previous 12‐month period by summing the total monthly mercury emissions for the previous 12 calendar months.

Minn. Stat. 216B.68 – Minn. Stat. 216B.688 is a state‐only requirement not enforceable by the administrator. [Minn. R. 7007.0800, subp. 4&5, Minn. Stat. 216B.687, subd. 1&2]

Subject

Item ID

Sequence

Number Requirement

EQUI100 13.1

Operate and maintain EQUI44 (the EQUI100 SO2 CEMS) to meet the requirements of CAM for EQUI100 SO2 emissions.

Operate and maintain EQUI45 (the EQUI100 NOx CEMS) to meet the requirements of CAM for EQUI100 NOx emissions. [40

CFR 64.3(d), 40 CFR 64.7, Minn. R. 7017.0200]

Subject

Item ID

Sequence

Number Requirement

EQUI 100 14






EQUI 100 15

Operate TREA8 (low NOx burners and overfire air system) and vent all EQUI100 emissions to TREA5 (selective catalytic reduction system), TREA9 (fabric filter), TREA10 (wet flue gas desulfurization system), and TREA28 (carbon injection system) when EQUI100 is operating. The Permittee is not required to operate TREA28 when EQUI100 combusts only natural gas. [Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 100 16

Vent EQUI100 emissions to TREA10 for EQUI100 fluorides emissions control at all times that EQUI100 is operating. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

EQUI 100 17

Vent EQUI100 emissions to TREA10 (wet flue gas desulfurization) for EQUI100 SO2 and hydrogen chloride emissions control at all times that EQUI100 is operating. [Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.0800, subp.16(J)]

EQUI 100 19

The Permittee shall measure EQUI100 opacity, SO2, NOx, and CO2 emissions in accordance with 40 CFR Section 75.10. The Permittee shall measure EQUI100 SO2 and NOx emissions in accordance with Minn. R. 7017.1160, subps 1, 2, and 3. The Permi ee shall measure EQUI100 opacity in accordance with Minn. R. 7017.1200, subps 1, 2, 3, and 4.


EQUI 100 20

Operate and maintain EQUI71 (EQUI100 CO CEMS) according to 40 CFR pt. 60, Appendix B, Performance Standard 4 to measure all EQUI100 CO emissions. The CEMS Data Acquisition System shall determine CO emission rates in units of pounds per million Btu heat input on a 30‐day rolling average. Refer to subject items EQUI71 and COMG8 for additional requirements regarding CO monitoring. [Minn. R. 7007.0800, subp. 4(B), Title I Condition: 40 CFR 52.21(j)(BACT) & Minn. R. 7007.3000]

EQUI 100 21

EQUI100 Fluorides Monitoring: The Permittee shall use EQUI44 SO2 CEMS for monitoring EQUI100 fluoride emissions. Refer to TREA10 for additional fluoride monitoring requirements. [Minn. R. 7007.0800, subp. 4(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

EQUI 100 22

Monitor TREA9 pressure differential for PM and PM10 compliance assurance monitoring. [40 CFR 64.7, Minn. R. 7017.0200]

Subject

Item ID

Sequence

Number Requirement

EQUI 100 23

EQUI100 Mercury Emissions Monitoring: Use EQUI109 (EQUI100 Hg CEMS) to measure EQUI100 Hg emissions. Addi onal Hg monitoring requirements are located under subject item EQUI109.

Minn. Stat. 216B.68 – Minn. Stat. 216B.688 is a state‐only requirement not enforceable by the administrator. [Minn. R. 7017.1006, Minn. Stat. 216B.681]

EQUI 100 25

Filterable Particulate Matter : The Permittee shall conduct performance test : Due after 03/31/2010 every 60 months to determine compliance with the EQUI100 0.014 and 0.60 pound per million Btu heat input filterable particulate matter emission limits. The next test is due 03/31/2020 and tests thereafter shall be conducted every 60 months. The performance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 5, 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. [40 CFR pt. 64, Minn. R. 7017.2020, subp. 1]

EQUI 100 26

Filterable Particulate Matter : The Permittee shall conduct performance test : Due by the end of each calendar year to measure the EQUI100 Filterable Particulate Matter emissions to determine compliance with the Consent Decree 0.015 pounds per million Btu heat input Filterable PM emission rate. If EQUI100 is or will be Retired, Refueled, or Repowered by June 30 of the same calendar year, testing is not required for that unit. This annual performance test requirement imposed on the Permittee by Consent Decree Section VI.H may be satisfied by stack tests conducted by the Permittee as may be required by its permits from the State of Minnesota for any year that such stack tests are required under the permits.

The Permittee may perform EQUI100 testing every other year, rather than every year, provided that the two most recently completed test results conducted in accordance with the methods and procedures specified in the Consent Decree, demonstrate EQUI100 filterable PM emissions are equal to or less than 0.0075 pounds per million Btu heat input. The Permittee shall perform EQUI100 testing every year, rather than every other year, beginning in the year immediately following any test result demonstrating that EQUI100 filterable PM emissions are greater than 0.0075 pounds per million Btu heat input.

Testing shall be conducted using EPA Method 5 (filterable portion only) or a PM stack testing method specified in and allowed by applicable Minnesota SIP provision(s). Following the installation and operation of Filterable PM Continuous Emissions Monitoring Systems ("CEMS") as required by Section VI.I of the Consent Decree, the Permittee may seek EPA approval pursuant to Section XIII (Review and Approval of Submittals) of the Consent Decree to forego filterable PM stack testing and instead demonstrate compliance with an applicable filterable PM Emission Rate using CEMS on a 3‐Hour Rolling Average Emission Rate basis. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

Subject

Item ID

Sequence

Number Requirement

EQUI 100 27

Condensable Particulate Matter : The Permittee shall conduct a performance test : Due by the end of each calendar year to measure EQUI100 Condensable Particulate Matter emissions using the reference methods and procedures set forth at 40 C.F.R. Part 51, Appendix M, Method 202. If EQUI100 is or will be Retired, Refueled, or Repowered by June 30 of the same calendar year, testing is not required for that unit. Each test shall consist of three separate runs performed under representative operating conditions not including periods of startup, shutdown, or Malfunction. The sampling time for each run shall be at least 60 minutes and the volume of each run shall be at least 0.85 dry standard cubic meters (30 dry standard cubic feet). The Permittee shall calculate the number of pounds of condensable PM emitted per million Btu of heat input (pound per million Btu) from the stack test results in accordance with 40 C.F.R. Section 60.8(f). The results of the PM stack test (conducted pursuant to Paragraph 129 of the Consent Decree) shall not be used for the purpose of determining compliance with the PM Emission Rates required by the Consent Decree. The results of each PM stack test shall be submitted to EPA and MPCA within 60 Days following completion of such test.

The Permittee may perform EQUI100 condensable PM testing every other year, rather than every year, when EQUI100 filterable PM emissions qualify for every other year testing (refer to Appendix K). The Permittee shall resume EQUI100 condensable PM testing every year, rather than every other year, when EQUI100 filterable PM testing must be conducted every year. [CAAA of 1990, Minn. R. 7007.0100, subp. 7(A)&(B), Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI 100 28

PM < 10 micron : The Permittee shall conduct performance test : Due after 04/01/2010 every 60 months to determine compliance with the 0.035 pound per million Btu heat input PM < 10 micron emission limit. The next test is due 04/01/2020 and tests thereafter shall be conducted every 60 months. The performance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Methods 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. [40 CFR pt. 64, Minn. R. 7017.2020, subp. 1]

EQUI 100 29

Fluorides : The Permittee shall conduct performance test : Due after 03/31/2010 every 60 months. The next test is due 03/31/2020 and tests thereafter shall be conducted every 60 months. The performance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 13A, 13B, 26A, 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: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

Subject

Item ID

Sequence

Number Requirement

EQUI 100 30

Lead : The Permittee shall conduct performance test : Due after 03/30/2010 every 60 months. The next test is due 03/30/2020 and tests thereafter shall be conducted every 60 months. The performance test shall be conducted at worst case conditions as defined at Minn. R. 7017.2025, subp. 2, using EPA Reference Method 12, 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: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

EQUI 100 31

Hydrogen Chloride : The Permittee shall conduct a performance test : Due quarterly to determine compliance for EQUI100 Hydrogen Chloride emissions, unless the Permittee installs, operates, and maintains a Hydrogen Chloride CEMS to measure EQUI100 Hydrogen Chloride emissions, or elects to implement the alternate SO2 limit and determine compliance using EQUI44 (the EQUI100 SO2 CEMS). The Permittee shall use EPA Reference Method 26 or Method 26A at appendix A‐8 to part 60, Method 320 at appendix A to part 63, or ASTM 6348‐03 as specified at and according to all applicable requirements of Table 5 in part 63, subp. UUUUU.


EQUI 100 32




EQUI 100 33






Subject

Item ID

Sequence

Number Requirement

EQUI 100 34



EQUI 100 35





EQUI 102 1



EQUI 102 4

Vent all EQUI102 (EU012) emissions to fabric filter TREA38 (CE008). TREA38 shall meet the applicable requirements in COMG3. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 106 1

EQUI106 contains Mercury Sorbent Trap System requirements from 40 CFR pt. 63, subp. UUUUU and Minn. R. 7011.0561. Additional monitoring requirements may also apply to the Facility, and it is the responsibility of the Facility to meet all applicable requirements. [Minn. R. 7007.0800, subp. 4(A)]

EQUI 106 2

Mercury Emissions Monitoring Before EQUI82 and EQUI83 Shutdown: The Permittee shall use either EQUI106 or EQUI109 as the primary STRU13 mercury monitoring system according to the requirements of 40 CFR pt. 63, subp. UUUUU. The Permittee shall designate which monitor is the primary STRU13 mercury monitoring system as required by 40 CFR pt. 63, subp. UUUUU, Appendix A, section 2.2. The Permittee shall determine the primary STRU13 mercury monitoring system hourly emissions data according to the requirements of 40 CFR pt. 63, subp. UUUUU. [40 CFR pt. 63, subp. UUUUU, Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

EQUI 106 3

Mercury Emissions Monitoring After EQUI82 and EQUI83 Shutdown: The Permittee shall use either EQUI106 or EQUI109 as the primary EQUI100 mercury monitoring system according to the requirements of 40 CFR pt. 63, subp. UUUUU. The Permittee shall designate which monitor is the primary monitoring system as required by 40 CFR pt. 63, subp. UUUUU, Appendix A, section 2.2.

Use of EQUI106 as the primary EQUI100 mercury monitoring system meets the monitoring required by Minn. Stat. 216B.681 and Minn. R. 7011.0561, subp. 5. When EQUI106 is the primary EQUI100 mercury monitoring system, EQUI106 emissions data shall be determined according to the applicable requirements of subp. UUUUU and Minn. R. 7011.0561, subp. 7.

When EQUI106 is the primary monitoring system the Permittee is not required to substitute for missing data for determining EQUI100 emissions regulated by subp. UUUUU during any EQUI106 downtime, malfunction, or out of control period (as defined in subp. UUUUU and Minn. R. 7017.1002).

When EQUI106 is the primary monitoring system the Permittee shall follow the Missing Hg Concentration Data Substitution Requirements in subject item EQUI109 for determining EQUI100 mercury emissions regulated by Minn. Stat. 216B.68 ‐ Minn. Stat. 216B.688 and Minn. R. 7011.0561, during any EQUI106 downtime, malfunction, or out of control period.

Minn. Stat. 216B.68 ‐ Minn. Stat. 216B.688 and Minn. R. 7011.0561 are state‐only requirements not enforceable by the administrator. [40 CFR pt. 63, subp. UUUUU, Minn. R. 7011.0561, subp. 5‐7, Minn. R. 7011.0563, Minn. Stat. 216B.681]

EQUI 106 5

Mercury Emissions Monitoring After EQUI82 and EQUI83 Shutdown: If EQUI106 is not the designated primary EQUI100 mercury monitoring system, EQUI106 may be used as a temporary non‐redundant backup monitoring system according to the requirements of subp. UUUUU, Appendix A, if the Permittee elects to monitor EQUI100 mercury emissions according to subp. UUUUU during any EQUI109 downtime. [40 CFR pt. 63, subp. UUUUU, App. A , Minn. R. 7011.0563]

EQUI 106 6

Mercury Emissions Monitoring After EQUI82 and EQUI83 Shutdown: If EQUI106 is not the designated primary EQUI100 mercury monitoring system, EQUI106 may be used as a temporary non‐redundant backup monitoring system according to the requirements of subp. UUUUU, Appendix A, including section 2.2.2, for monitoring EQUI100 mercury emissions as required by Minn. Stat. 216B.681 and Minn. R. 7011.0561, subp. 5.

Minn. Stat. 216B.68 ‐ Minn. Stat. 216B.688 and Minn. R. 7011.0561 are state‐only requirements not enforceable by the administrator. [Minn. R. 7007.0800, subp. 4(A), Minn. R. 7011.0561, subp. 5, Minn. Stat. 216B.681]

EQUI 107 1

Emissions Monitoring: The Permittee shall use EQUI107 (filterable particulate matter continuous emissions monitoring system) for monitoring STRU13 filterable particulate matter emissions. [CAAA of 1990, Minn. R. 7007.0100, subp. 7, Minn. R. 7007.0800, subp. 1&2, Minn. R. 7017.1006, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI 107 3

The Permittee shall operate and maintain EQUI107 according to 40 CFR part 60, Appendix F, Performance Specification 2 (PS2), the site‐specific monitoring plan, and the 2014 Consent Decree (paragraph 134) required QA/QC plan. The Permittee shall conduct the following QA/QC activities for EQUI107 and all other applicable QA/QC ac vi es as described in the Site‐Specific Monitoring Plan and PS2:

1. Daily Zero and High Calibra on Dri Checks 2. Quarterly Absolute Correla on Audits 3. Rela ve Response Audits 4. Relative Correlation Audits. [40 CFR 63.10000(d)(4), 40 CFR 63.10010(i)(2), CAAA of 1990, Minn. R. 7007.0100, subp. 7, Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

Subject

Item ID

Sequence

Number Requirement

EQUI 108 1

Emissions Monitoring: The Permittee shall use EQUI108 (filterable particulate matter continuous emissions monitoring system) for monitoring EQUI85 filterable particulate matter emissions. [CAAA of 1990, Minn. R. 7007.0100, subp. 7, Minn. R. 7007.0800, subp. 1&2, Minn. R. 7017.1006, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI 108 3

The Permittee shall operate and maintain EQUI108 according to 40 CFR part 60, Appendix F, Performance Specification 2 (PS2), the site‐specific monitoring plan, and the 2014 Consent Decree (paragraph 134) required QA/QC plan. The Permittee shall conduct the following QA/QC activities for EQUI108 and all other applicable QA/QC ac vi es as described in the Site‐Specific Monitoring Plan and PS2:

1. Daily Zero and High Calibra on Dri Checks 2. Quarterly Absolute Correla on Audits 3. Rela ve Response Audits 4. Relative Correlation Audits. [40 CFR 63.10000(d)(4), 40 CFR 63.10010(i)(2), CAAA of 1990, Minn. R. 7007.0100, subp. 7, Minn. R. 7007.0800, subp. 1&2, Minn. Stat. 116.07, subd. 4a&9, Title I Condition: 40 CFR 52.21]

EQUI 109 1

EQUI109 contains Mercury Continuous Emissions Monitoring System requirements from 40 CFR pt. 63, subp. UUUUU. Additional monitoring requirements may also apply to the Facility, and it is the responsibility of the Facility to meet all applicable requirements. [Minn. R. 7007.0800, subp. 4(A)]

EQUI 109 2

Mercury Emissions Monitoring Before EQUI82 and EQUI83 Shutdown: The Permittee shall use either EQUI106 or EQUI109 as the primary EQUI100 mercury monitoring system for monitoring EQUI100 mercury emissions as required by Minn. Stat. 216B.681 and Minn. R. 7011.0561, subp. 5. The Permittee shall designate which monitor is the primary monitoring system as required by 40 CFR pt. 63, subp. UUUUU (at Appendix A, section 2.2) as referenced by Minn. R. 7011.0561, subp. 5(A)(2).

The primary EQUI100 mercury monitoring system hourly emissions data shall be determined according to the requirements of Minn. R. 7011.0561, subp. 6 or 7 as applicable. During the primary EQUI100 mercury monitoring system downtime, malfunction, or out of control periods (as defined in subp. UUUUU and Minn. R. 7017.1002), the Permittee shall follow the Missing Hg Concentration Data Substitution Requirements in this subject item for determining EQUI100 mercury emissions regulated by Minn. Stat. 216B.68 ‐ Minn. Stat. 216B.688 and Minn. R. 7011.0561.

Minn. Stat. 216B.68 ‐ Minn. Stat. 216B.688 and Minn. R. 7011.0561 are state‐only requirements not enforceable by the administrator. [Minn. R. 7011.0561, subp. 5‐7, Minn. Stat. 216B.681]

Subject

Item ID

Sequence

Number Requirement

EQUI 109 3

Mercury Emissions Monitoring After EQUI82 and EQUI83 Shutdown: The Permittee shall use either EQUI109 or EQUI106 as the primary EQUI100 mercury monitoring system according to the requirements of 40 CFR pt. 63, subp. UUUUU. The Permittee shall designate which monitor is the primary monitoring system as required by 40 CFR pt. 63, subp. UUUUU, Appendix A, section 2.2. Use of EQUI109 as the primary EQUI100 mercury monitoring system meets the monitoring required by Minn. Stat. 216B.681 and Minn. R. 7011.0561, subp. 5. When EQUI109 is the primary EQUI100 mercury monitoring system, EQUI109 hourly emissions data shall be determined according to the applicable requirements of subp. UUUUU and Minn. R. 7011.0561, subp. 6.

When EQUI109 is the primary monitoring system the Permittee is not required to substitute for missing data or use EQUI106 for determining EQUI100 mercury emissions regulated by subp. UUUUU during any EQUI109 downtime, malfunction, or out of control period (as defined in subp. UUUUU and Minn. R. 7017.1002). However, the Permittee may elect to use EQUI106 as a non‐redundant backup monitoring system for determining EQUI100 mercury emissions regulated by subp. UUUUU according to the requirements of subp. UUUUU, Appendix A.

When EQUI109 is the primary monitoring system the Permittee shall use either EQUI106 as a temporary non‐redundant backup monitoring system (as allowed at subp. UUUUU, App. A, section 2.2.2) or follow the Missing Hg Concentration Data Substitution Requirements in this subject item for determining EQUI100 mercury emissions regulated by Minn. Stat. 216B.68 ‐ Minn. Stat. 216B.688 and Minn. R. 7011.0561, during any EQUI109 downtime, malfunction, or out of control period.

Minn. Stat. 216B.68 ‐ Minn. Stat. 216B.688 and Minn. R. 7011.0561 are state‐only requirements not enforceable by the administrator. [40 CFR pt. 63, subp. UUUUU, Minn. R. 7011.0561, subp. 5‐7, Minn. R. 7011.0563, Minn. Stat. 216B.681]

EQUI 109 4

The Permittee shall conduct a daily EQUI109 calibration error test according to the requirements of subp. UUUUU, Appendix A and Minn. R. 7011.0561, subp. 6. Minn. R. 7011.0561 is a state‐only requirement not enforceable by the administrator. [40 CFR pt. 63, subp. UUUUU, App. A, Minn. R. 7011.0561, subp. 6, Minn. R. 7011.0563]

EQUI 109 5

The Permittee shall conduct a weekly EQUI109 single‐level system integrity check according to the requirements at subp. UUUUU, Appendix A and Minn. R. 7011.0561, subp. 6. Minn. R. 7011.0561 is a state‐only requirement not enforceable by the administrator. [40 CFR pt. 63, subp. UUUUU, App. A, Minn. R. 7011.0561, subp. 6, Minn. R. 7011.0563]

EQUI 109 6

The Permittee shall conduct a quarterly EQUI109 linearity check or 3‐level system integrity check according to the requirements at subp. UUUUU, Appendix A and Minn. R. 7011.0561, subp. 6. Minn. R. 7011.0561 is a state‐only requirement not enforceable by the administrator. [40 CFR pt. 63, subp. UUUUU, App. A, Minn. R. 7011.0561, subp. 6, Minn. R. 7011.0563]

EQUI 109 7

The Permittee shall conduct CEMS relative accuracy test audit (RATA) : Due annually for EQUI109 according to the requirements at subp. UUUUU, Appendix A and Minn. R. 7011.0561, subp. 6.

'Annually' means once every four QA operating quarters, and a 'QA operating quarter' is a calendar quarter with at least 168 unit or stack operating hours. Minn. R. 7011.0561 is a state‐only requirement not enforceable by the administrator. [40 CFR pt. 63, subp. UUUUU, App. A, Minn. R. 7011.0561, subp. 6, Minn. R. 7011.0563]

Subject

Item ID

Sequence

Number Requirement

EQUI 109 8

Mercury: Missing Hg Concentration Data Substitution For Mercury Emissions Monitoring Required by Minn. Stat. 216B.681 and Minn. R. 7011.0561, subp. 5.

The Permittee shall provide substitute Hg concentration data for EQUI100 according to the missing data procedures in this permit whenever EQUI100 combusts any fuel and a valid, quality‐assured hour of Hg concentration data (in microgram/scm) has not been measured and recorded for EQUI100 by EQUI109 and EQUI105. (EQUI109 is a Hg CEMS certified in accordance with Appendix A to 40 CFR pt. 63, subp. UUUUU and EQUI105 is the data acquisition and handling system). [Minn. R. 7007.0800, subp. 2(B), Minn. R. 7007.0800, subp. 4(D)]

EQUI 109 9

Mercury: Ini al Missing Hg Concentra on Data Subs tu on During Unit Opera ng Hours.

(a) Before 720 quality assured monitor operating hours of Hg concentration data have been obtained following initial certification or recertification, the Permittee shall provide substitute data for Hg concentration in accordance with the procedures outlined below.

(b) For each hour of missing Hg emissions concentration data, the Permittee shall calculate the substitute data as follows:

(1) Whenever prior quality‐assured data exist, the Permittee shall substitute, by means of the data acquisition and handling system, for each hour of missing data, the average of the hourly Hg concentrations recorded by a certified monitor for the unit operating hour immediately before and the unit operating hour immediately after the missing data period.

(2) Whenever no prior quality assured Hg concentration data exist, the Permittee shall substitute, as applicable, for each hour of missing data, the maximum potential Hg concentration (MPC), as specified below. [Minn. R. 7007.0800, subps. 4‐5]

EQUI 109 10

Mercury: Standard Missing Hg Concentra on Data Subs tu on During Unit Opera ng Hours.

(a) Once 720 quality assured monitor operating hours of Hg concentration data have been obtained following initial certification or recertification, the Permittee shall provide substitute data for Hg concentration in accordance with the procedures outlined under "Standard Missing Hg Concentration Data Substitution Procedure" below.

(b) For any hour(s) in the missing data period for which any add‐on emission control equipment (including activated carbon injection as well as flue gas desulfurization that significantly reduces Hg emissions) is malfunctioning, the Permittee shall use the Maximum Potential Hg Concentration (MPC), as defined below. [Minn. R. 7007.0800, subps. 4‐5]

EQUI 109 11

Mercury: Standard Missing Hg Concentration Data Substitution Procedure.For each hour of missing Hg concentra on data (a er 720 quality assured monitor opera ng hours of Hg concentration data have been obtained following initial certification orecertification.(1) If the monitor data availability is equal to or greater than 90.0 percent, the Permi ee shall calculate substitute data by means of the automated data acquisition and handling system for that hour of the missing data period according to the following procedures:(i) For a missing data period less than or equal to 24 hours, substitute the average of the hourly Hg concentrations recorded by an Hg pollutant concentration monitor for the hour before and the hour after the missing data period.(ii) For a missing data period greater than 24 hours, subs tute the greater of:(A) The 90th percentile hourly Hg concentration recorded by an Hg pollutant concentration monitor during the previous 720 quality‐assured monitor opera ng hours*; or(B) The average of the hourly Hg concentrations recorded by an Hg pollutant concentration monitor for the hour before and the hour a er the missing data period.[Minn. R. 7007.0800, subps. 4‐5]

Subject

Item ID

Sequence

Number Requirement

EQUI 109 11

Cont. from Above:(2) If the monitor data availability is at least 80.0 percent but less than 90.0 percent, the Permittee shall calculate substitute data by means of the automated data acquisition and handling system for that hour of the missing data period according to the following procedures:(i) For a missing data period of less than or equal to 8 hours, substitute the average of the hourly Hg concentrations recorded by an Hg pollutant concentration monitor for the hour before and the hour after the missing data period.(ii) For a missing data period of more than 8 hours, substitute the greater of:(A) the 95th percentile hourly Hg concentration recorded by an Hg pollutant concentration monitor during the previous 720 quality‐assured monitor operating hours*; or(B) The average of the hourly Hg concentrations recorded by an Hg pollutant concentration monitor for the hour before and the hour after the missing data period.(3) If the monitor data availability is at least 70.0 percent but less than 80.0 percent, the Permittee shall substitute for that hour of the missing data period the maximum hourly Hg concentration recorded by an Hg pollutant concentration monitor during the previous 720 quality‐assured monitor operating hours*.(4) If the monitor data availability is less than 70.0 percent, the Permittee shall substitute for that hour of the missing data period the maximum potential Hg concentration, as defined below.*Quality‐assured, monitor operating hours, during unit operation. May be either fuel‐specific or non‐fuel‐specific. Use data from no earlier than 3 years prior to the missing data period. [Minn. R. 7007.0800, subps. 4‐5]

EQUI 109 12

Mercury: Maximum Poten al Concentra on (MPC).

When required to substitute missing Hg concentration data using the MPC, the Permittee shall use the following procedure to determine the MPC for each unit.

For the MPC determina on, there are three op ons:

(1) Use the following default value: 10 microgram/scm for sub‐bituminous coal; or(2) The Permittee may base the MPC on the results of site‐specific emission testing using the one of the Hg reference methods in item 4 of Table 5 to 40 CFR pt. 63, subp. UUUUU, if the unit does not have add‐on Hg emission controls or a flue gas desulfurization system, or if the Permittee tests upstream of these control devices. A minimum of 3 test runs are required, at the normal operating load. Use the highest total Hg concentra on obtained in any of the tests as the MPC; or(3) The Permittee may base the MPC on 720 or more hours of historical CEMS data or data from a sorbent trap monitoring system, if the unit does not have add‐on Hg emission controls or a flue gas desulfurization system (or if the CEMS or sorbent trap system is located upstream of these control devices) and if the Hg CEMS or sorbent trap system has been tested for relative accuracy against one of the Hg reference methods in Appendix A to 40 CFR pt. 63, subp. UUUUU and has met a relative accuracy specification of 20.0% or less. [Minn. R. 7007.0800, subps. 4‐5]

EQUI 109 13

Mercury: Percent Monitor Data Availability.

The Hg CEMS or sorbent trap monitoring system percent monitor data availability shall be determined in accordance with 40 CFR Section 75.32. [Minn. R. 7007.0800, subps. 4‐5]

EQUI 110 1

EQUI110 contains Mercury Continuous Emissions Monitoring System requirements from 40 CFR pt. 63, subp. UUUUU. Additional monitoring requirements may also apply to the Facility, and it is the responsibility of the Facility to meet all applicable requirements. [Minn. R. 7007.0800, subp. 4(A)]

Subject

Item ID

Sequence

Number Requirement

EQUI 110 2

Emissions Monitoring: The Permittee shall use EQUI110 for monitoring EQUI85 mercury emissions as required by Minn. Stat. 216B.681 and Minn. R. 7011.0561, subp. 5. EQUI110 hourly emissions data shall be determined according to the requirements of Minn. R. 7011.0561, subp. 6. During EQUI110 downtime, malfunction, or out of control periods (as defined in subp. UUUUU and Minn. R. 7017.1002), the Permittee shall follow the Missing Hg Concentration Data Substitution Requirements in this subject item for determining EQUI85 mercury emissions regulated by Minn. Stat. 216B.68 ‐ Minn. Stat. 216B.688 and Minn. R. 7011.0561.

Minn. Stat. 216B.68 ‐ Minn. Stat.216B.688 and Minn. R. 7011.0561 are state‐only requirements not enforceable by the administrator. [Minn. R. 7011.0561, subp. 5&6, Minn. Stat. 216B.681]

EQUI 110 3

The Permittee shall comply with the applicable mercury monitoring provisions at 40 CFR pt. 63, subp. UUUUU, Appendix A for EQUI110. [40 CFR pt. 63, subp. UUUUU, App. A, Minn. R. 7011.0563]

EQUI 110 4

The Permittee shall conduct a daily EQUI110 calibration error test according to the requirements of subp. UUUUU, Appendix A and Minn. R. 7011.0561, subp. 6.

Minn. R. 7011.0561 is a state‐only requirement not enforceable by the administrator. [40 CFR pt. 63, subp. UUUUU, App. A, Minn. R. 7011.0561, subp. 6, Minn. R. 7011.0563]

EQUI 110 5

The Permittee shall conduct a weekly EQUI110 single‐level system integrity check according to the requirements at subp. UUUUU, Appendix A and Minn. R. 7011.0561, subp. 6.


EQUI 110 6

The Permittee shall conduct a quarterly EQUI110 linearity check or 3‐level system integrity check according to the requirements at subp. UUUUU, Appendix A and Minn. R. 7011.0561, subp. 6.


EQUI 110 7

The Permittee shall conduct CEMS relative accuracy test audit (RATA) : Due annually for EQUI110 according to the requirements at subp. UUUUU, Appendix A and Minn. R. 7011.0561, subp. 6.

'Annually' means once every four QA operating quarters, and a 'QA operating quarter' is a calendar quarter with at least 168 unit or stack opera ng hours. Minn. R. 7011.0561 is a state‐only requirement not enforceable by the administrator. [40 CFR pt. 63, subp. UUUUU, App. A, Minn. R. 7011.0561, subp. 6, Minn. R. 7011.0563]

EQUI 110 8

Mercury: Missing Hg Concentration Data Substitution For Mercury Emissions Monitoring Required by Minn. Stat. 216B.681 and Minn. R. 7011.0561, subp. 5.

The Permittee shall provide substitute Hg concentration data for EQUI85 according to the missing data procedures in this permit whenever EQUI85 combusts any fuel and a valid, quality‐assured hour of Hg concentration data (in microgram/scm) has not been measured and recorded for EQUI85 by EQUI110 and EQUI105. (EQUI110 is a Hg CEMS certified in accordance with Appendix A to 40 CFR pt. 63, subp. UUUUU and EQUI105 is the data acquisition and handling system.). [Minn. R. 7007.0800, subp. 2(B), Minn. R. 7007.0800, subp. 4(D)]

Subject

Item ID

Sequence

Number Requirement

EQUI 110 9

Mercury: Initial Missing Hg Concentration Data Substitution During Unit Operating Hours.

(a) Before 720 quality assured monitor operating hours of Hg concentration data have been obtained following initial certification or recertification, the Permittee shall provide substitute data for Hg concentration in accordance with the procedures outlined below.

(b) For each hour of missing Hg emissions concentration data, the Permittee shall calculate the substitute data as follows:

(1) Whenever prior quality‐assured data exist, the Permittee shall substitute, by means of the data acquisition and handling system, for each hour of missing data, the average of the hourly Hg concentrations recorded by a certified monitor for the unit operating hour immediately before and the unit operating hour immediately after the missing data period.

(2) Whenever no prior quality assured Hg concentration data exist, the Permittee shall substitute, as applicable, for each hour of missing data, the maximum potential Hg concentration (MPC), as specified below. [Minn. R. 7007.0800, subps. 4‐5]

EQUI 110 10

Mercury: Standard Missing Hg Concentra on Data Subs tu on During Unit Opera ng Hours.

(a) Once 720 quality assured monitor operating hours of Hg concentration data have been obtained following initial certification or recertification, the Permittee shall provide substitute data for Hg concentration in accordance with the procedures outlined under "Standard Missing Hg Concentration Data Substitution Procedure" below.

(b) For any hour(s) in the missing data period for which any add‐on emission control equipment (including activated carbon injection as well as flue gas desulfurization that significantly reduces Hg emissions) is malfunctioning, the Permittee shall use the Maximum Potential Hg Concentration (MPC), as defined below. [Minn. R. 7007.0800, subps. 4‐5]

EQUI 110 11

Mercury: Standard Missing Hg Concentration Data Substitution Procedure.For each hour of missing Hg concentra on data (a er 720 quality assured monitor opera ng hours of Hg concentra on data have been obtained following ini al cer fica on or recer fica on),

(1) If the monitor data availability is equal to or greater than 90.0 percent, the Permi ee shall calculate substitute data by means of the automated data acquisition and handling system for that hour of the missing data period according to the following procedures:(i) For a missing data period less than or equal to 24 hours, substitute the average of the hourly Hg concentrations recorded by an Hg pollutant concentration monitor for the hour before and the hour after the missing data period.(ii) For a missing data period greater than 24 hours, subs tute the greater of:(A) The 90th percentile hourly Hg concentration recorded by an Hg pollutant concentration monitor during the previous 720 quality‐assured monitor opera ng hours*; or(B) The average of the hourly Hg concentrations recorded by an Hg pollutant concentration monitor for the hour before and the hour a er the missing data period.(2) If the monitor data availability is at least 80.0 percent but less than 90.0 percent, the Permi ee shall calculate substitute data by means of the automated data acquisition and handling system for that hour of the missing data period according to the following procedures:(i) For a missing data period of less than or equal to 8 hours, substitute the average of the hourly Hg concentrations recorded by an Hg pollutant concentration monitor for the hour before and the hour after the missing data period.(ii) For a missing data period of more than 8 hours, subs tute the greater of:(A) the 95th percentile hourly Hg concentration recorded by an Hg pollutant concentration monitor during the previous 720 quality‐assured monitor opera ng hours*; or(B) The average of the hourly Hg concentrations recorded by an Hg pollutant concentration monitor for the hour before and the hour a er the missing data period.[Minn. R. 7007.0800, subps. 4‐5]

Subject

Item ID

Sequence

Number Requirement

Cont. from Above:(3) If the monitor data availability is at least 70.0 percent but less than 80.0 percent, the Permittee shall substitute for that hour of the missing data period the maximum hourly Hg concentration recorded by an Hg pollutant concentration monitor during the previous 720 quality‐assured monitor operating hours*.

(4) If the monitor data availability is less than 70.0 percent, the Permittee shall substitute for that hour of the missing data period the maximum potential Hg concentration, as defined below.

*Quality‐assured, monitor operating hours, during unit operation. May be either fuel‐specific or non‐fuel‐specific. Use data from no earlier than 3 years prior to the missing data period. [Minn. R. 7007.0800, subps. 4‐5]

EQUI 110 12

Mercury: Maximum Poten al Concentra on (MPC).

When required to substitute missing Hg concentration data using the MPC, the Permittee shall use the following procedure to determine the MPC for each unit.

For the MPC determina on, there are three op ons:

(1) Use the following default value: 10 microgram/scm for sub‐bituminous coal; or(2) The Permittee may base the MPC on the results of site‐specific emission testing using the one of the Hg reference methods in item 4 of Table 5 to 40 CFR pt. 63, subp. UUUUU, if the unit does not have add‐on Hg emission controls or a flue gas desulfurization system, or if the Permittee tests upstream of these control devices. A minimum of 3 test runs are required, at the normal operating load. Use the highest total Hg concentra on obtained in any of the tests as the MPC; or(3) The Permittee may base the MPC on 720 or more hours of historical CEMS data or data from a sorbent trap monitoring system, if the unit does not have add‐on Hg emission controls or a flue gas desulfurization system (or if the CEMS or sorbent trap system is located upstream of these control devices) and if the Hg CEMS or sorbent trap system has been tested for relative accuracy against one of the Hg reference methods in Appendix A to 40 CFR pt. 63, subp. UUUUU and has met a relative accuracy specification of 20.0% or less. [Minn. R. 7007.0800, subps. 4‐5]

EQUI 110 13

Mercury: Percent Monitor Data Availability.

The Hg CEMS or sorbent trap monitoring system percent monitor data availability shall be determined in accordance with 40 CFR Section 75.32. [Minn. R. 7007.0800, subps. 4‐5]

EQUI 111 1


EQUI 111 2

Opacity <= 20 percent opacity except for one six‐minute period per hour of not more than 60 percent opacity. [Minn. R. 7011.0710, subp. 1(B)]

EQUI 111 3

Vent all EQUI111 emissions to fabric filter TREA46. TREA46 shall meet the applicable requirements in COMG3. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B)]

EQUI 112 1


EQUI 112 2


EQUI 112 3


EQUI 113 1


EQUI 113 2


Subject

Item ID

Sequence

Number Requirement

EQUI 113 3


EQUI 114 1


EQUI 114 2


EQUI 114 3


EQUI 115 1


EQUI 115 2


EQUI 115 3


EQUI 116 1


EQUI 116 2


EQUI 116 3


EQUI 117 1


EQUI 117 2


EQUI 117 3


EQUI 118 1



EQUI 118 3


EQUI 119 1

The Permittee is subject to Part 63, Subpart ZZZZ "National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines" because it owns and operates EQUI119/EU034 (a stationary RICE) located at a major HAP emissions source, and EQUI119 is not being tested at a stationary RICE test cell/stand. [40 CFR 63.6585, Minn. R. 7011.8150]

EQUI 119 2

EQUI119 is a stationary RICE subject to 40 CFR pt. 63, subp. ZZZZ because it has a site rating of greater than 500 brake HP, is located at a major source of HAP emissions, and the Permittee commenced construction of EQUI119 on or after December 19, 2002. [40 CFR 63.6590(a)(2)(i), Minn. R. 7011.8150]

EQUI 119 3

EQUI119 is subject to limited requirements because it is a new stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions that does not operate or is not contractually obligated to be available for more than 15 hours per calendar year for the purposes specified in Section 63.6640(f)(2)(ii) and (iii). [40 CFR 63.6590(b)(1)(i)]

Subject

Item ID

Sequence

Number Requirement

EQUI 119 4





EQUI 119 5

The Permittee owns and operates EQUI119 which is an emergency stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions. Therefore the Permittee does not need to comply with the emission limitations in Table 2a or operating limitations in Table 2b in pt. 63, subp. ZZZZ. [40 CFR 63.6600(c), Minn. R. 7011.8150]

EQUI 119 6

The Permittee must be in compliance with applicable requirements in pt. 63, subp. ZZZZ (other than the Table 2a emission limitations and Table 2b operating limitations) at all times. [40 CFR 63.6605(a), Minn. R. 7011.8150]

EQUI 119 7

At all times the Permittee must operate and maintain EQUI119, including associated air pollution control equipment and 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 the Permittee to make any further efforts to reduce emissions if levels required by this standard have been achieved. Determination of whether such operation and maintenance procedures are being used will be based 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 EQUI119. [40 CFR 63.6605(b), Minn. R. 7011.8150]

EQUI 119 8

The Permittee must operate EQUI119 according to the requirements in Section 63.6640(f)(1) through (4). In order for EQUI119 to be considered an emergency stationary ICE under pt. 63, subp. ZZZZ, any operation other than emergency operation, maintenance and testing, emergency demand response, and operation in non‐emergency situations for 50 hours per year, as described in Section 63.6640(f)(1) through (4) is prohibited. If the Permittee does not operate EQUI119 according to the requirements in Section 63.6640(f)(1) through (4), EQUI119 will not be considered an emergency engine under subp. ZZZZ and must meet all requirements for non‐emergency engines. Note that as of May 4, 2016, the U.S. Court of Appeals for the D.C. Circuit reversed and remanded paragraphs 63.6640(f)(2)(ii) and (iii) back to EPA for further action. [40 CFR 63.6640(f), Minn. R. 7011.8150]

Subject

Item ID

Sequence

Number Requirement

EQUI 119 9

(1) There is no time limit on the use of EQUI119 in emergency situations.

(2) The Permittee may operate EQUI119 for any of the purposes specified in paragraphs (f)(2)(i) of Section 63.6640 for a maximum of 100 hours per calendar year. Any operation for non‐emergency situations as allowed by paragraphs (f)(3) and (4) of Section 63.6640 counts as part of the 100 hours per calendar year allowed by Section 63.6640(f)(2).


EQUI 119 10

(3) EQUI119 may be operated 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 and emergency demand response provided in Section 63.6640(f)(2). The 50 hours per year for non‐emergency situations cannot be used for peak shaving or non‐emergency demand response, 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 119 12

Part 63 General Provisions: Except for the initial notification requirements, the Permittee is not required to comply with the requirements in Table 8 of pt. 63, subp. ZZZZ (pt. 63, subp. A General Provisions) for EQUI119 (because EQUI119 is a new emergency stationary RICE), [40 CFR 63.6665, Minn. R. 7011.8150]

EQUI 119 13

"Stationary internal combustion engine" means any internal combustion engine, except combustion turbines, that converts heat energy into mechanical work and is not mobile. Stationary ICE differ from mobile ICE in that a stationary internal combustion engine is not a nonroad engine as defined at 40 CFR 1068.30 (excluding paragraph (2)(ii) of that definition), and is not used to propel a motor vehicle, aircraft, or a vehicle used solely for compe on. Sta onary ICE include reciproca ng ICE, rotary ICE, and other ICE, except combus on turbines. "Emergency stationary internal combustion engine" means any stationary reciprocating internal combustion engine that meets all of the criteria in paragraphs (1) through (3) of this definition. All emergency stationary ICE must comply with the requirements specified in Section 60.4211(f) in order to be considered emergency stationary ICE. If the engine does not comply with the requirements specified in Section 60.4211(f), then it is not considered to be an emergency stationary ICE under part 60, subp. IIII. [40 CFR 60.4219, Minn. R. 7011.2305]

EQUI 119 14

The Permittee is subject to part 60, subp. IIII because it owns and operates EQUI119 for which construction commenced after July 11, 2005, EQUI119 was manufactured after April 1, 2006, and EQUI119 is not a fire pump engine. [40 CFR 60.4200(a)(2)(i), Minn. R. 7011.2305]

EQUI 119 15


EQUI 119 15


EQUI 119 16


Subject

Item ID

Sequence

Number Requirement

EQUI 119 18



EQUI 119 20


EQUI 119 21


EQUI 119 22

Use diesel fuel that meets the requirements of 40 CFR Section 80.510(b):


(2) Cetane index or aromatic content, as follows:


(ii) A maximum aromatic content of 35 volume percent. [40 CFR 60.4207(b), Minn. R. 7011.2305]

EQUI 119 23 Install a non‐resettable hour meter prior to EQUI119 startup. [40 CFR 60.4209(a), Minn. R. 7011.2305]

EQUI 119 24

(a) The Permittee must do all of the following, except as permitted under Section 60.4211(g):

(1) Operate and maintain EQUI119 (and any control device) according to the manufacturer's emission‐related written instructions;

(2) Change only those emission‐related settings that are permitted by the manufacturer; and


EQUI 119 25

(c) The Permittee must comply with pt. 60, subp. IIII by purchasing an engine certified to the emission standards in Section 60.4205(b), as applicable, for the same model year and maximum engine power. EQUI119 must be installed and configured according to the manufacturer's emission‐related specifications, except as permitted in Section 60.4211(g). [40 CFR 60.4211(c), Minn. R. 7011.2305]

EQUI 119 26


Subject

Item ID

Sequence

Number Requirement

EQUI 119 27




EQUI 119 28

(3) EQUI119 may be operated 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 and emergency demand response provided in Section 60.4211(f)(2). Except as provided in Section 60.4211(f)(3)(i), the 50 hours per calendar year for non‐emergency situations cannot be used for peak shaving or non‐emergency demand response, or to generate income for a facility to an electric grid or otherwise supply power as part of a financial arrangement with another en ty.

(i) The 50 hours per year for non‐emergency situa ons can be used to supply power as part of a financial arrangement with another en ty if all of the following condi ons are met:

(A) EQUI119 is dispatched by the local balancing authority or local transmission and distribu on system operator;

(B) The dispatch is intended to mi gate local transmission and/or distribu on limita ons so as to avert poten al voltage collapse or line overloads that could lead to the interrup on of power supply in a local area or region.(C) The dispatch follows reliability, emergency opera on or similar protocols that follow specific NERC, regional, state, public u lity commission or local standards or guidelines.(D) The power is provided only to the facility itself or to support the local transmission and distribu on system.

(E) The Permi ee iden fies and records the en ty that dispatches EQUI119 and the specific NERC, regional, state, public utility commission or local standards or guidelines that are being followed for dispatching EQUI119. The local balancing authority or local transmission and distribution system operator may keep these records on behalf of the Permittee. [40 CFR 60.4211(f)(3), Minn. R. 7011.2305]

EQUI 119 28

If the Permittee does not install, configure, operate, and maintain EQUI119 and control device according to the manufacturer's emission‐related written instructions, or changes emission‐related settings in a way that is not permitted by the manufacturer, the Permittee must keep a maintenance plan and records of conducted maintenance and must, to the extent practicable, maintain and operate EQUI119 in a manner consistent with good air pollution control practice for minimizing emissions. In addition, the Permittee must conduct an initial performance test to demonstrate compliance with the applicable emission standards within 1 year of startup, or within 1 year after EQUI119 and any control device is no longer installed, configured, operated, and maintained in accordance with the manufacturer's emission‐related written instructions, or within 1 year after the Permittee changes emission‐related settings in a way that is not permitted by the manufacturer. The Permittee must conduct subsequent performance testing every 8,760 hours of EQUI119 operation or 3 years, whichever comes first, thereafter to demonstrate compliance with the applicable emission standards. [40 CFR 60.4211(g)(3), Minn. R. 7011.2305]

EQUI 119 29


Subject

Item ID

Sequence

Number Requirement

EQUI 119 30

Commencing 2011, if EQUI119 does not meet the standards applicable to non‐emergency engines in the applicable model year, the Permittee must keep records of EQUI119 operation in emergency and non‐emergency service that are recorded through the non‐resettable hour meter. The Permittee must record the time of EQUI119 operation and the reason EQUI119 was in operation during that time. [40 CFR 60.4214(b), Minn. R. 7011.2305]

EQUI 119 31

Table 8 to part 60, subp. IIII specifies the requirements of part 60, subp. A that apply to EQUI119. [40 CFR 60.4218, Minn. R. 7011.2305]

EQUI 119 32


EQUI 119 33


EQUI 119 34


EQUI 119 35


EQUI 120 1


EQUI 120 2


EQUI 120 3


EQUI 120 4



EQUI 120 6


EQUI 122 2


EQUI 122 3


EQUI 122 4


EQUI 122 5



EQUI 122 7

Vent all captured EQUI122 emissions to fabric filter TREA36 (CE015). TREA36 shall meet the applicable requirements in COMG3. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

FUGI 3 1

Use best management practice (BMP) to control unpaved road dust. BMP includes watering, with additional control through use of chemical stabilizers during adversely dry conditions. Maintain a record for each day of all activities taken to control unpaved road dust. Maintain posted speed limit of 20 miles per hour. [Minn. R. 7011.0150]

FUGI 9 1

Coal Stockpile Working Area: The Permittee shall limit the active uncrusted coal stockpile working area to a maximum of 20 acres at any time. [Minn. R. 7007.0800, subp. 2(A)&(B)]

Subject

Item ID

Sequence

Number Requirement

FUGI 1 1


FUGI 2 1


Subject

Item ID

Sequence

Number Requirement

FUGI 9 2

The Permittee shall prepare, submit, and operate in accordance with a fugitive coal dust emissions control plan that is appropriate for the site conditions as specified in 40 CFR 60.254(c)(1) through (6). The fugitive coal dust emissions control plan for the coal storage pile (FUGI9) shall include the equipment used in the loading, unloading, and conveying opera ons of the storage pile (FUGI11).

Fugi ve coal dust emissions control plan revisions shall be made according to 40 CFR 60.254(c)(4)(ii).

The fugitive coal dust emissions control plan is a part of the Appendix D Fugitive Emissions Control Plan. [40 CFR 60.254(c), Minn. R. 7011.1150]

FUGI 10 2

Under dry pavement conditions, if the temperature is less than 35 degrees F, or if conditions due to weather in combination with the application of water, could create hazardous driving conditions, paved plant roads shall be swept weekly. Sweeping is not required if the pavement is snow or ice covered.

Under dry pavement conditions, if the temperature is greater than 35 degrees F, and conditions due to weather in combination with the application of water will not create hazardous driving conditions, paved plant roads shall be swept and flushed weekly.

FUGI10 is composed of the following components:

1. Paved Roads‐Light Vehicles2. Paved Roads‐Other Vehicles3. Paved Roads‐Ammonia Trucks4. Paved Roads‐Lime/Limestone Trucks5. Paved Roads‐PAC Trucks6. Paved Roads‐Fly Ash Trucks7. Paved Roads ‐ Coal to Rapids Energy Center8. Paved Roads ‐ J‐duct Material. [Minn. R. 7011.0150, Title I Condition: Avoid major modification under 40 CFR52.21(b)(2)(i) and Minn. R. 7007.3000]

FUGI 10 4

Maintain daily records of:‐ whether and which areas are snow and ice covered,‐ whether and which areas are dry,‐ dates of sweeping and areas swept,‐ dates of flushing and areas flushed, and‐ amounts of water applied when flushing. [Minn. R. 7007.0800, subp. 4, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) and Minn. R. 7007.3000]

FUGI 11 1

The Permittee shall prepare, submit, and operate in accordance with a fugitive coal dust emissions control plan that is appropriate for the site conditions as specified in 40 CFR 60.254(c)(1) through (6). The fugitive coal dust emissions control plan for the coal storage pile (FUGI9) shall include the coal stockpile material handling and the coal stockpile portable conveyors that comprise FUGI11.

Fugi ve coal dust emissions control plan revisions shall be made according to 40 CFR 60.254(c)(4)(ii).

The fugitive coal dust emissions control plan is a part of the Appendix D Fugitive Emissions Control Plan. [40 CFR 60.254(c), Minn. R. 7011.1150]

FUGI 11 2

A maximum of 10 portable coal stockpile conveyors may be operated at any time (11 drop points including the drop onto the stockpile). [Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

FUGI 11 2

The Permittee shall limit portable conveyor handling of Coal <= 450 tons per hour. [Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

Subject

Item ID

Sequence

Number Requirement

FUGI 11 4

Maximum Wind Speed During Coal Handling Activities: The Permittee shall cease coal stockpile material handling activities using portable conveyors when the 24‐hour average wind speed exceeds 20 miles per hour as measured at the Range Regional Airport in Hibbing, Minnesota. [Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

FUGI 11 5

Coal Moisture Content >= 20 percent by weight for all coal handled by coal stockpile portable conveyors. [Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

FUGI 11 6

Recordkeeping ‐ Number of Portable Coal Stockpile Conveyor Drop Points: The Permittee shall keep a log of the number of portable coal stockpile conveyor drop points in use for each day such conveyors are used. [Minn. R. 7007.0800, subps. 4‐5, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

FUGI 11 7

Coal Moisture Content Recordkeeping: The Permittee shall keep a record of the moisture content of all coal conveyed by the FUGI11 portable conveyors. [Minn. R. 7007.0800, subps. 4‐5, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

FUGI 11 8

Recordkeeping ‐ Portable Conveyor Capacity:

The Permittee shall keep a log of the capacity in tons per hour, of each FUGI11 portable conveyor. [Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

STRU 13 1

STRU13 SO2 1‐Hour Emissions Monitoring: The Permittee shall determine the 1‐hour STRU13 SO2 pound per hour emission rate using the EQUI105 Data Acquisition System and the EQUI36, EQUI40, and EQUI44 SO2 CEMS (and corresponding stack gas flow monitors) that measure EQUI82, EQUI83, and EQUI100 SO2 emissions, respectively. [Minn. R. 7007.0800, subp. 4(B)&(D)]

TREA 5 1

The Permittee shall operate and maintain TREA5 Selective Catalytic Reduction at all times that EQUI100 is in operation. The Permittee shall document periods of non‐operation of TREA5. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B)]

TREA 5 2

The Permittee shall operate and maintain TREA5 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. 7007.0800, subp. 14]

TREA 5 3

NOx Compliance Assurance Monitoring (CAM):

The Permittee shall use EQUI45 (Unit 3 NOx CEMS) for NOx CAM. NOx emissions in excess of any NOx limit are emission excursions under 40 CFR Sec on 64.6(c)(2). The Permittee shall comply with all applicable EQUI45 NOx CEMS requirements in COMG6. [40 CFR 64.3, Minn. R. 7017.0200]

TREA 5 4

TREA5 Corrective Actions:

The Permittee shall take corrective action as soon as possible if any of the following occur: ‐ The EQUI45 NOx CEMS indicates an exceedance of any applicable EQUI100 NOx emission limit; or ‐ TREA5 Selective Catalytic Reduction system or any of its components are found during any inspection to need repair.

Corrective actions shall reduce the EQUI100 NOx emission rate to less than any applicable NOx limit, and/or include completion of necessary repairs identified during any TREA5 inspection, as applicable. Corrective actions include, but are not limited to, those outlined in the TREA5 O&M Plan. The Permittee shall keep a record of the type and date of any TREA5 corrective action. [40 CFR 64.7(d), Minn. R. 7017.0200]

Subject

Item ID

Sequence

Number Requirement

TREA 5 5

The Permittee shall maintain records of monitoring data, monitor performance data, corrective actions taken, any written quality improvement plan required pursuant to 40 CFR Section 64.8 and any activities undertaken to implement a quality improvement plan, 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]

TREA 6 1

The Permittee shall operate and maintain TREA6 Low NOx Burners and Separated Over‐Fire Air at all times that EQUI85 is in operation. The Permittee shall document periods of non‐operation of TREA6. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B)]

TREA 6 2


TREA 7 1

The Permittee shall operate and maintain TREA7 ROTA‐Mix Selective Non‐Catalytic Reduction at all times that EQUI85 is in operation. The Permittee shall document periods of non‐operation of TREA7. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B)]

TREA 7 2


TREA 7 3


The Permittee shall use EQUI54 (Unit 4 NOx CEMS) for NOx CAM. NOx emissions in excess of any NOx limit are emission excursions under 40 CFR Sec on 64.6(c)(2).

The Permittee shall comply with all applicable EQUI54 NOx CEMS requirements in COMG6. [40 CFR 64.3, Minn. R. 7017.0200]

TREA 7 4


The Permittee shall take corrective action as soon as possible if any of the following occur: ‐ The EQUI54 NOx CEMS indicates an exceedance of any applicable EQUI85 NOx emission limit; or ‐ TREA7 Selective Noncatalytic Reduction system or any of its components are found during any inspection to need repair.


TREA 7 5


TREA 8 1

The Permittee shall operate and maintain TREA8 Low NOx Burners/Over‐Fire Air at all times that EQUI100 is in operation. The Permittee shall document periods of non‐operation of TREA8. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B)]

TREA 8 2


Subject

Item ID

Sequence

Number Requirement

TREA 9 1

The Permittee shall operate and maintain TREA9 Fabric Filter so that it achieves an overall control efficiency for Particulate Matter >= 99.6 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

TREA 9 2

The Permittee shall operate and maintain TREA9 Fabric Filter so that it achieves an overall control efficiency for PM < 10 micron >= 97.0 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

TREA 9 3

The Permittee shall operate and maintain TREA9 Fabric Filter so that it achieves an overall control efficiency for PM < 2.5 micron >= 88.4 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

TREA 9 4

The Permittee shall operate and maintain TREA9 Fabric Filter so that it achieves an overall control efficiency for Lead >= 93 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

TREA 9 5

The Permittee shall operate and maintain TREA9 Fabric Filter at all times that EQUI100 is in operation. The Permittee shall document periods of non‐operation of TREA9. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

TREA 9 6

The Permittee shall operate and maintain the TREA9 Fabric Filter 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. 7007.0800, subp. 14]

TREA 9 7

The Permittee shall conduct the monitoring required under part 64 upon permit issuance. [40 CFR 64.7(a), Minn. R. 7017.0200]

TREA 9 8

The Permittee shall comply with the approved monitoring for PM. The Permittee shall use pressure differential for monitoring PM. Differential pressure shall be measured with a differential pressure gauge. [40 CFR 64.3(b), 40 CFR 64.6(c)(1)(i)&(ii), Minn. R. 7017.0200, Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

TREA 9 9

The Permittee shall comply with the approved monitoring for PM10. The Permittee shall use pressure differential for monitoring PM10. Differential pressure shall be measured with a differential pressure gauge. [40 CFR 64.3(b), 40 CFR 64.6(c)(1)(i), 40 CFR 64.6(c)(1)(ii), Minn. R. 7017.0200]

TREA 9 10

Filterable PM and PM10 Compliance Assurance Monitoring (CAM):

TREA9 Pressure Drop >= 2.0 and <= 11.0 inches of water column 1‐hour average. The Permittee shall monitor and record four or more pressure drop values equally spaced over each hour. The Permittee shall average the values over the 1‐hour averaging period, and record the 1‐hour average pressure drop. If the recorded pressure drop is outside the required range by more than 0.1 inch w.c., the emissions during that time shall be considered uncontrolled until the pressure drop is once again within the required range. The period of time for which the pressure drop is considered out of range shall be reported as a deviation. [40 CFR 64.3(a)(2), Minn. R. 7017.0200]

TREA 9 12

TREA9 pressure drop indicator values may not be reset by the pressure drop values measured during a single PM/PM10 performance test because the permitted values were determined through examination of months of TREA9 pressure drop data encompassing compliant PM/PM10 performance testing. The Permittee shall follow the requirements of Minn. R. 7007.1150 through Minn. R. 7007.1500 to revise the TREA9 pressure drop indicators. [Minn. R. 7007.0800, subp. 2(A), Minn. R. 7007.1150 ‐ 7007.1500]

TREA 9 14

The Permittee shall operate and maintain a pressure drop monitoring device that continuously indicates and records the pressure drop across the fabric filter. [40 CFR 64.7(b)&(c), Minn. R. 7017.0200]

TREA 9 15

Continued Operation: Except for, as applicable, monitoring malfunctions, associated repairs, and required quality assurance or control activities, the Permittee shall continuously operate the monitoring system at all times the pollutant‐specific emissions unit is operating. [40 CFR 64.7(c), Minn. R. 7017.0200]

Subject

Item ID

Sequence

Number Requirement

TREA 9 16

An excursion from the specified parameter range occurs when TREA9 pressure drop deviates from the specified minimum or maximum by 0.1 inch w.c. or more on a 1‐hour average basis. [40 CFR 64.6(c)(2), Minn. R. 7017.0200]

TREA 9 17

Response to excursions or exceedances: Upon detecting an excursion or exceedance, the Permittee shall restore operation of the pollutant‐specific emissions unit to its normal or usual manner of operation as expeditiously as practicable in accordance with good air pollution control practices for minimizing emissions. [40 CFR 64.7(d)(1), Minn. R. 7017.0200]

TREA 9 18


1. The TREA9 differential pressure is less than 2.0 inches w.c. or greater than 11.0 inches w.c. on a 1‐hour average; or2. TREA9 fabric filter or any of its components are found to need repair during any inspection.

Corrective actions shall return the differential pressure to greater than or equal to 2.0 inches w.c. or less than or equal to 11.0 inches w.c., and/or complete necessary repairs identified during any inspection, as applicable. Corrective actions include, but are not limited to, those outlined in the TREA9 O&M Plan. The Permittee shall keep a record of the type and date of any TREA9 corrective action. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subps. 4‐5]

TREA 9 19

Documentation of need for improved monitoring: After approval of monitoring under this part, if the Permittee identifies a failure to achieve compliance with an emission limitation or standard for which the approved 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 indicator ranges or designated conditions, the Permittee shall promptly notify the permitting authority and, if necessary, submit a proposed modification to the part 70 permit to address the necessary monitoring changes. [40 CFR 64.7(e), Minn. R. 7017.0200]

TREA 9 20

Annual Calibration: The Permittee shall calibrate the pressure drop monitor at least once every 12 months and shall maintain a written record of the calibration and any action resulting from the calibration. [40 CFR 64.3(b)(3), Minn. R. 7017.0200]

TREA 9 21

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]

TREA 9 22

As required by 40 CFR Section 64.9(a)(2), for the Semi‐Annual Deviations Report required by this permit and/or the Notification of Deviations Endangering Human Health and the Environment required by 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 correc ve ac on 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 10 1

The Permittee shall operate and maintain TREA10 so that it achieves a control efficiency for Fluorides >= 65 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

TREA 10 2

The Permittee shall operate and maintain TREA10 so that it achieves a control efficiency for Hydrogen fluoride >= 65.0 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

Subject

Item ID

Sequence

Number Requirement

TREA 10 3

The Permittee shall operate and maintain TREA10 so that it achieves a control efficiency for Hydrogen Chloride >= 97.1 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

TREA 10 4

The Permittee shall operate and maintain TREA10 Wet Flue Gas Desulfurization at all times that EQUI100 is in operation. The Permittee shall document periods of non‐operation of TREA10. [40 CFR 50.17, Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7009.0020, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

TREA 10 5

SO2 Compliance Assurance Monitoring (CAM):

The Permittee shall use EQUI44 (Unit 3 SO2 CEMS) for EQUI100 SO2 CAM. All EQUI100 COMG1 SO2 limits are subject to CAM except the SO2 limits based on 40 CFR part 63, subp. UUUUU. SO2 emissions in excess of any SO2 limit subject to CAM are emission excursions under 40 CFR Section 64.6(c)(2).

The Permittee shall comply with all applicable EQUI44 SO2 CEMS requirements in COMG6. [40 CFR 64.3, Minn. R. 7017.0200]

TREA 10 6

Fluorides Emissions Monitoring:

The Permittee shall use EQUI44 (Unit 3 SO2 CEMS) SO2 emissions data as an indicator of fluorides emissions. Compliance with the 30‐day rolling average 0.030 pounds SO2 per million Btu heat input limit ensures compliance with the 0.0018 pounds per million Btu heat input EQUI100 fluorides limit unless demonstrated otherwise by a fluorides emissions performance test.

The Permittee shall comply with all applicable EQUI44 SO2 CEMS requirements in COMG6. [Minn. R. 7007.0800, subp. 4(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i)]

TREA 10 7

The Permittee shall operate and maintain TREA10 Wet Flue Gas Desulfurization 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. 7007.0800, subp. 14]

TREA 10 8

TREA10 Correc ve Ac ons For SO2 Emissions:

The Permi ee shall take correc ve ac on as soon as possible if any of the following occur:

‐ The EQUI44 SO2 CEMS indicates an exceedance of any applicable EQUI100 SO2 emission limit; or ‐ TREA10 Wet Flue Gas Desulfurization system or any of its components are found during any inspection to need repair.

Corrective actions shall reduce the EQUI100 SO2 emission rate to less than any applicable SO2 limit, and/or include completion of necessary repairs identified during any TREA10 inspection, as applicable. Corrective actions include, but are not limited to, those outlined in the TREA10 O&M Plan. The Permittee shall keep a record of the type and date of any TREA10 corrective action. [40 CFR 64.7(d), Minn. R. 7017.0200]

TREA 10 9

TREA10 Corrective Actions For Fluorides Emissions:

The Permittee shall take corrective action as soon as possible if any of the following occur:

‐ The result of any EQUI100 fluorides performance test exceeds the EQUI100 fluorides limit; or ‐ TREA10 Wet Flue Gas Desulfurization system or any of its components are found during any inspection to need repair.

Corrective actions shall reduce the EQUI100 fluorides emission rate to less than the EQUI100 fluorides limit, and/or include completion of necessary repairs identified during any TREA10 inspection, as applicable. Corrective actions include, but are not limited to, those outlined in the TREA10 O&M Plan. The Permittee shall keep a record of the type and date of any TREA10 corrective action. [Minn. R. 7007.0800, subp. 2(A)&(B)]

Subject

Item ID

Sequence

Number Requirement

TREA 10 10

TREA10 Correc ve Ac ons For Hydrogen Chloride Emissions: If the Permittee elects to comply with the (2.0 E‐03 pound per million Btu heat input or 2.0 E‐02 pound per megawatt) hydrogen chloride (HCl) emission limit at pt. 63, subp. UUUUU, Table 2 item 1.b. (instead of the 2.0 E‐01 pound per million Btu heat input or 1.5 pound per megawatt SO2 limit), the Permittee shall take corrective ac on as soon as possible if any of the following occur:

‐ The results of any EQUI100 hydrogen chloride (HCl) performance test exceed the EQUI100 HCl limit; or ‐ TREA10 Wet Flue Gas Desulfurization system or any of its components are found during any inspection to need repair.

Corrective actions shall reduce the EQUI100 HCl emission rate to less than the EQUI100 HCl limit and/or include completion of necessary repairs identified during any TREA10 inspection, as applicable. Corrective actions include, but are not limited to, those outlined in the TREA10 O&M Plan. The Permittee shall keep a record of the type and date of any TREA10 corrective action. [40 CFR 63.4(a)(1), Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7011.7000]

TREA 10 13

Fluorides Monitoring Revision: If the Permittee fails to demonstrate compliance with the EQUI100 0.0018 pounds per million Btu heat input fluorides limit during a fluorides performance test, and valid EQUI44 SO2 CEMS 1‐hour emissions data recorded over the span of the test did not exceed 0.030 pound per million Btu heat input, the Permittee shall promptly notify the MPCA and, if necessary, submit a permit amendment application to address the necessary monitoring change. [Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7007.0800, subp. 4(B)]

TREA 10 14


TREA 11 1


TREA 11 2


TREA 11 3




Subject

Item ID

Sequence

Number Requirement

TREA 11 4



‐ The EQUI41 NOx CEMS indicates an exceedance of any applicable EQUI83 NOx emission limit; or ‐ TREA11 Selective Noncatalytic Reduction system or any of its components are found during any inspection to need repair.


TREA 11 5


TREA 12 1

The Permittee shall operate and maintain TREA12 Rotating Over‐Fire Air at all times that EQUI82 is in operation. The Permittee shall document periods of non‐operation of TREA12. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B)]

TREA 12 2


TREA 13 1

The Permittee shall operate and maintain TREA13 Rotating Over‐Fire Air at all times that EQUI83 is in operation. The Permittee shall document periods of non‐operation of TREA13. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B)]

TREA 13 2


TREA 14 1

The Permittee shall operate and maintain TREA14 Fabric Filter such that it achieves an overall control efficiency for Particulate Matter >= 99 percent collection efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

TREA 14 2

The Permittee shall operate and maintain TREA14 Fabric Filter at all times that EQUI83 is in operation. The Permittee shall document periods of non‐operation of TREA14. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

TREA 14 3


TREA 14 4


TREA 14 5

The Permittee shall comply with the approved monitoring for particulate matter. The Permittee shall use pressure drop as a surrogate for monitoring particulate matter, and shall measure pressure drop with a pressure differential gauge. [40 CFR 64.3(b), 40 CFR 64.6(c)(1)(i), 40 CFR 64.6(c)(1)(ii), Minn. R. 7007.0800, subp. 4(B), Minn. R. 7017.0200]

Subject

Item ID

Sequence

Number Requirement

TREA 14 6

Filterable PM Compliance Assurance Monitoring (CAM):

TREA14 Pressure Drop >= 2.0 and <= 14.0 inches of water column 1‐hour average. The Permittee shall monitor and record four or more pressure drop values equally spaced over each hour. The Permittee shall average the values over the 1‐hour averaging period, and record the 1‐hour average pressure drop. If the recorded pressure drop is outside the required range by more than 0.1 inch w.c., the emissions during that time shall be considered uncontrolled until the pressure drop is once again within the required range. The period of time for which the pressure drop is considered out of range shall be reported as a deviation. [40 CFR 64.3(a)(2), Minn. R. 7017.0200, Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

TREA 14 7

TREA14 pressure drop indicator values may not be reset by the pressure drop values measured during a single PM performance test because the permitted values were determined through examination of at least one month of TREA14 pressure drop data encompassing compliant PM performance testing. The Permittee shall follow the requirements of Minn. R. 7007.1150 through Minn. R. 7007.1500 to revise the TREA14 pressure drop indicators. [Minn. R. 7007.0800, subp. 2(A), Minn. R. 7007.1150 ‐ 7007.1500]

TREA 14 8


TREA 14 9


TREA 14 10

An excursion from the specified parameter range occurs when the measured pressure drop deviates from the specified minimum or maximum by 0.1 inch w.c. or more on a 1‐hour average basis. [40 CFR 64.6(c)(2), Minn. R. 7017.0200]

TREA 14 11


TREA 14 12

Correc ve Ac ons: The Permi ee shall take correc ve ac on as soon as possible if any of the following occur:

‐ The TREA14 pressure drop gauge measures TREA14 1‐hour average pressure drop outside the permitted range; or‐ TREA14 fabric filter or any of its components are found during the inspec ons to need repair.

Corrective actions shall return the pressure drop 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 TREA14 O&M Plan. The Permittee shall keep a record of the type and date of any TREA14 corrective action. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subps. 4‐5]

TREA 14 13


TREA 14 14


Subject

Item ID

Sequence

Number Requirement

TREA 14 15


TREA 14 16

As required by 40 CFR Section 64.9(a)(2), for the Semi‐Annual Deviations Report required by this permit and/or the Notification of Deviations Endangering Human Health and the Environment required by 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 correc ve ac on 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 15 1


TREA 15 2


TREA 15 3




TREA 15 4


The Permittee shall take corrective action as soon as possible if any of the following occur: ‐ The EQUI37 NOx CEMS indicates an exceedance of any applicable EQUI82 NOx emission limit; or ‐ TREA15 Selective Noncatalytic Reduction system or any of its components are found during any inspection to need repair.


TREA 15 5


TREA 16 1

The Permittee shall operate and maintain TREA16 Fabric Filter such that it achieves an overall control efficiency for Particulate Matter >= 99 percent collection efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

Subject

Item ID

Sequence

Number Requirement

TREA 16 2

The Permittee shall operate and maintain TREA16 Fabric Filter at all times that EQUI82 is in operation. The Permittee shall document periods of non‐operation of TREA16. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

TREA 16 3


TREA 16 4


TREA 16 5

The Permittee shall comply with the approved monitoring for particulate matter. The Permittee shall use pressure drop as a surrogate for monitoring particulate matter, and shall measure pressure drop with a pressure differential gauge. [40 CFR 64.3(b), 40 CFR 64.6(c)(1)(i), 40 CFR 64.6(c)(1)(ii), Minn. R. 7017.0200]

TREA 16 6


TREA16 Pressure Drop >= 2.0 and <= 14.0 inches of water column 1‐hour average. The Permittee shall monitor and record four or more pressure drop values equally spaced over each hour. The Permittee shall average the values over the 1‐hour averaging period, and record the 1‐hour average pressure drop. If the recorded pressure drop is outside the required range by more than 0.1 inch w.c., the emissions during that time shall be considered uncontrolled until the pressure drop is once again within the required range. The period of time for which the pressure drop is considered out of range shall be reported as a deviation. [40 CFR 64.3(a)(2), Minn. R. 7017.0200, Title I Condition: 40 CFR 52.21(k)(modeling) & Minn. R. 7007.3000]

TREA 16 7

TREA16 pressure drop indicator values may not be reset by the pressure drop values measured during a single PM performance test because the permitted values were determined through examination of at least one month of TREA16 pressure drop data encompassing compliant PM performance testing. The Permittee shall follow the requirements of Minn. R. 7007.1150 through Minn. R. 7007.1500 to revise the TREA16 pressure drop indicators. [Minn. R. 7007.0800, subp. 2(A), Minn. R. 7007.1150 ‐ 7007.1500]

TREA 16 8


TREA 16 9


TREA 16 10

An excursion from the specified parameter range occurs when the measured pressure drop deviates from the specified minimum or maximum by 0.1 inch w.c. or more on a 1‐hour average basis. [40 CFR 64.6(c)(2), Minn. R. 7017.0200]

TREA 16 11


Subject

Item ID

Sequence

Number Requirement

TREA 16 12


‐ The TREA14 pressure drop gauge measures TREA14 1‐hour average pressure drop outside the permitted range; or‐ TREA14 fabric filter or any of its components are found during the inspections to need repair.

Corrective actions shall return the pressure drop 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 TREA14 O&M Plan. The Permittee shall keep a record of the type and date of any TREA14 corrective action. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subps. 4‐5]

TREA 16 13


TREA 16 14


TREA 16 15


TREA 16 16

As required by 40 CFR Section 64.9(a)(2), for the Semi‐Annual Deviations Report required by this permit and/or the Notification of Deviations Endangering Human Health and the Environment required by 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, andthe correc ve ac on taken; and,

2) Summary information on the number, duration, and cause for monitor downtime incidents. [40 CFR64.9(a)(2), Minn. R. 7017.0200]

TREA 21 1

The Permittee shall operate and maintain TREA21 Semi‐Dry Flue Gas Desulfurization and Fabric Filter so that it achieves a control efficiency for Particulate Matter >= 99.6 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), 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]

TREA 21 2

The Permittee shall operate and maintain TREA21 Semi‐Dry Flue Gas Desulfurization and Fabric Filter so that it achieves a control efficiency for PM < 10 micron >= 97.8 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

TREA 21 3

The Permittee shall operate and maintain TREA21 Semi‐Dry Flue Gas Desulfurization and Fabric Filter so that it achieves a control efficiency for PM < 2.5 micron >= 91.7 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

TREA 21 4

The Permittee shall operate and maintain TREA21 so that it achieves a control efficiency for Hydrogen Chloride >= 97.1 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

Subject

Item ID

Sequence

Number Requirement

TREA 21 5

The Permittee shall operate and maintain TREA21 Semi‐Dry Flue Gas Desulfurization and Fabric Filter so that it achieves a control efficiency for Fluorides >= 90 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B), Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R.7007.3000]

TREA 21 6

The Permittee shall operate and maintain TREA21 so that it achieves a control efficiency for Hydrogen fluoride >= 90.0 percent control efficiency. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 2(A)&(B)]

TREA 21 7

The Permittee shall operate and maintain TREA21 Semi‐Dry Flue Gas Desulfurization and Fabric Filter at all times that EQUI85 is in operation. The Permittee shall document periods of non‐operation of TREA21. [40 CFR 50.17, Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2(A)&(B), 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, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

TREA 21 8

The Permittee shall operate and maintain TREA21 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. 7007.0800, subp. 14]

TREA 21 9


TREA 21 10

The Permittee shall comply with the approved monitoring for PM, PM10, PM2.5, SO2, and fluorides. The Permittee shall use pressure drop as a surrogate for monitoring PM, PM10, and PM2.5, and shall measure pressure drop with a pressure differential gauge. The Permittee shall use EQUI53 (EQUI85 SO2 CEMS) for monitoring SO2 and fluorides. [40 CFR 64.3(b), 40 CFR 64.6(c)(1)(i), 40 CFR 64.6(c)(1)(ii), Minn. R. 7017.0200]

TREA 21 11


TREA21 Pressure Drop >= 4.0 and <= 18.0 inches of water column 1‐hour average. The Permittee shall monitor and record four or more pressure drop values equally spaced over each hour. The Permittee shall average the values over the 1‐hour averaging period, and record the 1‐hour average pressure drop. If the recorded pressure drop is outside the required range by more than 0.1 inch w.c., the emissions during that time shall be considered uncontrolled until the pressure drop is once again within the required range. The period of time for which the pressure drop is considered out of range shall be reported as a deviation. [40 CFR 64.3(a)(2), Minn. R. 7017.0200, 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]

TREA 21 12

PM10 and PM2.5 CAM:

TREA21 Pressure Drop >= 4.0 and <= 18.0 inches of water column 1‐hour average. The Permittee shall monitor and record four or more pressure drop values equally spaced over each hour. The Permittee shall average the values over the 1‐hour averaging period, and record the 1‐hour average pressure drop. If the recorded pressure drop is outside the required range by more than 0.1 inch w.c., the emissions during that time shall be considered uncontrolled until the pressure drop is once again within the required range. The period of time for which the pressure drop is considered out of range shall be reported as a deviation. [40 CFR 64.3(a)(2), Minn. R. 7017.0200]

TREA 21 12

TREA21 pressure drop indicator values may not be reset by the pressure drop values measured during a single PM/PM10/PM2.5 performance test because the permitted values were determined through examination of months of TREA21 pressure drop data encompassing compliant PM/PM10/PM2.5 performance testing. The Permittee shall follow the requirements of Minn. R. 7007.1150 through Minn. R. 7007.1500 to revise the TREA21 pressure drop indicators. [Minn. R. 7007.0800, subp. 2(A), Minn. R. 7007.1150 ‐ 7007.1500]

Subject

Item ID

Sequence

Number Requirement

TREA 21 13

SO2 CAM:

The Permittee shall use EQUI53 (Unit 4 SO2 CEMS) for EQUI85 SO2 CAM. All EQUI85 and STRU14 COMG1 SO2 limits are subject to CAM except the SO2 limits based on 40 CFR part 63, subp. UUUUU. SO2 emissions in excess of any SO2 limit subject to CAM are emission exceedances under 40 CFR Section 64.6(c)(2).

The Permittee shall comply with all applicable EQUI53 SO2 CEMS requirements in COMG6. [40 CFR 64.3(a)(2), Minn. R. 7017.0200]

TREA 21 14

Fluorides CAM:

The Permittee shall use EQUI53 SO2 emissions data for fluorides CAM. Compliance with the 30‐day rolling average 0.030 pounds per million Btu heat input EQUI85 SO2 limit ensures compliance with the 0.0084 pounds per million Btu heat input EQUI85 fluorides limit. SO2 emissions in excess of this SO2 limit are a fluorides emission excursion under 40 CFR Section 64.6(c)(2).

The Permittee shall review and verify the EQUI85 fluoride ‐ SO2 emissions relationship after completion of each EQUI85 fluorides performance to verify SO2 CEMS emissions data continues to be a valid indicator of fluorides emissions compliance as part of the TREA21 'Documentation of Need for Improved Monitoring' requirement.

The Permittee shall comply with all applicable EQUI53 SO2 CEMS requirements in COMG6. [40 CFR 64.3(a)(2), Minn. R. 7017.0200, Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2)(i) & Minn. R. 7007.3000]

TREA 21 15


TREA 21 16


TREA 21 17

An excursion from the specified parameter range or exceedance of an emission limit occurs under the following condi ons:

1. For PM, PM10, and PM2.5 emissions, an excursion occurs when the TREA21 pressure drop deviates from thespecified minimum or maximum by 0.1 inch w.c. or more on a 1‐hour average basis;

2. For fluoride emissions, an excursion occurs when EQUI53 measures SO2 in excess of the 30‐day rollingaverage 0.030 pounds per million Btu heat input EQUI85 SO2 limit;

3. For SO2, an exceedance occurs when EQUI53 measures SO2 in excess of any EQUI85 SO2 limit. [40 CFR64.6(c)(2), Minn. R. 7017.0200]

TREA 21 18


Subject

Item ID

Sequence

Number Requirement

TREA 21 19

Correc ve Ac ons ‐ SO2, Fluorides, PM, PM10, and PM2.5 Emissions:


‐ The EQUI53 SO2 CEMS indicates an exceedance of any EQUI85 SO2 applicable SO2 limit; ‐ The 1‐hour block average TREA21 pressure differen al is outside the permi ed 4.0 ‐ 18.0 inches w.c. range; ‐ The result of any EQUI85 fluorides performance test exceeds the EQUI85 fluorides limit; or ‐ TREA21 fabric filter/semi‐dry flue gas desulfurization or any of its components are found during the inspec ons to need repair.

Correc ve ac ons shall:

1. Reduce the EQUI85 SO2 emission rate to less than all applicable SO2 limits,

2. Return the TREA21 1‐hour block average pressure differen al to the permi ed range,3. Reduce the EQUI85 fluorides emission rate to less than the EQUI85 fluorides emission limit, and/or,4. Include comple on of necessary repairs iden fied during any TREA21 inspec on, as applicable.

Corrective actions include, but are not limited to, those outlined in the TREA21 O&M Plan. The Permittee shall keep a record of the type and date of any TREA21 corrective action. [40 CFR 64.7(d), Minn. R. 7017.0200]

TREA 21 20

Corrective Actions ‐ Hydrogen Chloride Emissions:

If the Permittee elects to comply with the (2.0 E‐03 pound per million Btu heat input or 2.0 E‐02 pound per megawatt) hydrogen chloride (HCl) emission limit at pt. 63, subp. UUUUU, Table 2 item 1.b. (instead of the 2.0 E‐01 pound per million Btu heat input or 1.5 pound per megawatt SO2 limit), the Permittee shall take corrective action as soon as possible if any of the following occur:

‐ The results of any EQUI85 hydrogen chloride (HCl) performance test exceed the EQUI85 HCl limit; or ‐ TREA21 Fabric Filter/Semi‐Dry Flue Gas Desulfurization system or any of its components are found during any inspection to need repair.

Corrective actions shall reduce the EQUI85 HCl emission rate to less than the EQUI85 HCl limit and/or include completion of necessary repairs identified during any TREA21 inspection, as applicable. Corrective actions include, but are not limited to, those outlined in the TREA21 O&M Plan. The Permittee shall keep a record of the type and date of any TREA21 corrective action. [40 CFR 63.4(a)(1), Minn. R. 7007.0800, subp. 2(A)&(B), Minn. R. 7011.7000]

TREA 21 21

Documentation of Need for Improved Monitoring: If the Permittee fails to demonstrate compliance with the EQUI85 0.0084 pounds per million Btu heat input fluorides limitation during a fluorides performance test and valid EQUI53 SO2 CEMS 1‐hour emissions data recorded over the span of the test did not exceed 0.030 pound per million Btu heat input, the Permittee shall promptly notify the MPCA and, if necessary, submit a permit amendment applica on to address the necessary monitoring change.

If the Permittee fails to demonstrate compliance with any EQUI85 PM, PM10, and/or PM2.5 limitation during a performance test and the TREA21 pressure differential gauge measures valid 1‐hour block average pressure drop data in the permitted 4.0 ‐ 18.0 inches w.c. range, the Permittee shall promptly notify the MPCA and, if necessary, submit a permit amendment application to address the necessary monitoring change. [40 CFR 64.7(e), Minn. R. 7017.0200]

TREA 21 22


Subject

Item ID

Sequence

Number Requirement

TREA 21 23


TREA 21 24

As required by 40 CFR Section 64.9(a)(2), for the Semi‐Annual Deviations Report required by this permit and/or the Notification of Deviations Endangering Human Health and the Environment required by 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, andthe corrective action taken; and,

2) Summary information on the number, duration, and cause for monitor downtime incidents. [40 CFR64.9(a)(2), Minn. R. 7017.0200]

TREA 22 2


TREA 22 8



‐ The EQUI110 Hg CEMS indicates an exceedance of any applicable EQUI85 Hg emission limit; or ‐ TREA22 Activated Carbon Injection system or any of its components are found during any inspection to need repair.

Corrective actions shall reduce the EQUI85 Hg emission rate to less than any applicable Hg limit, and/or include completion of necessary repairs identified during any TREA22 inspection, as applicable. Corrective actions include, but are not limited to, those outlined in the TREA22 O&M Plan. The Permittee shall keep a record of the type and date of any TREA22 corrective action. [Minn. R. 7007.0800, subp. 16(J)]

TREA 28 2


TREA 28 3

TREA28 Correc ve Ac ons:


‐ The EQUI109 Hg CEMS indicates an exceedance of any applicable EQUI100 Hg emission limit; or ‐ TREA28 Activated Carbon Injection system or any of its components are found during any inspection to need repair.

Corrective actions shall reduce the EQUI100 Hg emission rate to less than any applicable Hg limit, and/or include completion of necessary repairs identified during any TREA28 inspection, as applicable. Corrective actions include, but are not limited to, those outlined in the TREA28 O&M Plan. The Permittee shall keep a record of the type and date of any TREA28 corrective action. [Minn. R. 7007.0800, subp. 16(J)]

TREA 28 8

The Permittee shall operate and maintain a logic feedback loop between TREA28 (EQUI100 Activated Carbon Injection) and EQUI109 (EQUI100 Hg CEMS) to ensure optimization of ongoing TREA22 mercury reduction.

Minn. Stat. 216B.68 – Minn. Stat. 216B.688 is a state‐only requirement not enforceable by the administrator. [Minn. R. 7007.0800, subp. 2(B), Minn. Stat. 216B.687, subd. 3]

ATTACHMENT 4 – POINTS CALCULATOR



Points Calculator

1) AI ID No.: 2493 Total Points 113

2) Facility Name: Minnesota Power Inc - Boswell Energy Ctr

3) Small business? y/n? No

4) Air Project Tracking Numbers (including all 5161; 5254; 5383; 6017

5) Date of each Application Received: see below under 'NOTES'

6) Final Permit No. 06100004-008

7) Permit Staff Marshall Cole

Total Total

Application Type Air Project Tracking No. Tempo Activity ID Qty. Points Points Additionl Cost Details

Administrative Amendment 1 0 -$

Minor Amendment 5254; 5383 IND20150001; IND20150003 2 4 8 2,280.00$ 5254 coal stockpile; 5383 Unit 4 e-gen

Applicability Request 10 0 -$

Moderate Amendment 15 0 -$

Major Amendment 5161; 6017 IND20150002; IND20170001 2 25 50 14,250.00$

Individual State Permit (not reissuance) 50 0 -$

Individual Part 70 Permit (not reissuance) 75 0 -$

Additional Points

Modeling Review 15 0 -$

BACT Review 6017 IND20170001 1 15 15 4,275.00$ EQUI85 AND EQUI100 CO BACT REVISION

LAER Review 15 0 -$

CAA section 110(a)(2)(D)(i)(I) Review (i.e.,

Transport Rule/CAIR/CSAPR)10 0 -$

Part 75 CEM analysis 10 0 -$

NSPS Review 5383 (subp. IIII); 5254 (subp. Y) IND20150003; IND20150001 2 10 20 5,700.00$ IIII (Unit 4 e-gen EQUI119), Y (coal stockpile)

NESHAP Review 5383 (subp. ZZZZ) IND20150003 1 10 10 2,850.00$ ZZZZ (Unit 4 e-gen EQUI119

Case-by-case MACT Review 20 0 -$

Netting 10 0 -$

Limits to remain below threshold 5254 coal stockpile IND20150001 1 10 10 2,850.00$ Limits to avoid PSD

Plantwide Applicability Limit (PAL) 20 0 -$

AERA review 15 0 -$

Variance request under 7000.7000 35 0 -$

Confidentiality request under 7000.1300 2 0 -$

EAW review 0

Part 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 55

NOTES:

5161 Consent Decree; 6017 CO BACT

Application receipt dates: 5161 (Consent Decree) 3/31/2015; 5254 (coal stockpile increase) 6/2/2015; 5383 (Unit 4 E-Gen): 10/30/2015; 6017 (EQUI85 and EQUI100 CO

BACT revision) 12/26/2017

Total Additional Fee is $15,675.00

(DQ Points)

ATTACHMENT 5 - 2014 SO2 AND PM2.5 MODELING REPORT REVIEW



www.pca.state.mn.us • 651-296-6300 • 800-657-3864 • TTY 651-282-5332 or 800-657-3864 • Available in alternative formats

aq2-49 • 7/10/13 Page 1 of 5

AQDM-07 Air Quality Dispersion Modeling Report Review Form

for Criteria Pollutant Modeling using AERMOD (Previously AQDMRRF-01)

Doc Type: Air Dispersion Modeling

Acronym Information on Page 4

Instructions: This form is used for Minnesota Pollution Control Agency (MPCA) internal use by Air Dispersion Modelers to review

for Criteria Pollutant Modeling.

Facility Information

Project title: Submittal date (mm/dd/yyyy): 10/24/2014

AQ file no.: AQ facility/permit ID no.: 06100004 AQ tracking number: 4608

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

Facility name: Minnesota Power- Boswell Energy Center

Facility street address: 1210 NW 3rd

Street

City: Cohasset County: Itasca State: MN Zip Code: 55721

Facility contact: Melissa Weglarz Report prepared by: Jared Anderson

Facility contact phone: 218-355-3321 Preparer phone: 651-294-4592

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

MPCA air modeler: Melissa Sheffer MPCA air permit engineer: Marshall Cole

UTM coordinates of facility (NAD83, zone 15 extended only): x = 450,543.00 m East, y = 5,234,355.00 m North

List of Files with Names/Descriptions submitted with Modeling Report

1. AERMOD input files (*.inp, *.adi, *.ami)

AERMOD output files (*.out, *.ado, *.amo)

AERMOD plot files (*.plt)

AERMOD post files (*.pst) – If applicable

AERMOD event files (*.evi, *.evo) – If applicable

AERMOD miscellaneous/other files (MAXDCONT, SUMTABLE, etc.) – If applicable

2. AERMOD meteorological surface files (*.sfc)

AERMOD meteorological upper air/profile files (*.pfl)

3. BPIP-PRIME input files (*.bpi, *.pip)

BPIP-PRIME output files (*.bpo, *.sum)

4. Terrain file(s) for AERMAP(*.dem, *.tif)

AERMAP input files (*.ami)

AERMAP output files (*.rou, *.sou, etc.)

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

6. Figures for modeling results (*.jpeg, *.bmp, *.pdf)

GIS maps for modeling results (*.shp)

http://www.pca.state.mn.us/


aq2-49 • 7/10/13 Page 2 of 5

7. AQDM-02 form – if applicable (not applicable if changes were not made)

8. Other files and supporting documents (hourly ozone, background files, supplements, etc.):

Section 1. Modeling Review – 30-Day Substantial Completeness Determination

Completeness review of modeling report by sections

Section and section name

Substantially

complete/incomplete Deficiencies and/or comments

Files to accompany modeling Substantially Complete No comments on this section

Section 1: Modeling protocol Substantially Complete No comments on this section

Section 2: Changes to modeling protocol [Select from list]

Changes were made from the protocol to the report in

sections D, F, and J.

Section 3: Paved roads fugitive dust

(optional) Substantially Complete Paved roads were included in modeling.

Section 4: Modeling results Substantially Complete No comments on this section

Section 5: Discussion Substantially Complete No discussion included.

Section 6: Modeling results figures/maps Substantially Complete Figures included as an attachment to the aq2-48 form.

Modeling report substantially complete? Substantially Complete Date (mm/dd/yyyy): 12/18/2014

Section 2. Modeling Review – 150-Day Approval Determination/Permit Conditions

Has the 150-day completeness requirement been waived? No Yes

Technical review of final modeling report

Review items Acceptable/ Unacceptable Deficiencies and/or comments

Are all changes from the protocol adequately described and addressed? Acceptable

Changes to the modeling from the protocol included:

Section D: Four changes were made within this section. These changes included: 1) correcting the stack heights for SV17 and SV18; 2) changed the emission rates for SO2 at SV03 and SV04 (from 19,420 lb/hr and 6,131 lb/hr to 4,450 lb/hr to 2,600 lb/hr, respectively); 3) added area sources BECFS452-BECFS456 to the model to account for trucks picking up coal from the Boswell coal yard to deliver to the Rapids Energy Center; and 4) adding emission calculations and documentation for possible additional pollution control equipment from Clean Coal Solutions.

Section F: Receptor grid was corrected for the ambient air receptor that was placed on Keetac's property. Two modeling grids were modeled during this analysis: All receptors (minus one receptor on Keetac property) with



aq2-49 • 7/10/13 Page 3 of 5

Boswell and all three nearby sources, and one receptor (on Keetac property) with Boswell, Blandin, and Rapids Energy Center. Section J: Incorporated SO2 emission rates for Blandin/Rapids Energy Center and Keetac that were provided by MPCA. Also incorporated PM2.5 emissions for Keetac that were also provided by MPCA.

All of the changes that were described above and in the aq2-48 form were made to the analysis.

Are the model files consistent with the MPCA AQDM-02 spreadsheet accompanying the permit application? Acceptable

AQDM-02 spreadsheet lists BECSV020 and BECSV021 as horizontally-oriented stacks, but the exit velocities do not reflect that (set at 12.05 m/s instead of 0.001 m/s).

*Based on phone call with Jared Anderson on 1/7/15, the release types listed in the AQDM-02 spreadsheet was a typo. Both BECSV020 and BECSV021 are vertical releases and the exit velocities of 12.05 m/s are correct. This was also noted in the file "aq2-41 10-22-2014_MShefferEdits.xlsx".

BEC_SV03 was modeled at a rate of 560.688 g/s, but the AQDM-02 spreadsheet states that the emission rate is 327.593 g/s. It appears that the spreadsheet refers to the wrong cell (refers to BEC_SV04) for the emission rate. The same with the lb/hr emission rate as well. *This typo was verified during the 1/7/15 phone call with Jared Anderson. This was corrected to the link to the correct cells for the emission rates in the file "aq2-41 10-22-2014_MShefferEdits.xlsx".

Modeling demonstrates compliance with applicable NAAQS/MAAQS, SIL’s, and PSD increments? Acceptable

1-hour SO2 = 186.6 ug/m3 (including background of 23.58 ug/m3 and nearby sources), which is 95.2% of 1-hour SO2 NAAQS

24-hour PM2.5 = 28.17 ug/m3 (including background of 17 ug/m3 and nearby sources), which is 80.5% of 24-hour PM2.5 NAAQS

Modeling report approved? Acceptable Date (mm/dd/yyyy): 1/7/2015

Recommended permit conditions or related items: (To be determined)

Section 3. Recommended Permitting Language

Modeling language tier table

Pollutant Recommended tier

CO Not modeled

NO2 Not modeled

Pb Not modeled



aq2-49 • 7/10/13 Page 4 of 5

PM2.5 Tier 2

PM10 Not modeled

SO2 Tier 4

Tier language for each modeled pollutant will be based on the lowest growth level for all averaging times.

% of NAAQS/MAAQS: > 90% 90% - 75% < 75%

Allowable Growth Level: Low Medium High

PSD – Limits Tier 4 Tier 2** Tier 1

PSD – No Limits Tier 3 Tier 2** Tier 1

Not PSD – Limits Tier 3** Tier 2** Tier 1

Not PSD – No Limits Tier 1 Tier 1 Tier 1



aq2-49 • 7/10/13 Page 5 of 5

Acronyms

AERMAP AERMOD Terrain Preprocessor

AERMOD AMS/EPA Regulatory Model

AQ Air Quality

AQDMPS-01 Air Quality Dispersion Modeling Protocol Spreadsheet

BPIP-PRIME Building Profile Input Program for PRIME

CO Carbon Monoxide

MAAQS Minnesota State Ambient Air Quality Standard

MPCA Minnesota Pollution Control Agency

NAAQS National Ambient Air Quality Standard

NO2 Nitrogen Dioxide

Pb Lead

PM10 Particulate Matter less than 10 um in size

PM2.5 Particulate Matter less than 2.5 um in size

PSD Prevention of Significant Deterioration Program

SO2 Sulfur Dioxide


ATTACHMENT 6 - UPDATED CAM PLANS



1

BOSWELL ENERGY CENTER UNITS 1 AND 2 COMPLIANCE ASSURANCE MONITORING PLAN – PM

A. Emissions Unit

Description: Coal and natural gas fired boilers Emission Unit ID: EU001 and EU002, Air Emission Permit No. 06100004-007 Control Equipment: High temperature fabric filter (CE 001 & CE 002) Facility: Minnesota Power Boswell Energy Center,

Cohasset, MN

B. Applicable Regulation, Emissions Limits, and Monitoring Requirements

Regulation: 40 CFR Part 52.21(k) (ambient air impacts); US EPA Consent Decree 0:14-cv-2911-ADM-LIB,

9/29/1014

Emission Limits: 0.1 lbs/mmBtu – permit per 40 CFR 52.21(k) 0.015 lbs/mmBtu (3-hr avg) – Consent Decree Compliance Monitoring Requirements: Periodic stack tests not to exceed 60 months; annual for Consent Decree

C. Control Technology: High temperature fabric filter D. Monitoring Approach

The key elements of the monitoring approach are presented below: Indicator: fabric filter differential pressure (∆P) Normal Indicator Range: 2” – 14” w. c. ∆P (1-hour average basis)

E. Indicator Monitoring Performance Criteria

The Units 1 and 2 fabric filter differential pressure monitoring instrumentation is installed and maintained by Minnesota Power engineers and technicians in accordance with the manufacturer’s recommendations.


BOS 1&2 PM CAM Plan 5.9.18, JLMc, MP 2 of 4

F: Justification for Selection of Monitoring Indicator and Normal Indicator Range

Differential pressure is used as the performance indicator because it relates directly to proper fabric filter operation. An increase in differential pressure can indicate that the filter bags are aging or are blinded because the cleaning process is insufficient. Decreases in differential pressure may indicate damaged or missing bags or structural issues that can cause increased particulate emissions. The differential pressure indicator range for CAM purposes was selected based on historical data obtained during normal operation as described below. Differential pressure during the most recent performance test in 2012 is shown in the following two charts – 2” to 10” was normal when measured emissions of 0.007 lbs/mmBtu were less than ½ of the 0.015 lbs/mmBtu 3-hour average PM limit.



However, as the fabric filter bags age the differential pressure range increases as illustrated by comparing the 2012 charts to the 2016 chart below.



And, following a full bag replacement differential pressure decreases substantially as illustrated by comparing the 2016 Unit 1 chart above to the 2017 chart below.

To accommodate the full differential pressure range that occurs over the full fabric filter bag life cycle a differential pressure range of 2” – 14” w.c. is selected for CAM purposes. When a 1-hour average differential pressure outside this range occurs corrective action will be initiated to restore normal operation.

BOS 3 PM CAM Plan April 2018 Page 1 of 2

BOSWELL ENERGY CENTER UNIT 3 COMPLIANCE ASSURANCE MONITORING PLAN – PM/PM10

APRIL 2018 A. Emissions Unit

Description: Coal and natural gas-fired boiler Emission Unit ID: EU 003, Air Emission Permit No. 06100004-007 Facility: Minnesota Power Boswell Energy Center

B. Emission Limits and Applicable Regulations

Emission Limit Regulation 0.60 lbs/MMBtu Total PM Minn R. 7011.0510, subp. 1 0.014 lbs/MMBtu Filterable PM Minn R. 7007.0800, subp. 2 0.035 lbs/MMBtu PM10 Minn R. 7007.0800 subp. 2 0.015 lbs/MMBtu PM (3-hr avg) US EPA Consent decree 0:14-cv-2911-ADM-LIB, 9/29/1014

C. Control Technology: High temperature fabric filter. D. Performance Monitoring Indicator and Normal Indicator Range

Differential pressure (∆P) is used to monitor performance of the fabric filter. A 1-hour average ∆P between 2” and 11” w.c. indicates normal operation. Operation of Unit 3 with a fabric filter ∆P outside this normal indicator range is considered an excursion for possible corrective action and deviation reporting purposes.

E. Monitoring Equipment Performance Criteria

Differential pressure monitoring equipment is installed on the fabric filter by the Original Equipment Manufacturer (OEM) and the instruments are maintained and calibrated by Minnesota Power technicians following the OEM recommendations. Differential pressure measurements are continuously monitored and recorded by the Unit 3 control systems and are immediately available to control room operating personnel.

F: Justification for Selection of Performance Monitoring Indicator and Normal Indicator Range

Differential pressure is used as the performance indicator because it relates directly to proper fabric filter operation. An increase in ∆P can indicate that the filter bags are aging or are blinded because the cleaning process is insufficient. Decreases in ∆P may indicate damaged or missing bags or structural issues that can cause increased particulate emissions.

BOSWELL ENERGY CENTER UNIT 3 COMPLIANCE ASSURANCE MONITORING PLAN – PM/PM10

BOS 3 PM CAM Plan April 2018 2 of 2

The normal indicator range for the fabric filter ∆P (2” and 11” w.c.) was adopted based on years of operating experience and the manufacturer’s specifications. The highest ∆P occurs with aged filter bags and the higher airflows that occur under high boiler operating loads. The lowest ∆P occurs when the boiler is operating at low loads following periodic replacement of the filter bags as illustrated in the following chart:

Boswell Unit 3 Fabric Filter ∆P (1-hr avg)

BOS 3 SO2 F CAM Plan 4.24.17 1 of 1

BOSWELL ENERGY CENTER UNIT 3 COMPLIANCE ASSURANCE MONITORING PLAN – SO2 & FLOURIDES

A. Emissions Unit


B. Control Technology: Wet Flue Gas Desulfurization (FGD) D. Indicator of FGD Emissions Control Performance and Normal Operating Range SO2 emission rate is the FGD system performance indicator. The normal operating range

is less than or equal to the Unit 3 SO2 emission limits. Operation of Unit 3 with emissions exceeding permitted SO2 emission rates will be an excursion for responding and reporting

purposes. E. Monitoring Equipment Performance Criteria

The SO2 CEM (MR 036) is installed and operated consistent with 40 CFR Part 75.

F: Justification for Selection of Performance Monitoring Indicator

SO2 and fluorides are removed by the FGD process and FGD performance and emission limit compliance is continuously indicated by the SO2 CEM. Emission test results show that when SO2 emissions are controlled to comply with the SO2 limit fluoride emissions are controlled to a small percentage of the emission limit:

Date SO2 (lbs/mmBTU) F- (lbs/mmBtu)

Limit1 CEM 2 % of Limit F- Limit3 Test % of Limit 3/31/2010 0.030 0.026 87 % 0.0018 < 0.000114 < 6.1 % 2/18/2015 0.030 0.009 30 % 0.0018 0.00036 20 %

1 Unit 3 Consent Decree 30-day rolling average SO2 limit. 2 Unit 3 CEM hourly average SO2 emission rate during span of HF test runs. 3 Unit 3 fluoride limit. AP-42 states that fluoride emissions from combustion sources are "primarily" HF. 4 All analytical values used to calculate and report in-stack HF emission values are less than the laboratory's reported detection level(s)

1of 2

BOSWELL ENERGY CENTER UNIT 4 COMPLIANCE ASSURANCE MONITORING PLAN – PM/PM10/PM2.5

February 2018

A. Emissions Unit

Description: Coal and natural gas-fired boilers

Emission Unit ID: EU 004, Air Emission Permit No. 06100004-007

Facility: Minnesota Power Boswell Energy Center

B. Emission Limits and Applicable Regulations

Emission Limit Regulation

0.10 lbs/MMBtu Total PM Title I Condition: 40 CFR 52.21(j) PSD BACT limit and ambient impacts analysis; 40 CFR 60.42(a)(1)

0.015 lbs/MMBtu PM (3-hr avg) US EPA Consent decree 0:14-cv-2911-ADM-LIB, 9/29/1014 0.012 lbs/MMBtu front-half PM

Minn. R. 7007.0800, subp 2; state-only requirement 0.020 lbs/MMBtu PM10 0.020 lbs/MMBtu PM2.5

C. Control Technology: High temperature fabric filter.

D. Performance Monitoring Indicator and Normal Indicator Range

Differential pressure (∆P) is used to monitor performance of the fabric filter. A 1-hour average ∆P between 4” and 18” w.c. indicates normal operation. Operation of Unit 4 with a fabric filter ∆P outside this normal indicator range will be considered an excursion for possible corrective action and deviation reporting purposes.

E. Monitoring Equipment Performance Criteria

Differential pressure monitoring equipment is installed on the fabric filter by the Original Equipment Manufacturer (OEM) and the instruments are maintained and calibrated by Minnesota Power technicians following the OEM recommendations. Differential pressure measurements are continuously monitored and recorded by the Unit 4 control systems and are immediately available to control room operating personnel.

F: Justification for Selection of Performance Monitoring Indicator and Normal Indicator Range

Differential pressure is used as the performance indicator because it relates directly to proper fabric filter operation. An increase in ∆P can indicate that the filter bags are aging or are blinded because the cleaning process is insufficient. Decreases in ∆P may indicate damaged or missing bags or structural issues that can cause increased particulate emissions.

BOSWELL ENERGY CENTER UNIT 4 COMPLIANCE ASSURANCE MONITORING PLAN – PM/PM10/PM2.5

BOS 4 PM CAM Plan Feb 2018 Page 2 of 2

The indicator range is selected from baseline operating data collected since initial startup of the fabric filter in October, 2015. The ∆P has ranged between 4’’ and 13” w.c. on a 1- hour average basis; however, the CAM normal indicator range is set somewhat wider at 4” to 18” w.c. to allow for the inevitable gradual increase as the filter bags age through their life cycle.

Performance testing conducted during the baseline operating period demonstrates emission limit compliance by wide margins with ∆P in the normal operating range.

8/11/16 Performance Test PM = .0032 lbs/MMBtu

(27% of 0.012 lbs/MMBtu limit

10/4/16 Performance Test PM10 = .0101 lbs/MMBtu

(51% of 0.020 lbs/MMBtu limit PM2.5 – 0.0093 lbs/MMBtu

(47% of 0.020 lbs/MMBtu limit)

BOS 4 SO2 F CAM Plan 5.19.17 1 of 1

BOSWELL ENERGY CENTER UNIT 4 COMPLIANCE ASSURANCE MONITORING PLAN – SO2 & FLOURIDES

A. Emissions Unit


B. Control Technology: Semi-Dry Flue Gas Desulfurization (FGD) D. Indicator of FGD Emissions Control Performance and Normal Operating Range SO2 emission rate is the FGD system performance indicator. The normal operating range

is less than or equal to the Unit 4 SO2 emission limits. Operation of Unit 4 with emissions exceeding permitted SO2 emission rates will be an excursion for responding and reporting

purposes. E. Monitoring Equipment Performance Criteria

The SO2 CEM (MR 042) is installed, operated and certified under the EPA’s 40 CFR Part 75 regulations.

F: Justification for Selection of Performance Monitoring Indicator

SO2 and fluorides are removed by the FGD process, and FGD performance and emission limit compliance is continuously indicated by the SO2 CEM. Emission test results show that when SO2 emissions are controlled to comply with the SO2 limit, fluoride emissions are controlled to a small percentage of the emission limit:

Date SO2 (lbs/mmBTU) F- (lbs/mmBtu)

Limit1 CEM 2 % of Limit F- Limit3 Test Result % of Limit

10/4/2016 0.030 .024 80 % < or = to 0.0084

Below Detection

Limit4 0

1 Unit 4 Consent Decree 30-day rolling average SO2 limit. 2 Unit 4 CEM hourly average SO2 emission rate during span of HF test runs. 3 Unit 4 fluoride limit. AP-42 states that fluoride emissions from combustion sources are "primarily" HF. 4 All analytical values used to calculate and report in-stack HF emission values are less than the laboratory's reported detection level(s).

ATTACHMENT 7 - 2014 CONSENT DECREE



UNITED STATES DISTRICT COURT DISTRICT OF MINNESOTA

UNITED STATES OF AMERICA and THE STATE OF MINNESOTA by its MINNESOTA POLLUTION CONTROL AGENCY, Plaintiffs, v. ALLETE, INC., D/B/A MINNESOTA POWER Defendant.

) ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) )

Case No.: 0:14-cv-2911-ADM-LIB

CONSENT DECREE

CASE 0:14-cv-02911-ADM-LIB Document 3-1 Filed 07/16/14 Page 1 of 107

TABLE OF CONTENTS

I. JURISDICTION AND VENUE ................................................................................................. 3 II. APPLICABILITY ..................................................................................................................... 4 III. DEFINITIONS ......................................................................................................................... 4 IV. NOx EMISSION REDUCTIONS AND CONTROLS .......................................................... 17 V. SO2 EMISSION REDUCTIONS AND CONTROLS ............................................................ 23 VI. PM EMISSION REDUCTIONS AND CONTROLS............................................................ 29 VII. RETIRE, REFUEL, REPOWER, OR REROUTE OPTION AND FUELS AND RENEWABLE ENERGY ............................................................................................................. 36 VIII. PROHIBITION ON NETTING CREDITS OR OFFSETS ................................................. 38 IX. ENVIRONMENTAL MITIGATION PROJECTS................................................................ 40 X. CIVIL PENALTY ................................................................................................................. 42 XI. RESOLUTION OF CLAIMS AGAINST MINNESOTA POWER ....................................... 43 XII. PERIODIC REPORTING ..................................................................................................... 44 XIII. REVIEW AND APPROVAL OF SUBMITTALS ............................................................. 47 XIV. STIPULATED PENALTIES .............................................................................................. 48 XV. FORCE MAJEURE .............................................................................................................. 58 XVI. DISPUTE RESOLUTION ................................................................................................... 62 XVII. PERMITS ........................................................................................................................... 64 XVIII. INFORMATION COLLECTION AND RETENTION .................................................... 67 XIX. NOTICES............................................................................................................................. 68 XX. SALES OR TRANSFERS OF OPERATIONAL OR OWNERSHIP INTERESTS ............ 70 XXI. EFFECTIVE DATE ............................................................................................................. 73 XXII. RETENTION OF JURISDICTION ................................................................................... 73 XXIII. MODIFICATION ............................................................................................................. 73 XXIV. GENERAL PROVISIONS ............................................................................................... 73 XXV. SIGNATORIES AND SERVICE ...................................................................................... 76 XXVI. PUBLIC COMMENT ....................................................................................................... 77 XXVII. TERMINATION ............................................................................................................. 77 XXVIII. FINAL JUDGMENT...................................................................................................... 79 APPENDIX A -- ENVIRONMENTAL MITIGATION PROJECTS


1

WHEREAS, Plaintiff, the United States of America (“the United States”), on behalf of

the United States Environmental Protection Agency (“EPA”), and Plaintiff, the StatMinnesota by

its Minnesota Pollution Control Agency, are concurrently filing a Complaint and Consent Decree

for injunctive relief and civil penalties pursuant to Sections 113(a)(3) and (b)(2) and 167 of the

Clean Air Act (the “Act”), 42 U.S.C. §§ 7413(a)(3) and (b)(2) and 7477, alleging that ALLETE,

Inc. (d/b/a Minnesota Power) (“Minnesota Power”) violated the Prevention of Significant

Deterioration of Air Quality provisions found at Part C of Title I of the Act, 42 U.S.C. §§ 7470-

7492, and the requirements of Title V of the Act, 42 U.S.C. §§ 7661-7661f;

WHEREAS, the EPA has not approved a State of Minnesota State Implementation Plan

for purposes of Parts C (Prevention of Significant Deterioration of Air Quality) of Title I of the

Clean Air Act, but has delegated its authority to implement the Part C program to the State of

Minnesota at 40 C.F.R. 52.1234;

WHEREAS, the State of Minnesota has no areas designated as “nonattainment” for

nitrogen oxides, sulfur dioxide, or particulate matter under Part D of Title I of the Clean Air Act

at this time, and is therefore not required to have an approved Part D program for these

pollutants;

WHEREAS, on August 5, 2008 and March 31, 2011, EPA issued Notices of

Violation/Findings of Violation (“NOVs/FOVs”) to Minnesota Power with respect to certain

alleged violations of the CAA;

WHEREAS, the United States provided Minnesota Power and the State of Minnesota

with actual notice pertaining to Minnesota Power’s alleged violations, in accordance with

Section 113 of the Act, 42 U.S.C. § 7413;

WHEREAS, in the Complaint, the United States and the State of Minnesota (collectively


2

"Plaintiffs") allege claims upon which, if proven, relief can be granted against Minnesota Power

under Sections 113 and 167 of the Act, 42 U.S.C. §§ 7413 and 7477;

WHEREAS, in the Complaint, Plaintiffs allege, inter alia, that Minnesota Power made

major modifications to major emitting Units, and failed to obtain the necessary permits and

failed to install and operate the controls necessary under the Act to reduce sulfur dioxide,

nitrogen oxides, and/or particulate matter emissions, and that such emissions damage human

health and the environment;

WHEREAS, Minnesota Power has not answered the Complaint in light of the settlement

memorialized in this Decree;

WHEREAS, nothing herein shall constitute an admission of liability, and Minnesota

Power has denied and continues to deny the violations alleged in the NOVs/FOVs and

Complaint; maintains that it has been and remains in compliance with the Act and is not liable

for civil penalties or injunctive relief; and states that it is agreeing to the obligations imposed by

this Consent Decree solely to avoid the costs and uncertainties of litigation and to improve the

environment;

WHEREAS, the United States, the State of Minnesota, and Minnesota Power

(collectively, the “Parties”) have agreed that settlement of this action is in the best interests of the

Parties and in the public interest, and that entry of this Consent Decree without further litigation

is the most appropriate means of resolving this matter;

WHEREAS, the Parties anticipate that the installation and operation of pollution control

equipment pursuant to this Consent Decree, and the Retirement, Refueling, or Repowering of

certain facilities required by this Consent Decree, will achieve significant reductions of sulfur

dioxide, nitrogen oxides, and particulate matter emissions, as well as other pollutants, and


3

improve air quality;

WHEREAS, the Parties have agreed, and this Court by entering this Consent Decree

finds, that this Consent Decree has been negotiated in good faith and at arm’s length and that this

Consent Decree is fair, reasonable, in the public interest, and consistent with the goals of the Act;

and

WHEREAS, the Parties have consented to entry of this Consent Decree without trial of

any issues;

NOW, THEREFORE, without any admission of fact or law, it is hereby ORDERED,

ADJUDGED, AND DECREED as follows:

I. JURISDICTION AND VENUE

1. This Court has jurisdiction over this action, the subject matter herein, and the

Parties consenting hereto, pursuant to 28 U.S.C. §§ 1331, 1345, 1355, and 1367, and pursuant to

Sections 113 and 167 of the Act, 42 U.S.C. §§ 7413 and 7477. Venue is proper under Section

113(b) of the Act, 42 U.S.C. § 7413(b), and under 28 U.S.C. § 1391(b) and (c). Solely for the

purposes of this Consent Decree and the underlying Complaint, and for no other purpose,

Minnesota Power waives all objections and defenses that it may have to the Court’s jurisdiction

over this action, the Court’s jurisdiction over Minnesota Power, and to venue in this judicial

district. Minnesota Power consents to and shall not challenge entry of this Consent Decree or

this Court’s jurisdiction to enter and enforce this Consent Decree. Notwithstanding the

foregoing, should this Consent Decree not be entered by this Court, then the waivers and

consents set forth in this Section I (Jurisdiction and Venue) shall be null and void and of no

effect.


4

2. Except as expressly provided for herein, this Consent Decree shall not create any

rights in or obligations of any party other than the Parties to this Consent Decree. Except as

provided in Section XXVI (Public Comment) of this Consent Decree, the Parties consent to entry

of this Consent Decree without further notice.

II. APPLICABILITY

3. Upon entry, the provisions of this Consent Decree shall apply to and be binding

upon the United States, the State of Minnesota, and upon Minnesota Power and any successors,

assigns, or other entities or persons otherwise bound by law.

4. Minnesota Power shall provide a copy of this Consent Decree to all vendors,

suppliers, consultants, contractors, agents, and any other company or other organization retained

to perform any of the work required by this Consent Decree. Notwithstanding any retention of

contractors, subcontractors, or agents to perform any work required under this Consent Decree,

Minnesota Power shall be responsible for ensuring that all work is performed in accordance with

the requirements of this Consent Decree. In any action to enforce this Consent Decree, except as

expressly provided herein (e.g. Section XV (Force Majeure)), Minnesota Power shall not assert

as a defense the failure of its officers, directors, employees, servants, agents, or contractors to

take actions necessary to comply with this Consent Decree.

III. DEFINITIONS

5. Every term expressly defined by this Section shall have the meaning given that

term herein. Every other term used in this Consent Decree that is also a term used under the Act

or in a federal regulation implementing the Act shall mean in this Consent Decree what such

term means under the Act or those regulations.


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6. A “12-Month Percent Heat Input from Coal” for a Rapids Unit shall be expressed

as a percentage and calculated as follows: first, sum the total heat input to the Unit from coal in

mmBTU during the current Operating Month and the previous eleven (11) Operating Months;

second, sum the total heat input to the Unit from all fuel sources in mmBTU during the current

Operating Month and the previous eleven (11) Operating Months; and third, divide the total heat

input from coal by the total heat input from all fuel sources.

7. A “12-Month Rolling Average Emission Rate” for a Unit shall be expressed in

lb/mmBTU and calculated in accordance with the following procedure: first, sum the total

pounds of pollutant emitted from the applicable Unit during the current Operating Month and the

previous eleven (11) Operating Months; second, sum the total heat input to the unit in mmBTU

during the current Operating Month and the previous eleven (11) Operating Months; and third,

divide the total number of pounds of pollutant emitted during the twelve (12) Operating Months

by the total heat input during the twelve (12) Operating Months. A new 12-Month Rolling

Average Emission Rate shall be calculated for each new Operating Month in accordance with the

provisions of this Consent Decree. Each 12-Month Rolling Average Emission Rate shall include

all emissions of the applicable pollutant that occur during all periods of operation, including

startup, shutdown, and Malfunction, except as otherwise provided by Section XV (Force

Majeure).

8. A “3-Hour Rolling Average Emission Rate” for a Unit shall be expressed in


pounds of pollutant emitted from the Unit during the current operating hour and the previous two

operating hours; second, sum the total heat input to the Unit in mmBTU during the current

operating hour and the previous two operating hours; and third, divide the total number of


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pounds of pollutant emitted during the three operating hours by the total heat input during the

three operating hours. Each 3-Hour Rolling Average Emission Rate shall include all emissions

that occur during all periods within any operating period, including emissions from startup,

shutdown, and Malfunction, except as otherwise provided by Section XV (Force Majeure).

9. A “30-Day Rolling Average Emission Rate” for a Unit shall be expressed in


pounds of pollutant emitted from the applicable Unit during the current Operating Day and the

previous twenty-nine (29) Operating Days; second, sum the total heat input to the unit in

mmBTU during the current Operating Day and the previous twenty-nine (29) Operating Days;

and third, divide the total number of pounds of pollutant emitted during the thirty (30) Operating

Days by the total heat input during the thirty (30) Operating Days. A new 30-Day Rolling

Average Emission Rate shall be calculated for each new Operating Day. Each 30-Day Rolling

Average Emission Rate shall include all emissions that occur during all periods within any

Operating Day, including emissions from startup, shutdown, and Malfunction, except as

otherwise provided by Section XV (Force Majeure).

10. “Baghouse” means a full-stream (fabric filter) particulate emissions control

device.

11. “Boswell” means, for purposes of this Consent Decree, Minnesota Power’s

Boswell Energy Center consisting of four coal-fired units designated by Minnesota Power (as

reported to the SEC by Minnesota Power) as Boswell Unit 1 (68 net MW), Boswell Unit 2 (68

net MW), Boswell Unit 3 (362 net MW), and Boswell Unit 4 (585 net MW) and located in

Cohasset, Minnesota. Boswell Units 1, 2 and 3 currently share a common stack, but have

separate SO2 and NOx CEMS prior to the common stack. Boswell Unit 4 currently has a


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separate stack and separate SO2 and NOx CEMS.

12. “Business Day” means a Day that is not Saturday, Sunday or a Federal Holiday.

In computing any period of time for submission of a notice or report under this Consent Decree,

where the last Day would fall on a Saturday, Sunday, or Federal Holiday, the period shall run

until the close of business on the next Business Day.

13. Calendar Year Average Emission Rate for a Unit shall be expressed in

lb/mmBTU and calculated by dividing the total number of pounds of pollutant emitted during the

calendar year by the total heat input during the calendar year. Each Calendar Year Average

Emission Rate shall include all emissions of the applicable pollutant that occur during all periods

of operation, including startup, shutdown, and Malfunction, except as otherwise provided by

Section XV (Force Majeure).

14. “Clean Air Act,” “Act,” or “CAA” means the federal Clean Air Act, 42 U.S.C.

§§ 7401-7671q, and its implementing regulations.

15. “Consent Decree” means this Consent Decree and the Appendices hereto, which

are incorporated into the Consent Decree.

16. “Continuous Emissions Monitoring System” or “CEMS” means, for obligations

involving the monitoring of nitrogen oxides (“NOx”) and sulfur dioxide (SO2) emissions under

this Consent Decree, the devices defined in 40 C.F.R. § 72.2 and installed, operated, and

maintained as required by 40 C.F.R. Part 75 or, for purposes of Rapids, as required by 40 C.F.R.

Part 60 and Minn. R. 7017.1002 - .1170.

17. “Continuous Operation” and “Continuously Operate” mean that when a

pollution control technology or combustion control is required to be used at a Unit pursuant to

this Consent Decree (including, but not limited to a Baghouse, Dry Sorbent Injection system,


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Electrostatic Precipitator, Flue Gas Desulfurization system, Furnace Sorbent Injection system,

Low Nitrogen Oxides Burner, Over Fire Air system, Rotating Opposed Fire Air system,

Selective Catalytic Reduction device, Selective Non-Catalytic Reduction device, Wet Particulate

Scrubber, and/or Wet Venturi/ESP device) it shall be operated at all times such Unit is in

operation (except as otherwise provided by Section XV Force Majeure), consistent with the

technological limitations, manufacturers’ specifications, good engineering and maintenance

practices, and good air pollution control practices for minimizing emissions (as defined in 40

C.F.R. § 60.11(d)) for such equipment and the Unit.

18. “Date of Entry” means the date this Consent Decree is approved or signed by the

United States District Court Judge.

19. “Date of Lodging” means the date this Consent Decree is filed for lodging with

the Clerk of the Court for the United States District Court for the District of Minnesota.

20. “Day” means calendar Day unless otherwise specified in this Consent Decree.

21. “Dry Sorbent Injection” or “DSI” means a process in which a sorbent is injected

into the flue gas ductwork downstream of the boiler and upstream of the PM Control Device.

22. “Electrostatic Precipitator” or “ESP” means a control device for removing

particulate matter from flue gases by imparting an electric charge to the particles and then

attracting them to a metal plate or screen of opposite charge before the flue gases are exhausted

to the atmosphere.

23. “Emission Rate” for a given pollutant means the number of pounds of that

pollutant emitted per million British thermal units of heat input (lb/mmBTU), calculated in

accordance with this Consent Decree.

24. “EPA” means the United States Environmental Protection Agency.


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25. “Flue Gas Desulfurization” or “FGD” system means a pollution control device

that removes sulfur compounds from a flue gas stream, including an absorber or absorbers

utilizing lime, limestone, or a sodium-based slurry, for the reduction of SO2 emissions. FGD

shall not be defined as the use of any Dry Sorbent Injection system, as described above.

26. “Fossil Fuel” means any hydrocarbon fuel, including coal, petroleum coke,

petroleum oil, fuel oil, or natural gas.

27. “Furnace Sorbent Injection” or “FSI” means the process that involves injecting

dry sorbents into the upper furnace of a boiler to reduce sulfur dioxide (SO2) emissions by

forming solid products that can be captured by particulate control equipment and later removed.

28. A “Heat Input Weighted Average Emission Rate” shall be expressed in

lb/mmBTU and calculated in accordance with the following procedure: first, multiply 0.200

times the total heat input to Boswell Unit 1 and 2 for the current day and the previous twenty-

nine (29) days; second, multiply 0.060 times the total heat input to Boswell Unit 3 for the current

day and the previous twenty-nine (29) days; and third, divide the sum of the first and second

steps by the total heat input to Boswell Unit 1, Boswell Unit 2, and Boswell Unit 3 for the

current day and the previous twenty-nine (29) days; provided that such twenty-nine (29) days

shall not include days during which none of Boswell Unit 1, Boswell Unit 2, or Boswell Unit 3

fires Fossil Fuel. Minnesota Power shall substitute the actual measured emission rates for the

0.200 or 0.060 factors in the equation above for any Unit for which it is practically feasible to

obtain a representative measurement of NOx. A new Heat Input Weighted Average Emission

Rate shall be calculated for each new Operating Day. Each Heat Input Weighted Average

Emission Rate shall include all emissions that occur during all periods within any Operating

Day, including emissions from startup, shutdown, and Malfunction, except as otherwise provided


10

by Section XV (Force Majeure).

29. “Laskin” means, for purposes of this Consent Decree, Minnesota Power’s Laskin

Energy Center consisting of two coal-fired units designated by Minnesota Power (as reported to

the SEC by Minnesota Power) as Laskin Unit 1 (47 net MW) and Laskin Unit 2 (50 net MW)

and located in Hoyt Lakes, Minnesota. Laskin Unit 1 and Laskin Unit 2 share a common stack

with a shared NOx and SO2 CEMS located in the common stack.

30. “lb/mmBTU” means one pound per million British thermal units.

31. “Low Nitrogen Oxides Burner,” “Low NOx Burner,” or “LNB” means

commercially available combustion modification technology that minimizes NOx formation by

introducing coal and combusting air into a boiler such that initial combustion occurs in a manner

that promotes rapid coal devolatilization in a fuel-rich (i.e. oxygen deficient) environment and

introduces additional air to achieve a final fuel-lean (i.e. oxygen rich) environment to complete

the combustion processes.

32. “Malfunction” means any sudden, infrequent, and not reasonably preventable

failure of air pollution control equipment, process equipment, or a process to operate in a normal

or usual manner. Failures that are caused in part by poor maintenance or careless operation are

not Malfunctions.

33. “MPCA” means the Minnesota Pollution Control Agency and any successor

agency or department of MPCA authorized by the State of Minnesota.

34. “Minnesota Power System” means, solely for purposes of this Consent Decree,

Minnesota Power’s Boswell Energy Center Units 1 through 4, Laskin Energy Center Units 1 and

2, Taconite Harbor Energy Center Units 1 through 3, and Rapids Energy Center Units 5 and 6.

35. “Minnesota Renewable Energy Standard” or “Minnesota RES” means the


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standard set forth in Minnesota Statutes § 216B.1691, Subd. 2a(a).

36. “Month” means a calendar month.

37. “MW” means a megawatt or one million watts.

38. “MWh” means a megawatt hour or one million watt hours.

39. “National Ambient Air Quality Standards” or “NAAQS” means national ambient

air quality standards promulgated pursuant to Section 109 of the Act, 42 U.S.C. § 7409.

40. “Natural Gas” means natural gas received directly or indirectly through a

connection to an interstate pipeline.

41. “Netting” shall mean the process of determining whether a particular physical

change or change in the method of operation of a major stationary source results in a net

emissions increase, as that term is defined at 40 C.F.R. § 52.21(b)(3)(i), and/or an applicable

State Implementation Plan (“SIP”) and/or other clean air rules administered by MPCA.

42. “Nonattainment NSR” means the new source review program within the meaning

of Part D of Title I of the Act, 42 U.S.C. §§ 7501-7515 and 40 C.F.R. Part 51, and corresponding

provisions of an applicable SIP, and all rules addressing nonattainment new source review

administered by MPCA.

43. “Nitrogen Oxides” or “NOx” means oxides of nitrogen, measured in accordance

with the provisions of this Consent Decree.

44. “NOx Allowance” means an authorization to emit a specified amount of NOx that

is allocated or issued under an emissions trading or marketable permit program of any kind

established under the Clean Air Act or applicable State Implementation Plan; provided, however,

that with respect to any such program that first applies to emissions occurring after December 31,

2011, a “NOx Allowance” shall include a NOx Allowance created and allocated to a Minnesota


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Power System Unit under such program only for control periods starting on or after the fourth

anniversary of the Date of Entry of this Consent Decree.

45. “Operational or Ownership Interest” means part or all of Minnesota Power’s legal

or equitable operational or ownership interest in any Unit at its Boswell Energy Center, Laskin

Energy Center, Taconite Harbor Energy Center and/or Rapids Energy Center.

46. “Operating Day” means any calendar Day on which a Unit fires Fossil Fuel.

47. “Operating Month” means any calendar month during which a Unit fires Fossil

Fuel.

48. “Over Fire Air” or “OFA” mean an in-furnace staged combustion control to

reduce NOx emissions.

49. “Parties” means the United States of America on behalf of EPA, the State of

Minnesota on behalf of MPCA, and Minnesota Power.

50. “Party” means one of the named Parties.

51. “Particulate Matter” or “PM,” except as used in Paragraph 129 herein, means total

filterable particulate matter, measured in accordance with the provisions of this Consent Decree.

52. “Particulate Matter Continuous Emission Monitoring System” or “PM CEMS”

means, for obligations involving the monitoring of PM emissions under this Consent Decree, the

continuous emissions monitoring systems installed, operated and maintained as described in 40

C.F.R. § 60.49Da(v).

53. “Particulate Matter Control Device” or “PM Control Device” means any device

including a Baghouse, ESP, or Wet Particulate Scrubber which reduces emissions of PM.

54. “PM Emission Rate” means the number of pounds of PM emitted per million

BTU of heat input (lb/mmBTU).


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55. “Prevention of Significant Deterioration” or “PSD” means the new source review

program within the meaning of Part C of Title I of the Clean Air Act, 42 U.S.C. §§ 7470-7492

and 40 C.F.R. Part 52, and Minn. R., Chapter 7007 (Permits and Offsets).

56. “Project Dollars” means Minnesota Power’s expenditures and payments incurred

or made in carrying out the Environmental Mitigation Projects identified in Section IX and

Appendix A of this Consent Decree to the extent that such expenditures or payments both: (a)

comply with the requirements set forth in Section IX and Appendix A of this Consent Decree,

and (b) constitute Minnesota Power’s direct payments for such projects, or Minnesota Power’s

external costs for contractors, vendors, and equipment.

57. “Rapids” or “REC” means, for purposes of this Consent Decree, the two solid

fuel-fired cogeneration units at Minnesota Power’s Rapids Energy Center designated by

Minnesota Power as Rapids Unit 5 (approximately 175,000 pounds of steam per hour and

approximately 13 net MW of electricity) and Rapids Unit 6 (approximately 175,000 pounds of

steam per hour and approximately 16 net MW of electricity) and currently co-located with UPM

(United Paper Mill) Blandin paper mill in Grand Rapids, Minnesota. Rapids Unit 5 and Rapids

Unit 6 share a common stack, but have separate SO2 and NOx CEMS installed prior to the

common stack.

58. “Refuel” or “Refueled” means the alteration of a Unit such that the altered Unit

can no longer combust any fuel (such as coal, petroleum coke, petroleum oil, fuel oil) except

Natural Gas, and/or herbaceous crops, trees, agricultural waste, logging or silvicultural waste,

untreated wood residue or products, aquatic plant matter or other non-Fossil Fuel approved by

EPA and MPCA.

59. “Repower” or “Repowered” means, solely for purposes of this Consent Decree,


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replacement of the Unit components such that the Unit is solely able to generate electricity

through the use of a combined cycle combustion turbine technology from the combustion of

Natural Gas rather than coal or another Fossil Fuel (such as coal, petroleum coke, petroleum oil,

fuel oil).

60. “Reroute” means to reroute the flue gas from Boswell Unit 1 and Boswell Unit 2

through an FGD device that treats the flue gas from such Units and Boswell Unit 3.

61. “Retire” means to permanently shut down a Unit and to comply with applicable

state and federal requirements for permanently ceasing operation of the Unit, including

submitting a request to MPCA to amend the state’s air emission inventory to reflect shutdown,

and withdrawing and/or requesting amendment of all applicable permits so as to reflect the

permanent shutdown status of such Unit.

62. “Rotating Opposed Fire Air” system or “ROFA©” system by Nalco Mobotec

means a process by which air is injected into the furnace via rotating, asymmetrically placed air

nozzles designed to generate turbulence and reduce NOx.

63. “SEC” means the United States Securities and Exchange Commission.

64. “SCR” or “Selective Catalytic Reduction” means an air pollution control device

for reducing NOx emissions in which ammonia (NH3) is added to the flue gas and then passed

through layers of a catalyst material. The ammonia and NOx in the flue gas stream react on the

surface of the catalyst, forming nitrogen (N2) and water vapor.

65. “SNCR” or “Selective Non-Catalytic Reduction” means an air pollution control

process for the reduction of NOx emissions through the injection of ammonia or urea into the

boiler.

66. “SO2 Allowance” means an authorization to emit a specified amount of SO2 that


15

is allocated or issued under an emissions trading or marketable permit program of any kind

established under the Clean Air Act or applicable State Implementation Plan; provided, however,

that with respect to any such program that first applies to emissions occurring after December 31,

2011, an “SO2 Allowance” shall include a SO2 Allowance created and allocated to a Minnesota

Power System Unit under such program only for control periods starting on or after the fourth

anniversary of the Date of Entry of this Consent Decree.

67. “State” or “State of Minnesota” means the State of Minnesota by its Minnesota

Pollution Control Agency (“MPCA”).

68. “Sulfur dioxide” or “SO2” means oxides of sulfur measured in accordance with

the provisions of this Consent Decree.

69. “Super-Compliant Allowance” means a NOx Allowance or SO2 Allowance

attributable to reductions beyond the requirements of this Consent Decree, as described in

Paragraphs 96 and 117.

70. “Surrender” or “Surrender of Allowances” means, for purposes of SO2

Allowances or NOx Allowances, permanently surrendering SO2 Allowances or NOx Allowances

from the accounts administered by EPA and MPCA for all Units in the Minnesota Power

System, so that such SO2 Allowances or NOx Allowances can never be used thereafter to meet

any compliance requirements under the Clean Air Act, or this Consent Decree.

71. “System-Wide Annual Tonnage Limitation” means the limitation, as specified in

this Consent Decree, on the number of tons of pollutant (SO2 or NOx) that may be emitted from

the Boswell, Taconite Harbor, Laskin, and Rapids Energy Centers during the relevant calendar

year (i.e., January 1 through December 31), and shall include all emissions of the specified

pollutant that occur during all periods of operation, including startup, shutdown, and


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Malfunction.

72. “Taconite Harbor” means, for purposes of this Consent Decree, Minnesota

Power’s Taconite Harbor Energy Center consisting of three coal-fired units designated by

Minnesota Power (as reported to the SEC by Minnesota Power) as Taconite Harbor Unit 1 (79

net MW), Taconite Harbor Unit 2 (76 net MW), and Taconite Harbor Unit 3 (84 net MW) and

located in Schroeder, Minnesota. Each of the Taconite Harbor Units have separate stacks and

monitor each pollutant separately.

73. “Title V Permit” means the permit required for Defendant’s major sources

pursuant to Title V of the Act, 42 U.S.C. §§ 7661-7661e.

74. “Unit” means collectively, the coal pulverizer, stationary equipment that feeds

coal to the boiler, the boiler that produces steam for the steam turbine, the steam turbine, the

generator, the equipment necessary to operate the generator, steam turbine, and boiler, and all

ancillary equipment, including pollution control equipment and systems necessary for production

of electricity. Each of Minnesota Power’s energy centers may comprise one or more Units.

75. “Wet Particulate Scrubber” means a control device for removal of particulate

matter that relies on direct and irreversible contact of a liquid (droplets, foam, or bubbles) with

the particulates in the flue gas to collect and remove the pollutants from the flue gas stream.

76. “Wet Venturi Scrubber” is a type of Wet Particulate Scrubber that uses a gas-

atomized spray to atomize the scrubbing liquid and improve gas-liquid contact for removal of

PM.


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IV. NOx EMISSION REDUCTIONS AND CONTROLS

A. Boswell Units 1 and 2 NOx Emission Limits and Controls

77. Commencing upon the Date of Entry of the Consent Decree and continuing

thereafter, Minnesota Power shall optimize combustion and Continuously Operate the ROFA and

SNCR control devices at Boswell Units 1 and 2 such that Boswell Unit 1 and Boswell Unit 2

each achieves and maintains a 30-Day Rolling Average Emission Rate for NOx no greater than

0.250 lb/mmBTU.

78. By no later than June 30, 2014, and continuing thereafter, Minnesota Power shall

optimize combustion and Continuously Operate the ROFA and SNCR control devices at Boswell

Units 1 and 2 such that Boswell Unit 1 and Boswell Unit 2 each achieves and maintains a 30-

Day Rolling Average Emission Rate for NOx no greater than 0.200 lb/mmBTU. If Minnesota

Power chooses to Reroute Boswell Units 1 and 2 through an FGD device that treats the flue gas

from such Units and Boswell Unit 3, Minnesota Power shall continue to Continuously Operate

the ROFA and SNCR control devices at such Units and maintain a 30-Day Rolling Average

Emission Rate for NOx no greater than 0.200 lb/mmBTU at each Unit as measured before flue

gases from Boswell Units 1 and 2 combine with the flue gases from Boswell Unit 3.

79. If Minnesota Power chooses to Reroute the flue gas from Boswell Units 1 and 2

and Minnesota Power demonstrates to the reasonable satisfaction of EPA and the MPCA that it

is practically infeasible to obtain a representative measurement of NOx emissions for Boswell

Units 1 and/or 2 consistent with 40 C.F.R. Part 60, Appendix A, Method 1 and 40 C.F.R. Part 75,

Appendix A before the flue gases from Boswell Units 1 and 2 combine with the flue gases from

Boswell Unit 3, then Minnesota Power shall continue to Continuously Operate the ROFA and

SNCR control devices at such Units, and shall demonstrate that it is in compliance with the 30-


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Day Rolling Average Emission Rate for NOx for Boswell Units 1 and 2 by showing that the

combined 30-Day Rolling Average Emission Rate for NOx for Boswell Unit 1, Boswell Unit 2,

and Boswell Unit 3 is no greater than the Heat-Input Weighted Average Emission Rate.

B. Boswell Unit 3 NOx Emission Limits and Controls


thereafter, Minnesota Power shall Continuously Operate the Low NOx Burners, OFA system and

SCR control device at Boswell Unit 3 such that the Unit achieves and maintains a 30-Day

Rolling Average Emission Rate for NOx no greater than 0.060 lb/mmBTU. An SCR control

device is still required if Minnesota Power elects to Refuel or Repower Boswell Unit 3 and

replaces the boiler. If Minnesota Power chooses to Reroute the flue gas from Boswell Units 1

and 2, Minnesota Power shall continue to Continuously Operate the Low NOx Burners, OFA

system and SCR control device at Boswell Unit 3 such that the Unit achieves and maintains a 30-

Day Rolling Average Emission Rate for NOx no greater than 0.060 lb/mmBTU as measured

before flue gases from Boswell Units 1 and 2 combine with the flue gases from Boswell Unit 3.

81. If Minnesota Power chooses to Reroute the flue gas from Boswell Units 1 and 2

and Minnesota Power demonstrates to the reasonable satisfaction of EPA and the MPCA that it

is practically infeasible to obtain a representative measurement of NOx emissions for Boswell

Units 3 consistent with 40 C.F.R. Part 60, Appendix A, Method 1 and 40 C.F.R. Part 75,

Appendix A before the flue gases from Boswell Units 1 and 2 combine with the flue gases from

Boswell Unit 3, then Minnesota Power shall continue to Continuously Operate the Low NOx

Burners, OFA system, and SCR control device at Boswell Unit 3, and shall demonstrate that it is

in compliance with the 30-Day Rolling Average Emission Rate for NOx for Boswell Units 1 and

2 by showing that the combined 30-Day Rolling Average Emission Rate for NOx for Boswell


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Unit 1, Boswell Unit 2, and Boswell Unit 3 is no greater than the Heat-Input Weighted Average

Emission Rate.

C. Boswell Unit 4 NOx Emission Limits and Controls


thereafter, Minnesota Power shall Continuously Operate the Low NOx Burners, OFA system and

SNCR control device at Boswell Unit 4 such that this Unit achieves and maintains a 30-Day

Rolling Average Emission Rate for NOx no greater than 0.120 lb/mmBTU.

D. Laskin Units 1 and 2 NOx Emission Limits and Controls

83. Commencing upon the Date of Entry of the Consent Decree and continuing until

the Units are Retired, Refueled, or Repowered, Minnesota Power shall Continuously Operate

Low NOx Burners and OFA systems at each of Laskin Units 1 and 2, such that the Units shall

achieve and maintain a combined 30-Day Rolling Average Emission Rate for NOx no greater

than 0.190 lb/mmBTU.

E. Taconite Harbor Units 1 and 2 NOx Emission Limits and Controls


thereafter, Minnesota Power shall Continuously Operate the ROFA systems and SNCR control

devices at Taconite Harbor Units 1 and 2 such that Taconite Harbor Unit 1 and Taconite Harbor

Unit 2 each achieves and maintains a 30-Day Rolling Average Emission Rate for NOx no greater

than 0.160 lb/mmBTU.

F. Taconite Harbor Unit 3 NOx Emission Limits and Controls

85. By no later than December 31, 2015, Minnesota Power shall Retire, Refuel or

Repower Taconite Harbor Unit 3.


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G. Rapids Units 5 and 6 NOx Emission Limits and Controls


thereafter, Minnesota Power shall operate Rapids Units 5 and 6 such that each unit achieves and

maintains a 12-Month Rolling Average Emission Rate for NOx of no greater than 0.370

lb/mmBTU.

H. System-Wide Annual Tonnage Limitations for NOx

87. In calendar year 2014 and in each calendar year thereafter, Minnesota Power shall

not exceed the following System-Wide Annual Tonnage Limitations for NOx emissions:

Year System-wide Calendar Year Tonnage Cap (tpy)

2014 8,400

2015 7,500

2016-Forward 6,700

I. Monitoring of NOx Emissions

88. In determining a 30-Day Rolling Average Emission Rate for NOx, Minnesota

Power shall use a Continuous Emissions Monitoring System (“CEMS”) in accordance with the

procedures of 40 C.F.R. Part 75 and 40 C.F.R. Part 60, Appendix F, Procedure 1, except that

NOx emissions data for the 30-Day Rolling Average Emission Rate for NOx need not be bias

adjusted and the missing data substitution procedures of 40 C.F.R. Part 75 shall not apply.

89. In determining a 12-Month Rolling Average Emission Rate for NOx, for Rapids,

Minnesota Power shall use CEMS in accordance with the procedures at 40 C.F.R. Part 60 and

Minn. R. 7017.1002 - .1170.


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90. For purposes of determining compliance with the System-Wide Annual Tonnage

Limitation for NOx, Minnesota Power shall use CEMS in accordance with the procedures at 40

C.F.R. Part 75, or, for purposes of Rapids, in accordance with 40 C.F.R. Part 60.

J. Use and Surrender of NOx Allowances

91. Except as may be necessary to comply with Section XIV (Stipulated Penalties),

Minnesota Power shall not use NOx Allowances to comply with any requirement of this Consent

Decree, including by claiming compliance with any emission limitation required by this Consent

Decree by using, tendering, or otherwise applying NOx Allowances to offset any excess

emissions (i.e., emissions above the limits set forth in this Consent Decree).

92. Except as provided in this Consent Decree, beginning in calendar year 2014 and

continuing each calendar year thereafter, Minnesota Power shall not sell, bank, trade, or transfer

any NOx Allowances allocated to the Minnesota Power System for that calendar year.

93. Beginning in calendar year 2014 and continuing each calendar year thereafter,

Minnesota Power shall Surrender all NOx Allowances allocated to Units within the Minnesota

Power System for that calendar year (other than those NOx Allowances that Minnesota Power

needs to meet federal and/or state Clean Air Act regulatory requirements for the Minnesota

Power System Units).

94. Nothing in this Consent Decree shall prevent Minnesota Power from purchasing

or otherwise obtaining NOx Allowances from another source to the extent otherwise allowed by

law.

95. The requirements of this Consent Decree pertaining to Minnesota Power’s use

and Surrender of NOx Allowances are permanent injunctions not subject to any termination

provision of this Consent Decree.


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K. Super-Compliant NOx Allowances

96. Notwithstanding Paragraphs 92 and 93, in each calendar year beginning in 2014,

and continuing thereafter, Minnesota Power may sell, bank, use, trade, or transfer NOx

Allowances made available in each calendar year solely as a result of:

a. the installation and operation of any NOx pollution control equipment that is not

otherwise required by, or necessary to maintain compliance with, any provision of

this Consent Decree, and is not otherwise required by law; or

b. achievement and maintenance of an Emission Rate below the Calendar Year

Average Emission Rate for NOx equal to the lesser of (i) ninety percent of an

applicable 30-Day Rolling Average Emission Rate for NOx, or (ii) an applicable

12-Month Rolling Average Emission Rate for NOx, provided that Minnesota

Power is also in compliance for that calendar year with all emission limitations

for NOx set forth in this Consent Decree.

Minnesota Power shall timely report the generation of such Super-Compliant NOx Allowances in

accordance with Section XII (Periodic Reporting) of this Consent Decree.

L. Method for Surrender of NOx Allowances

97. Minnesota Power shall Surrender all NOx Allowances required to be Surrendered

pursuant to Paragraph 93 by April 30 of the immediately following calendar year.

98. For all NOx Allowances required to be Surrendered, Minnesota Power shall first

submit a NOx Allowance transfer request to EPA’s Office of Air and Radiation’s Clean Air

Markets Division directing the transfer of such NOx Allowances to the EPA Enforcement

Surrender Account or to any other EPA account that EPA may direct in writing. Such NOx

Allowance transfer requests may be made in an electronic manner using the EPA’s Clean Air


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Markets Division Business System or similar system provided by EPA. As part of submitting

these transfer requests, Minnesota Power shall irrevocably authorize the transfer of these NOx

Allowances and identify, by name of account and any applicable serial or other identification

numbers or station names, the source and location of the NOx Allowances being Surrendered.

V. SO2 EMISSION REDUCTIONS AND CONTROLS

A. Boswell Units 1 and 2 SO2 Emission Limits and Controls


thereafter, Minnesota Power shall operate Boswell Unit 1 and Boswell Unit 2 such that each Unit

achieves and maintains a 30-Day Rolling Average Emission Rate for SO2 no greater than 0.700

lb/mmBTU.

100. By no later than December 31, 2018, Minnesota Power shall Retire, Refuel,

Repower, or Reroute Boswell Unit 1 and Boswell Unit 2. If Minnesota Power chooses to

Reroute the flue gas from Boswell Units 1 and 2, Minnesota Power shall Continuously Operate

an FGD device such that Boswell Units 1, 2, and 3 achieve and maintain a combined 30-Day

Rolling Average Emission Rate for SO2 no greater than 0.030 lb/mmBTU.

B. Boswell Unit 3 SO2 Emission Limits and Controls


thereafter, Minnesota Power shall Continuously Operate an FGD device at Boswell Unit 3 such

that the Unit achieves and maintains a 30-Day Rolling Average Emission Rate for SO2 no greater

than 0.030 lb/mmBTU. If Minnesota Power chooses to Reroute the flue gas from Boswell Units

1 and 2, then Boswell Units 1, 2, and 3 shall achieve and maintain a combined 30-Day Rolling

Average Emission Rate for SO2 no greater than 0.030 lb/mmBTU.


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C. Boswell Unit 4 SO2 Emission Limits and Controls


installation and continuous operation of the new FGD device, Minnesota Power shall

Continuously Operate the existing FGD device at Boswell Unit 4 such that the Unit achieves and

maintains both (a) a 30-Day Rolling Average Emission Rate for SO2 no greater than 0.100

lb/mmBTU; and (b) a 12-Month Rolling Average Emission Rate for SO2 no greater than 0.070

lb/mmBTU. No later than May 31, 2016, Minnesota Power shall Continuously Operate a new

FGD device at Boswell Unit 4 such that the Unit achieves and maintains a 30-Day Rolling

Average Emission Rate for SO2 no greater than 0.030 lb/mmBTU.

D. Laskin Units 1 and 2 SO2 Emission Limits and Controls



Wet Particulate Scrubbers at Laskin Units 1 and 2 such that the Units achieve and maintain a

combined 30-Day Rolling Average Emission Rate for SO2 no greater than 0.200 lb/mmBTU.

E. Taconite Harbor Unit 1 SO2 Emission Limits and Controls


thereafter, Minnesota Power shall Continuously Operate an FSI system at Taconite Harbor Unit

1 so that the Unit achieves and maintains a 30-Day Rolling Average Emission Rate for SO2 no

greater than 0.550 lb/mmBTU. By no later than December 31, 2015, Minnesota Power shall

Continuously Operate a DSI and/or an FSI system at Taconite Harbor Unit 1 such that the Unit


lb/mmBTU.


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F. Taconite Harbor Unit 2 SO2 Emission Limits and Controls


thereafter, Minnesota Power shall Continuously Operate an FSI system at Taconite Harbor Unit

2 so that the Unit achieves and maintains a 30-Day Rolling Average Emission Rate for SO2 no

greater than 0.450 lb/mmBTU. By no later than December 31, 2015, Minnesota Power shall

Continuously Operate a DSI and/or an FSI system at Taconite Harbor Unit 2 such that the Unit


lb/mmBTU.

G. Taconite Harbor Unit 3 SO2 Emission Limits and Controls


the Unit is Retired, Refueled, or Repowered, Minnesota Power shall operate Taconite Harbor

Unit 3 such that the Unit achieves and maintains a 30-Day Rolling Average Emission Rate for

SO2 no greater than 0.700 lb/mmBTU. By no later than December 31, 2015, Minnesota Power

shall Retire, Refuel, or Repower Taconite Harbor Unit 3.

H. Rapids Units 5 and 6 SO2 Emission Limits and Controls


thereafter, Minnesota Power shall operate Rapids Units 5 and 6 such that each unit achieves and

maintains a 12-Month Rolling Average Emission Rate for SO2 of no greater than 0.150

lb/mmBTU.

I. System-Wide Annual Tonnage Limitations for SO2

108. In calendar year 2014 and in each calendar year thereafter, Minnesota Power shall

not exceed the following System-Wide Annual Tonnage Limitations of SO2 emissions:


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Year System-wide Calendar Year Tonnage Cap (tpy)

2014 11,500

2015 11,000

2016 7,400

2017-2018 7,000

2019-forward 3,000

J. Monitoring of SO2 Emissions

109. In determining a 30-Day Rolling Average Emission Rate for SO2, Minnesota

Power shall use a Continuous Emissions Monitoring System (CEMS) in accordance with the

procedures of 40 C.F.R. Part 75 and 40 C.F.R. Part 60, Appendix F, Procedure 1, except that SO2

emissions data for the 30-Day Rolling Average Emission Rate for SO2 need not be bias adjusted

and the missing data substitution procedures of 40 C.F.R. Part 75 shall not apply.

110. In determining a 12-Month Rolling Average Emission Rate for SO2, Minnesota

Power shall use a CEMS in accordance with the procedures specified in 40 C.F.R. Part 75 (or,

for purposes of Rapids, 40 C.F.R. Part 60) and Minn. R. 7017.1002 - .1170.

111. For purposes of determining compliance with the System-Wide Annual Tonnage

Limitation for SO2, Minnesota Power shall use a CEMS in accordance with the procedures

specified in 40 C.F.R. Part 75, or, for purposes of Rapids, in accordance with 40 C.F.R. Part 60.

K. Use and Surrender of SO2 Allowances

112. Except as may be necessary to comply with Section XIV (Stipulated Penalties),

Minnesota Power shall not use SO2 Allowances to comply with any requirement of this Consent

Decree, including by claiming compliance with any emission limitation required by this Consent


27

Decree by using, tendering, or otherwise applying SO2 Allowances to offset any excess

emissions.

113. Except as provided in this Consent Decree, beginning in calendar year 2014 and

continuing each calendar year thereafter, Minnesota Power shall not sell, bank, trade, or transfer

any SO2 Allowances allocated to the Minnesota Power System for that calendar year.

114. Beginning in calendar year 2014 and continuing each calendar year thereafter,

Minnesota Power shall Surrender all SO2 Allowances allocated to Units within the Minnesota

Power System for that calendar year (other than those SO2 Allowances needed to meet federal

and/or state Clean Air Act regulatory requirements for the Minnesota Power System Units).

115. Nothing in this Consent Decree shall prevent Minnesota Power from purchasing

or otherwise obtaining SO2 Allowances from another source to the extent otherwise allowed by

law.

116. The requirements of this Consent Decree pertaining to Minnesota Power’s use

and Surrender of SO2 Allowances are permanent injunctions not subject to any termination

provision of this Consent Decree.

L. Super-Compliant SO2 Allowances

117. Notwithstanding Paragraphs 113 and 114, in each calendar year beginning in

2014, and continuing thereafter, Minnesota Power may sell, bank, use, trade, or transfer SO2

Allowances made available in that calendar year solely as a result of:

a. the installation and operation of any SO2 pollution control that is not otherwise

required by, or necessary to maintain compliance with, any provision of this

Consent Decree, and is not otherwise required by law, or the installation and

operation of SO2 controls prior to the dates required under this Section V of this


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Consent Decree or otherwise required by law; or

b. achievement and maintenance of an SO2 Emission Rate below the Calendar Year

Average Emission Rate for SO2 equal to the lesser of (i) ninety percent of an

applicable 30-Day Rolling Average Emission Rate for SO2, or (ii) an applicable

12-Month Rolling Average Emission Rate for SO2, provided that Minnesota

Power is also in compliance for that calendar year with all emission limitations

for SO2 set forth in this Consent Decree.

Minnesota Power shall timely report the generation of such Super-Compliant SO2 Allowances to

EPA and MPCA in accordance with Section XII (Periodic Reporting) of this Consent Decree.

M. Method for Surrender of SO2 Allowances

118. Minnesota Power shall Surrender all SO2 Allowances required to be Surrendered

pursuant to Paragraph 114 by April 30 of the immediately following calendar year.

119. For all SO2 Allowances required to be Surrendered, Minnesota Power shall first

submit an SO2 Allowance transfer request to EPA’s Office of Air and Radiation’s Clean Air

Markets Division directing the transfer of such SO2 Allowances to the EPA Enforcement

Surrender Account or to any other EPA account that EPA may direct in writing. Such SO2

Allowance transfer requests may be made in an electronic manner using the EPA’s Clean Air

Markets Division Business System or similar system provided by EPA. As part of submitting

these transfer requests, Minnesota Power shall irrevocably authorize the transfer of these SO2

Allowances and identify, by name of account and any applicable serial or other identification

numbers or station names, the source and location of the SO2 Allowances being Surrendered.


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VI. PM EMISSION REDUCTIONS AND CONTROLS

A. Optimization of Baghouses and Electrostatic Precipitators

120. By no later than 90 Days after the Date of Entry of this Consent Decree, and

continuing thereafter, Minnesota shall Continuously Operate each existing PM Control Device

on each Unit in the Minnesota Power System (except the ESP for Boswell Unit 4) to maximize

PM emission reductions at all times when each Unit is in operation. By no later than 90 Days

after the Date of Entry of this Consent Decree, and continuing until the Baghouse is in operation

at Boswell Unit 4 pursuant to Paragraph 123, Minnesota Power shall operate the ESP on the

Boswell Unit 4 bypass when the Unit is in operation and venting emissions to the bypass duct.

Except as required during correlation testing under 40 C.F.R. Part 60, Appendix B, Performance

Specification 11, and Quality Assurance Requirements under Appendix F, Procedure 2, as

required by this Consent Decree, Minnesota Power shall, at a minimum, ensure that to the extent

practicable: (a) each section of each ESP (except the ESP for Boswell Unit 4) at such Unit is

fully energized and each compartment of each Baghouse at such Unit remains operational; (b)

the automatic control systems on each Electrostatic Precipitator at such Unit are operated to

maximize PM collection efficiency, where applicable; (c) each opening in the casings, ductwork,

and expansion joints for each ESP and each Baghouse at such Unit is inspected and repaired

during the next planned Unit outage (or unplanned outage of sufficient length) to minimize air

leakage; (d) the power levels delivered to each ESP at such Unit are maintained, where

applicable, consistent with manufacturers’ specifications, the operational design of the Unit, and

good engineering practices; (e) the plate-cleaning and discharge-electrode-cleaning systems for

each ESP at such Unit are optimized, where applicable, by varying the cycle time, cycle

frequency, rapper-vibrator intensity, and number of strikes per cleaning event; and (f) for each


30

such Unit with one or more Baghouses, a bag leak detection program is developed and

implemented to ensure that leaking bags are promptly replaced.

B. Boswell Units 1 and 2 PM Emission Limits and Controls


thereafter, Minnesota Power shall Continuously Operate Baghouses at Boswell Units 1 and 2

such that the Units achieve and maintain a combined PM Emission Rate of no greater than 0.015

lb/mmBTU based on a 3-hour average; provided that if Minnesota Power chooses to Reroute the

flue gas from Boswell 1 and 2, then Boswell Units 1, 2 and 3 shall achieve and maintain a

combined PM Emission Rate of no greater than 0.015 lb/mmBTU based on a 3-hour average.

C. Boswell Unit 3 PM Emission Limits and Controls


thereafter, Minnesota Power shall Continuously Operate a Baghouse at Boswell Unit 3 such that

the Unit achieves and maintains a PM Emission Rate of no greater than 0.015 lb/mmBTU based

on a 3-hour average; provided that if Minnesota Power chooses to Reroute the flue gas from

Boswell Units 1 and 2, then Boswell Units 1, 2 and 3 shall achieve and maintain a combined PM

Emission Rate of no greater than 0.015 lb/mmBTU based on a 3-hour average.

D. Boswell Unit 4 PM Emission Limits and Controls


thereafter, Minnesota Power shall Continuously Operate the Wet Venturi Scrubber, and ESP

whenever venting emissions to the bypass duct, at Boswell Unit 4 such that the Unit achieves

and maintains a PM Emission Rate of no greater than 0.060 lb/mmBTU based on a 3-hour

average. Commencing on May 31, 2016 and continuing thereafter, Minnesota Power shall

Continuously Operate a Baghouse at Boswell Unit 4 such that this Unit achieves and maintains a


31

PM Emission Rate of no greater than 0.015 lb/mmBTU based on a 3-hour average.

E. Laskin Units 1 and 2 PM Emission Limits and Controls



Wet Particulate Scrubbers at Laskin Units 1 and 2 such that the Units achieve and maintain a

combined PM Emission Rate of no greater than 0.050 lb/mmBTU based on a 3-hour average.

F. Taconite Harbor Units 1, 2, and 3 PM Emission Limits and Controls


thereafter (or, as to Taconite Harbor Unit 3, until such Unit is Retired, Refueled, or Repowered),

Minnesota Power shall Continuously Operate ESP devices at Taconite Harbor Units 1, 2, and 3

such that each Unit achieves and maintains a PM Emission Rate of no greater than 0.030

lb/mmBTU based on 3-hour average.

G. Rapids Units 5 and 6 PM Emission Limits and Controls


thereafter, Minnesota Power shall Continuously Operate ESP devices at Rapids Units 5 and 6

such that the Units achieve and maintain a combined PM Emission Rate of no greater than 0.030

lb/mmBTU based on a 3-hour average.

H. Stack Tests to Monitor PM Emissions

127. Commencing in calendar year 2014 and continuing thereafter, Minnesota Power

shall conduct stack tests each year on each Unit or Units served by a common stack in the

Minnesota Power System to determine compliance with the PM Emission Rates established by

this Consent Decree, unless the Unit to be tested is Retired, Refueled, or Repowered by June 30

of the same calendar year. Following the installation and operation of PM Continuous Emissions


32

Monitoring Systems (“CEMS”) as required by Section VI.I of this Consent Decree, Minnesota

Power may seek EPA's approval pursuant to Section XIII (Review and Approval of Submittals)

of this Consent Decree to forego filterable PM stack testing and instead demonstrate compliance

with an applicable filterable PM Emission Rate using CEMS on a 3-Hour Rolling Average

Emission Rate basis.

128. To determine compliance with the filterable PM Emission Rate established in

Paragraphs 121 through 126, Minnesota Power shall use EPA Method 5 (filterable portion only)

or a PM stack testing method specified in and allowed by applicable Minnesota SIP provision(s)

unless EPA approves a request to demonstrate continuous compliance with a filterable PM

Emission Rate using PM CEMS under the preceding Paragraph 127. Each test shall consist of

three separate runs performed under representative operating conditions not including periods of

startup, shutdown, or Malfunction. The sampling time for each run shall be at least 60 minutes

and the volume of each run shall be at least 0.85 dry standard cubic meters (30 dry standard

cubic feet). Minnesota Power shall calculate the PM Emission Rate from the stack test results in

accordance with 40 C.F.R. § 60.8(f). The results of each PM stack test shall be submitted to

EPA and MPCA within 60 Days following completion of such test.

129. Commencing in calendar year 2014, and continuing annually thereafter,

Minnesota Power shall also conduct a PM stack test for condensable PM on each Unit or Units

served by a common stack in the Minnesota Power System using the reference methods and

procedures set forth at 40 C.F.R. Part 51, Appendix M, Method 202, unless the Unit is Retired,

Refueled, or Repowered by June 30 of the same calendar year. Each test shall consist of three

separate runs performed under representative operating conditions not including periods of

startup, shutdown, or Malfunction. The sampling time for each run shall be at least 60 minutes


33

and the volume of each run shall be at least 0.85 dry standard cubic meters (30 dry standard

cubic feet). Minnesota Power shall calculate the number of pounds of condensable PM emitted

per million BTU of heat input (lb/mmBTU) from the stack test results in accordance with 40

C.F.R. § 60.8(f). The results of the PM stack test conducted pursuant to this Paragraph shall not

be used for the purpose of determining compliance with the PM Emission Rates required by this

Consent Decree. The results of each PM stack test shall be submitted to EPA and MPCA within

60 Days following completion of such test.

130. The annual performance test requirement imposed on Minnesota Power by

Section VI.H of this Consent Decree may be satisfied by stack tests conducted by Minnesota

Power as may be required by its permits from the State of Minnesota for any year that such stack

tests are required under the permits. Minnesota Power may perform testing every other year,

rather than every year, provided that the two most recently completed test results conducted in

accordance with the methods and procedures specified in this Consent Decree demonstrate that

the PM emissions are equal to or less than 0.015 lb/mmBTU for those Units with an Electrostatic

Precipitator and 0.0075 lb/mmBTU for those Units with a Baghouse. Minnesota Power shall

perform testing every year, rather than every other year, beginning in the year immediately

following any test result demonstrating that the PM emissions are greater than 0.015 lb/mmBTU

for those Units with an Electrostatic Precipitator or 0.0075 lb/mmBTU for those Units with a

Baghouse.

131. When Minnesota Power submits the application for amendment to its Title V

Permit pursuant to Paragraph 209, that application shall include a Compliance Assurance

Monitoring (“CAM”) plan, under 40 C.F.R. Part 64, for the PM Emission Rate in Paragraphs 121

through 125. The PM CEMS required under Paragraph 132 may be used in that CAM plan.


34

I. PM CEMS

132. Minnesota Power shall install, correlate, maintain, and operate PM CEMS on the

stack serving Boswell Units 1, 2 and 3 and on the stack serving Boswell Unit 4 as specified

below. The PM CEMS shall comprise a continuous particle mass monitor measuring filterable

particulate matter concentration, directly or indirectly, on an hourly average basis and a diluent

monitor or monitors used to convert the concentration to units expressed in lb/mmBTU. The PM

CEMS installed at each stack must be appropriate for the anticipated stack conditions and

capable of measuring PM concentrations on an hourly average basis. Minnesota Power shall

maintain, in an electronic database, the hourly average emission values of all PM CEMS in

lb/mmBTU. Except for periods of monitor Malfunction, maintenance, or repair, Minnesota

Power shall operate the PM CEMS at all times when any Unit it serves is operating, including

during Unit startup, shutdown, and Malfunction.

133. By no later than September 30, 2014 for the PM CEMS for the stack serving

Boswell Units 1, 2, and 3 and by no later than September 30, 2015 for the stack serving Boswell

Unit 4, Minnesota Power shall submit to EPA and MPCA for EPA’s review and approval after

consultation with MPCA pursuant to Section XIII (Review and Approval of Submittals) of this

Consent Decree a plan for the installation and correlation of the PM CEMS required by

Paragraph 132.

134. By no later than December 31, 2014 for the PM CEMS for the stack serving

Boswell Units 1, 2, and 3 and by no later than December 31, 2015 for the stack serving Boswell

Unit 4, Minnesota Power shall submit to EPA and MPCA for EPA’s review and approval after

consultation with MPCA pursuant to Section XIII (Review and Approval of Submittals) of this

Consent Decree a proposed Quality Assurance/Quality Control (“QA/QC”) protocol that shall be


35

followed for such PM CEMS. The proposed QA/QC protocol may include a process for

streamlined revisions to stay current with regulatory changes (e.g., EPA Performance Standard

PS 11) and PM CEMS vendor recommendations.

135. In developing both the plan for installation and correlation of the PM CEMS and

the QA/QC protocol, Minnesota Power shall use the criteria set forth in 40 C.F.R. Part 60,

Appendix B, Performance Specification 11, and Appendix F, Procedure 2, or equivalent criteria

specified in and allowed by applicable Minnesota SIP provision(s). For each Boswell Unit at

which Minnesota Power chooses to install, certify, operate, and maintain a PM CEMS under 40

C.F.R. § 63.10010(i) (the Utility MATS Rule), Minnesota Power may, pursuant to 40 C.F.R. §

63.7, seek approval to use Method 5 (at the temperature specified in 40 C.F.R. Part 60, Appendix

A-3) for correlation of its CEMS in order to comply with the Utility MATS Rule. If Minnesota

Power makes such a request, and EPA’s air program office disapproves it or requires the use or

submittal of a Method 301 validation (at 40 C.F.R. Part 63, Appendix A), then Minnesota Power

may use the correlation method specified in 40 C.F.R. § 63.10010(i) for purposes of correlating

the PM CEMS under this Consent Decree. If EPA, after consultation with MPCA, approves the

plan described in Paragraph 133 and the QA/QC protocol described in Paragraph 134, Minnesota

Power shall thereafter operate the PM CEMS in accordance with the approved plan and QA/QC

protocol.

136. By no later than June 30, 2015 for the PM CEMS for the stack serving Boswell

Units 1, 2, and 3 and by no later than June 30, 2016 for the PM CEMS for the stack serving

Boswell Unit 4, Minnesota Power shall install, correlate (and, for the stack serving Boswell

Units 1, 2, and 3, if Minnesota Power chooses Reroute, re-correlate), maintain, and operate each

PM CEMS, conduct performance specification tests on the PM CEMS, and demonstrate


36

compliance with the plan and protocol submitted to and approved by EPA in accordance with

Paragraphs 133 and 134. Minnesota Power shall report, pursuant to Section XII (Periodic

Reporting), the 3-Hour Rolling Average Emission Rate data recorded by the PM CEMS, in

electronic format (Microsoft Excel compatible) to EPA.

137. Stack testing shall be used to determine compliance with the PM Emission Rates

established by this Consent Decree, unless EPA approves after consultation with MPCA a

request under Paragraph 127, in which case PM CEMS shall be used to demonstrate compliance

with an applicable PM Emission Rate on a 3-Hour Rolling Average Emission Rate basis. Data

from the PM CEMS shall be used, at a minimum, to monitor emissions on a continuous basis.

138. Nothing in this Consent Decree is intended to, or shall, alter or waive any

applicable law (including but not limited to any defenses, entitlements, challenges, or

clarifications related to the Credible Evidence Rule, 62 Fed. Reg. 8314 (Feb. 24, 1997))

concerning the use of data for any purpose under the Act.

VII. RETIRE, REFUEL, REPOWER, OR REROUTE OPTION AND FUELS AND RENEWABLE ENERGY

139. Minnesota Power shall provide EPA and MPCA with written notification as per

Section XIX of this Consent Decree by no later than December 31, 2014 regarding whether

Taconite Harbor Unit 3 and Laskin Units 1 and 2 will be Retired, Refueled, or Repowered. By

no later than December 31, 2015, Minnesota Power shall Retire, Refuel, or Repower Taconite

Harbor Energy Center Unit 3 and Laskin Energy Center Units 1 and 2. If Minnesota Power elects

to Refuel a Laskin Unit or Taconite Harbor Unit 3 to Natural Gas pursuant to this Paragraph,

such election shall not prohibit Minnesota Power from adding herbaceous crops, trees,

agricultural waste, logging or silvicultural waste, untreated wood residue or products, aquatic


37

plant matter or other non-Fossil Fuel approved by EPA and MPCA as fuel(s) after such

Refueling, provided that Minnesota Power applies for, and obtains, all required permits,

including, if applicable, all appropriate permits pursuant to CAA Title I, Parts C and D.

140. Minnesota Power shall provide EPA and MPCA with written notification as per

Section XIX of this Consent Decree by no later than December 31, 2016 whether it will Retire,

Refuel, Repower, or Reroute Boswell Unit 1 and/or 2. By no later than December 31, 2018,

Minnesota Power shall Retire, Refuel, Repower, or Reroute Boswell Units 1 and/or 2. For each

Unit, if Retire, Refuel, or Repower is elected, Minnesota Power shall not be required to Reroute

the flue gas of such Unit as required by Paragraph 100.

141. If a Unit is Refueled, Repowered, or Rerouted, Minnesota Power must obtain any

and all required CAA permit(s) for the Refueled, Repowered, or Rerouted Unit, including but not

limited to, if applicable, an appropriate permit pursuant to CAA Title I, Parts C and D. If a

Refueled Unit is permitted to combust herbaceous crops, trees, agricultural waste, logging or

silvicultural waste, untreated wood residue or products, aquatic plant matter or other non-Fossil

Fuel approved by EPA and MPCA, the Refueled Unit shall achieve a PM Emission Rate of 0.015

lb/mmBtu based on a 3-hour average.

142. Nothing herein shall prevent the reuse of any equipment at any other existing Unit

or new emissions unit, provided that Minnesota Power applies for, and obtains, all required

permits, including, if applicable, all appropriate permits pursuant to CAA Title I, Parts C and D.


thereafter, Minnesota Power shall operate Rapids Units 5 and 6 such that each Unit’s 12-Month

Percent Heat Input from Coal will not exceed 40.0 percent during each 12-Operating Month

period. For purposes of calculating the 12-Month Percent Heat Input from Coal, Minnesota


38

Power shall calculate the monthly heat input from each of its fuels by multiplying the monthly

average heat content of each fuel by the total monthly fuel consumption for that respective fuel.

Monthly average heat content will be determined by averaging the results of samples taken

during that month.

144. Minnesota Power shall install and operate at least 200 MW (nameplate rating) of

renewable wind energy in advance of its obligations under the Minnesota Renewable Energy

Standard (RES). The commissioning of Minnesota Power’s Bison 2 and Bison 3 Wind Energy

Centers, with a total capacity of 210 MW, in December 2012 fulfills the requirements of this

Paragraph.

VIII. PROHIBITION ON NETTING CREDITS OR OFFSETS

145. Emission reductions that result from actions to be taken by Minnesota Power after

the Date of Entry of this Consent Decree to comply with the requirements of this Consent Decree

shall not be considered as a creditable contemporaneous emission decrease for the purpose of

obtaining a Netting credit or offset under the Clean Air Act’s PSD and Nonattainment NSR

programs. Notwithstanding the preceding sentence, and subject to the limitations provided in

Paragraph 146, Minnesota Power may treat up to (a) 75 tons of NOx, 75 tons of SO2, and 15 tons

of PM emission reductions at Boswell Units 3 and 4 as if they were not otherwise required by

this Consent Decree for purposes of Netting at the Boswell Units 3 and 4.

146. Use of the Netting credits provided in Paragraph 145 is subject to the following

additional restrictions:

(a) The emission reductions of NOx, SO2, and PM Minnesota Power intends to utilize for

Netting purposes must be contemporaneous and otherwise creditable within the meaning


39

of the Act and the applicable SIP, and Minnesota Power must comply with, and be

subject to, all requirements and criteria for creating contemporaneous creditable

decreases as set forth in 40 C.F.R. § 52.21(b) and the applicable SIP, subject to the

limitations of this Section,

(b) Minnesota Power must apply for, and obtain, any required major or minor NSR

permits for any project in which emission reductions under Paragraph 145 are used for

Netting. Minnesota Power shall provide notice and a copy of its permit application to

EPA in accordance with Section XIX (Notices), concurrent with its permit application

submission to the relevant permitting authority,

(c) The emission reductions of NOx, SO2, and PM that Minnesota Power intends to utilize

for Netting shall not be available under this Section if such use would result in an

exceedance of a PSD increment, or an interference with “reasonable further progress”

toward attainment of a NAAQS in accordance with Part D of Title I of the CAA, and

(d) Minnesota Power must be and remain in full compliance with the provisions of this

Consent Decree establishing performance, operational, maintenance, and control

technology requirements at Boswell Units 3 and 4, including Emission Rates, System-

Wide Annual Tonnage Limitations, and the requirements pertaining to the Surrender of

SO2 Allowances and NOx Allowances.

147. The limitations on the generation and use of Netting credits and offsets set forth in

this Section do not apply to emission reductions achieved by a particular Minnesota Power

System Unit that are greater than those required under this Consent Decree for that particular

Minnesota Power System Unit. For purposes of this Paragraph, emission reductions from a

Minnesota Power System Unit are greater than those required under this Consent Decree if they


40

result from such Unit’s compliance with federally-enforceable emission limits that are more

stringent than the limits imposed on the Unit under this Consent Decree and under applicable

provisions of the Clean Air Act.

148. Nothing in this Consent Decree is intended to preclude the emission reductions

generated under this Consent Decree from being considered by the applicable state regulatory

agency or EPA for the purpose of attainment demonstrations submitted pursuant to § 110 of the

Act, 42 U.S.C. § 7410, or in determining impacts on National Ambient Air Quality Standards,

PSD increment, or air quality related values, including visibility, in a Class I area.

IX. ENVIRONMENTAL MITIGATION PROJECTS

149. Minnesota Power shall implement the Environmental Mitigation Projects

(“Projects”) described in Appendix A to this Consent Decree in compliance with the approved

plans and schedules for such Projects and other terms of this Consent Decree. In implementing

the Projects, Minnesota Power shall spend no less than $4.2 million in Project Dollars.

Minnesota Power shall not include its own personnel costs in overseeing the implementation of

the Projects as Project Dollars.

150. Minnesota Power shall maintain, and present to EPA and MPCA upon request, all

documents to substantiate the Project Dollars expended to implement the Projects described in

Appendix A, and shall provide these documents to EPA and MPCA within thirty (30) Days

following a request for the documents.

151. All plans and reports prepared by Minnesota Power pursuant to the requirements

of this Section IX of the Consent Decree and required to be submitted to EPA and MPCA shall

be publicly available from Minnesota Power without charge in paper or electronic format.


41

152. Minnesota Power shall certify, as part of each plan submitted to EPA for any

Project, that Minnesota Power is not otherwise required by law to perform the Project described

in the plan, that Minnesota Power is unaware of any other person who is required by law to

perform the Project, and that Minnesota Power will not use any Project, or portion thereof, to

satisfy any obligations that it may have under other applicable requirements of law, including

any applicable renewable or energy efficiency portfolio standards.

153. Minnesota Power shall use good faith efforts to secure as much environmental

benefit as possible for the Project Dollars expended, consistent with the applicable requirements

and limits of this Consent Decree.

154. If Minnesota Power elects (where such an election is allowed) to undertake a

Project by contributing funds to another person or entity that will carry out the Project in lieu of

Minnesota Power, but not including Minnesota Power’s agents or contractors, that person or

instrumentality must, in writing: (a) identify its legal authority for accepting such funding; and

(b) identify its legal authority to conduct the Project for which Minnesota Power contributes the

funds. Regardless of whether Minnesota Power elects (where such election is allowed) to

undertake a Project by itself or to do so by contributing funds to another person or

instrumentality that will carry out the Project, Minnesota Power acknowledges that it will receive

credit for the expenditure of such funds as Project Dollars only if Minnesota Power demonstrates

that the funds have been actually spent by either Minnesota Power or by the person or

instrumentality receiving them, and that such expenditures met all requirements of this Consent

Decree.

155. Minnesota Power shall comply with the reporting requirements described in

Appendix A.


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156. Within sixty (60) Days following the completion of each Project required under

this Consent Decree (including any applicable periods of demonstration or testing), Minnesota

Power shall submit to EPA and MPCA a report that documents the date that the Project was

completed, the results achieved by implementing the Project, including the emission reductions

or other environmental benefits, and the Project Dollars expended by Minnesota Power in

implementing the Project.

X. CIVIL PENALTY

157. Within thirty (30) Days after the Date of Entry of this Consent Decree, Settling

Defendant shall pay to the United States and the State of Minnesota a civil penalty in the amount

of $1.4 million.

(a) The United States’ portion of the civil penalty shall be paid as follows: Within thirty

(30) Days after the Date of Entry of this Consent Decree, Settling Defendant shall pay a

civil penalty to the United States in the amount of $1.2 million paid by Electronic Funds

Transfer (“EFT”) to the United States Department of Justice, in accordance with current

EFT procedures, referencing USAO File Number 2014v00269, DOJ Case Number 90-5-

2-1-09683, and the civil action case name and case number of this action. The costs of

such EFT shall be Settling Defendant’s responsibility. Payment shall be made in

accordance with instructions provided to Settling Defendant by the Financial Litigation

Unit of the U.S. Attorney’s Office for the District of Minnesota. Any funds received after

2:00 p.m. EDT shall be credited on the next Business Day. At the time of payment,

Settling Defendant shall provide notice of payment, referencing the USAO File Number,

the DOJ Case Number, and the civil action case name and case number, to the


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Department of Justice and to EPA in accordance with Section XIX (Notices) of this

Consent Decree.

(b) The MPCA portion of the civil penalty shall be paid as follows: Within thirty (30)

Days after entry of this Consent Decree, Settling Defendant shall pay to MCPA a civil

penalty in the amount of $200,000 by certified check made payable to the Minnesota

Pollution Control Agency and sent to Carl Agerbeck, MPCA Fiscal Services-6th Floor,

Minnesota Pollution Control Agency, 520 Lafayette Road, St. Paul, Minnesota 55155-

4194.

158. Failure to timely pay the civil penalty shall subject Settling Defendant to interest

accruing from the date payment is due until the date payment is made at the rate prescribed by 28

U.S.C. § 1961, and shall render Settling Defendant liable for all charges, costs, fees, and

penalties established by law for the benefit of a creditor or of the United States in securing

payment.

159. Payments made pursuant to this Section are penalties within the meaning of

Section 162(f) of the Internal Revenue Code, 26 U.S.C. § 162(f), and are not tax-deductible

expenditures for purposes of federal law.

XI. RESOLUTION OF CLAIMS AGAINST MINNESOTA POWER

160. Civil Claims of the United States and the State of Minnesota Occurring Before the

Date of Lodging of this Consent Decree. Entry of this Consent Decree shall resolve all civil

claims of the United States and the State of Minnesota against Minnesota Power that arose from

any modifications commenced at Minnesota Power’s Boswell Units 1 through 4, Laskin Units 1

and 2, Taconite Harbor Units 1 through 3, and Rapids Units 5 and 6, prior to the Date of Lodging


44

of this Consent Decree, including but not limited to those modifications alleged in the

NOVs/FOVs issued by EPA to Minnesota Power on August 5, 2008 and March 31, 2011 and the

Complaint filed in this civil action, under any or all of: (a) Part C or D of Title I of the Clean Air

Act, 42 U.S.C. §§ 7470-7492, 7501-7515, and the implementing PSD and Nonattainment NSR

provisions of any Minnesota SIP or the MPCA rules, including but not limited to, all such rule

provisions set forth in the Minnesota Rules, Chapter 7007 (Permits and Offsets); (b) the New

Source Performance Standards of Section 111 of the Clean Air Act, 42 U.S.C. § 7411, and 40

C.F.R. § 60.14; and (c) Title V of the Clean Air Act, 42 U.S.C. § 7661-7661f, but only to the

extent that such Title V claims are based on Minnesota Power’s failure to obtain an operating

permit that reflects applicable requirements imposed under Section 111 or Part C or D of Title I

of the Clean Air Act.

161. This Consent Decree does not apply to any claim(s) of alleged criminal liability.

XII. PERIODIC REPORTING

162. After entry of this Consent Decree, Minnesota Power shall submit to EPA and

MPCA a periodic report, within sixty (60) Days after the end of each half of the calendar year

(January through June and July through December). The report shall include the following

information:

a. all information necessary to determine compliance with the requirements of the

following provisions of this Consent Decree: all applicable 30-Day Rolling

Average Emission Rates for NOx (including information regarding any applicable

Heat-Input Weighted Average Emission Rates) and 30-Day Rolling Average

Emission Rates for SO2; all applicable 12-Month Rolling Average Emission Rates


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for NOx and 12-Month Rolling Average Emission Rates for SO2; all applicable

PM Emission Stack Test data; all applicable System-Wide Annual Tonnage

Limitations for NOx and System-Wide Annual Tonnage Limitations for SO2; the

obligation to monitor NOx, SO2, and PM emissions; the obligation to optimize PM

emission controls; the obligation to limit coal use at Rapids 5 and Rapids 6 as

required by Paragraph 143; and the obligation to Surrender NOx Allowances and

SO2 Allowances;

b. 3-Hour Rolling Average Emission Rate PM CEMS data as required by Paragraph

132, identifying all periods in excess of applicable PM emission rates, in

electronic Microsoft Excel compatible format, and all periods of monitor

Malfunction, maintenance, and/or repair as provided in Paragraph 132;

c. emissions reporting and SO2 Allowance and NOx Allowance accounting

information necessary to determine Super-Compliant Allowances that Minnesota

Power claims to have generated in accordance with Sections IV (NOx Emission

Reductions and Controls) and V (SO2 Emission Reductions and Controls) through

control of emissions beyond the requirements of this Consent Decree;

d. schedule for the installation or upgrade and commencement of operation of new

or upgraded pollution control devices required by this Consent Decree, including

the nature and cause of any actual or anticipated delays, and any steps taken by

Minnesota Power to mitigate such delay;

e. all affirmative defenses asserted pursuant to Paragraphs 181 through 183 during

the period covered by the periodic report;

f. an identification of all periods when any pollution control device required by this


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Consent Decree to Continuously Operate was not operating, the reason(s) for the

equipment not operating, and the basis for Minnesota Power’s compliance or non-

compliance with the Continuous Operation requirements of this Consent Decree;

g. a summary of actions implemented and expenditures (cumulative and in the

current reporting period) made pursuant to implementation of the Environmental

Mitigation Projects required pursuant to Section IX and Appendix A; and

h. an identification of which of Minnesota Power’s Units will be Retired, Refueled,

or Repowered as required by Paragraphs 139 and 140 of this Consent Decree.

This information in the periodic report shall not replace the need for compliance

with the Notice requirements in Section VII of this Consent Decree.

163. In any periodic report submitted pursuant to this Section, Minnesota Power may

incorporate by reference information previously submitted under its Title V permitting

requirements, provided that Minnesota Power attaches the Title V Permit report (or the pertinent

portions of such report) and provides a specific reference to the provisions of the Title V Permit

report that are responsive to the information required in the periodic report.

164. In addition to the reports required pursuant to this Section, if Minnesota Power

violates or deviates from any requirement of this Consent Decree, Minnesota Power shall submit

to EPA and MPCA a report on the violation or deviation within fifteen (15) Business Days after

Minnesota Power knew or should have known of the event by exercise of due diligence. In the

report, Minnesota Power shall explain the cause or causes of the violation or deviation and any

measures taken or to be taken by Minnesota Power to cure the reported violation or deviation or

to prevent such violation or deviation in the future. If at any time, the requirements of this

Consent Decree are included in Title V Permits, consistent with the requirements for such


47

inclusion in this Consent Decree, then the submittal to EPA and MPCA of deviation reports

required under applicable Title V regulations shall be deemed to satisfy all the requirements of

this Paragraph.

165. Each Minnesota Power report required by this Consent Decree shall be signed by

Minnesota Power’s Responsible Official as defined in Title V of the Clean Air Act, or his or her

equivalent or designee of at least the rank of Vice President, and shall contain the following

certification:

This information was prepared either by me or under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted. Based on my evaluation, or the direction and my inquiry of the person(s) who manage the system, or the person(s) directly responsible for gathering the information, I hereby certify under penalty of law that, to the best of my knowledge and belief, this information is true, accurate, and complete. I understand that there are significant penalties for submitting false, inaccurate, or incomplete information to the United States.

XIII. REVIEW AND APPROVAL OF SUBMITTALS

166. Minnesota Power shall submit each plan, report, or other submission required by

this Consent Decree to EPA and MPCA whenever such a document is required to be submitted

for review or approval by EPA pursuant to this Consent Decree. For any submittal requiring

EPA approval under this Consent Decree, EPA may approve the submittal or decline to approve

it after consultation with the State of Minnesota and provide written comments explaining the

bases for declining such approval as soon as reasonably practicable. Within sixty (60) Days of

receiving written comments from EPA, Minnesota Power shall either: (a) revise the submittal

consistent with the written comments and provide the revised submittal to EPA and MPCA; or

(b) submit the matter for dispute resolution, including the period of informal negotiations, under

Section XVI (Dispute Resolution) of this Consent Decree.

167. Upon receipt of EPA’s final approval of the submittal, or upon completion of the


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submittal pursuant to dispute resolution, Minnesota Power shall implement the approved

submittal in accordance with the schedule specified therein, another EPA-approved schedule, or

as established through the dispute resolution process.

XIV. STIPULATED PENALTIES

168. For any failure by Minnesota Power to comply with the terms of this Consent

Decree, and subject to the provisions of Sections XV (Force Majeure) and XVI (Dispute

Resolution) and the other provisions of this Consent Decree, Minnesota Power shall pay to the

United States, within thirty (30) Days after receipt of written demand to Minnesota Power by the

United States stipulated penalties as follows:

Consent Decree Violation Stipulated Penalty

a. Failure to pay the civil penalty as required by Section X (Civil Penalty) of this Consent Decree

$10,000 per Day

b. Failure to comply with any applicable 30-Day Rolling Average Emission Rate

$2,500 per Day per violation where the violation is less than 5% in excess of the lb/mmBTU limits $5,000 per Day per violation where the violation is equal to or greater than 5% but less than 10% in excess of the lb/mmBTU limits $10,000 per Day per violation where the violation is equal to or greater than 10% in excess of the lb/mmBTU limits

c. Failure to comply with any applicable 12-Month Rolling Average Emission Rate for NOx or SO2

$200 per Day per violation where the violation is less than 5% in excess of the limits set forth in this Consent Decree $400 per Day per violation where the violation is equal to or greater than 5% but less than


49

10% in excess of the limits set forth in this Consent Decree $800 per Day per violation where the violation is equal to or greater than 10% in excess of the limits set forth in this Consent Decree

d. Failure to comply with an applicable System-Wide Annual Tonnage Limitations

(1) $5,000 per ton for first 100 tons, $10,000 per ton for each additional ton above 100 tons, plus (2) at Minnesota Power’s option, either the Surrender of NOx Allowances or SO2 Allowances in an amount equal to two times the number of tons of NOx or SO2 emitted that exceeded the System-Wide Annual Tonnage Limitation, or the payment of $2,500 per ton for an amount of tons equal to two times the number of tons of NOx or SO2 emitted that exceeded the System-Wide Annual Tonnage Limitation

e. Failure to install, commence Continuous Operation, or Continuously Operate a NOx, SO2, or PM control device as required by this Consent Decree

$10,000 per Day per violation during the first 30 Days; $37,500 per Day per violation thereafter

f. Failure to comply with any applicable PM Emission Rate $2,500 per Operating Day per violation where the violation is less than 5% in excess of the lb/mmBTU limit $5,000 per Operating Day per violation where the violation is equal to or greater than 5% but less than 10% in excess of the lb/mmBTU limit $10,000 per Operating Day per violation where the violation is equal to or greater than 10% in excess of the lb/mmBTU limit

g. Failure to comply with the 40.0 percent limitation on 12- $200 per Day where the 12-


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Month Percent Heat Input from Coal as required by Paragraph 143

Month Percent Heat Input from Coal is greater than 40.0 percent, but less than 41.0 percent $900 per Day where the 12-Month Percent Heat Input from Coal is greater than 41.0 percent, but less than 42.0 percent $2,100 per Day where the 12-Month Percent Heat Input from Coal is greater than 42.0 percent

h. Failure to Repower, Refuel, Retire, or Reroute a Unit as required by this Consent Decree


i. Failure to conduct a stack test for PM as required by Section VI of this Consent Decree

$1,000 per Day per violation

j. Failure to install or operate CEMS as required by this Consent Decree


k. Failure to apply for any permit required by Section XVII of this Consent Decree


l. Failure to timely submit, modify, or implement, as approved, the reports, plans, studies, analyses, protocols, or other submittals required by this Consent Decree

$750 per Day per violation during the first 10 Days; $1,000 per Day per violation thereafter

m. Failure to Surrender SO2 Allowances as required by this Consent Decree

$37,500 per Day, plus $1,000 per SO2 Allowance not Surrendered

n. Failure to Surrender NOx Allowances as required by this Consent Decree

$37,500 per Day, plus $1,000 per NOx Allowance not Surrendered

o. Using, selling, banking, trading, or transferring NOx Allowances or SO2 Allowances except as permitted by this Consent Decree

At Minnesota Power’s option, either the Surrender of NOx Allowances or SO2 Allowances in an amount equal to four (4) times the number of NOx Allowances or SO2 Allowances used, sold, banked, traded, or transferred in violation of this


51

Consent Decree, or the payment of $2,500 per ton for an amount of tons equal to four (4) times the number of NOx Allowances or SO2 Allowances used, sold, banked, traded, or transferred in violation of this Consent Decree

p. Failure to optimize the existing ESPs and Baghouses as required by Paragraph 120 of this Consent Decree


q. Failure to undertake and complete any of the Environmental Mitigation Projects in compliance with Section IX and Appendix A of this Consent Decree


r. Any other violation of this Consent Decree $1,000 per Day per violation

169. Violations of any limit based on a 30-Day Rolling Average Emission Rate

constitutes thirty (30) Days of violation, provided, however, that where such a violation (for the

same pollutant and from the same Unit) recurs within periods less than thirty (30) Days,

Minnesota Power shall not be obligated to pay a daily stipulated penalty for any Day of the

recurrence for which a stipulated penalty has already been paid.

170. Minnesota Power shall not be subject to stipulated penalties for a failure to

comply with any 30-Day Rolling Average Emission Rate for NOx or SO2 due to a startup or

shutdown event provided that (1) Minnesota Power’s emissions do not exceed the 30-Day

Rolling Average NOx or SO2 Emission Rate by more than 0.015 lb/mmBTU, (2) in the next

periodic reporting period, Minnesota Power provides EPA with data and calculations to

demonstrate a startup or shutdown event occurred and but for the startup or shutdown event,

Minnesota Power would have achieved and maintained compliance with the applicable 30-Day

Rolling Average Emission Rate for NOx or SO2, and (3) Minnesota Power identifies the time

period of the event, provides EPA and the MPCA with data regarding the flue gas temperature

entering each applicable control device during the startup or shutdown event and provides a brief


52

description of why such startup/shutdown conditions limited or impeded the operation of

applicable pollution control device(s). Minnesota Power may only invoke this provision in

relation to five startup or shutdown events per calendar year per Unit during the term of this

Consent Decree. For purposes of this Paragraph 170, a startup or shutdown event may not

extend more than 72 hours. This provision applies only to the calculation of stipulated penalties,

and shall not be included in any permit.

171. Violations of any limit based on a 12-Month Rolling Average Emission Rate or

violations of the 12-Month Percent Heat Input from Coal constitutes three hundred sixty-five

(365) Days of violation, provided, however, that where such a violation (as to a 12-Month

Rolling Average Emission Rate, for the same pollutant and from the same Unit) recurs within

periods less than 12 Months, Minnesota Power shall not be obligated to pay a daily stipulated

penalty for any Day of the recurrence for which a stipulated penalty has already been paid.

172. Violations of any applicable PM Emission Rate demonstrated by stack test shall

be deemed to start on the Day of the stack test demonstrating a violation and continue each

Operating Day thereafter until and excluding such Day on which a subsequent stack test

conducted pursuant to Paragraph 128 demonstrates compliance with the applicable PM Emission

Rate.

173. Where two or more Units share a common stack or monitoring point for NOx,

SO2, and/or PM, compliance with any and all of the requirements of this Consent Decree will

still be determined for each Unit individually. For purposes of determining compliance with this

Consent Decree, an emission rate measured at a common stack or monitoring point will be

treated as if it were the emission rate for each of the Units contributing emissions. For example,

if NOx emissions measured in the common stack for Laskin 1 and 2 were to exceed 0.190


53

lb/mmBTU, compliance for Laskin 1 and Laskin 2 would be individually determined by

comparing the required rate for each to the single rate measured in the common stack, and

Minnesota Power would have violated this Consent Decree twice and would be required to pay

stipulated penalties for both an exceedance at Laskin 1 and an exceedance at Laskin 2.

Notwithstanding the foregoing, if Minnesota Power demonstrates that a Unit was not operating

during an exceedance, then no violation will be found at that Unit for the exceedance.

174. All stipulated penalties shall begin to accrue on the Day after the performance is

due or on the Day a violation occurs, whichever is applicable, and shall continue to accrue until

performance is satisfactorily completed or until the violation ceases, whichever is applicable.

Nothing in this Consent Decree shall prevent the simultaneous accrual of separate stipulated

penalties for separate violations of this Consent Decree.

175. Minnesota Power shall pay all stipulated penalties to the United States within

thirty (30) Days following receipt of written demand to Minnesota Power from the United States,

and shall continue to make such payments every thirty (30) Days thereafter until the violation(s)

no longer continues, unless Minnesota Power elects within twenty (20) Days following receipt of

written demand to Minnesota Power from the United States to dispute the imposition or accrual

of stipulated penalties in accordance with the provisions in Section XVI (Dispute Resolution) of

this Consent Decree.

176. Stipulated penalties shall continue to accrue as provided in accordance with

Paragraph 173 during any dispute, with interest on accrued stipulated penalties payable and

calculated at the rate established by the Secretary of the Treasury, pursuant to 28 U.S.C. § 1961,

but need not be paid until the following:

a. If the dispute is resolved by agreement, or by a decision of the United States


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pursuant to Section XVI (Dispute Resolution) of this Consent Decree that is not

appealed to the Court, accrued stipulated penalties agreed or determined to be

owing, together with accrued interest, shall be paid to the United States within

thirty (30) Days following the effective date of the agreement or of the receipt of

the United States’ decision;

b. If the dispute is appealed to the Court and the United States prevails in whole or

in part, Minnesota Power shall, within sixty (60) Days of receipt of the Court’s

decision or order, pay all accrued stipulated penalties determined by the Court to

be owing, together with interest accrued on such penalties determined by the

Court to be owing, except as provided in Subparagraph (c), below;

c. If the Court’s decision is appealed by any Party, Minnesota Power shall, within

fifteen (15) Days of receipt of the final appellate court decision, pay all accrued

stipulated penalties determined by the appellate court to be owed, together with

interest accrued on such stipulated penalties.

177. Notwithstanding any other provision of this Consent Decree, the accrued

stipulated penalties agreed by the United States and Minnesota Power, or determined by the

United States through Dispute Resolution, to be owed may be less than the stipulated penalty

amounts set forth in Paragraph 168.

178. All monetary stipulated penalties shall be paid to the United States in the manner

set forth in Section X (Civil Penalty) of this Consent Decree, and all NOx Allowance Surrender

and SO2 Allowance Surrender stipulated penalties shall comply with the Surrender procedures of

Paragraphs 97 - 98 and 118 - 119.

179. If Minnesota Power fails to pay stipulated penalties in compliance with the terms


55

of this Consent Decree, the United States shall be entitled to collect interest on such penalties

owing to the United States, as provided for in 28 U.S.C. § 1961.

180. The stipulated penalties provided for in this Consent Decree shall be in addition to

any other rights, remedies, or sanctions available to the United States by reason of Minnesota

Power’s failure to comply with any requirement of this Consent Decree or applicable law, except

that for any violation of the Act for which this Consent Decree provides for payment of a

stipulated penalty, Minnesota Power shall be allowed a credit for stipulated penalties paid against

any statutory penalties also imposed for such violation.

181. Affirmative Defense as to Stipulated Penalties for Excess Emissions Occurring

During Malfunctions: If any of the Units at Minnesota Power’s Boswell Energy Center, Laskin

Energy Center, or Taconite Harbor, exceed an applicable 30-Day Rolling Average Emission Rate

for NOx or SO2 set forth in this Consent Decree due to Malfunction, or if any of the Units at

Minnesota Power’s Boswell Energy Center that have been approved to use PM CEMS for

compliance under Paragraph 127 exceed an applicable 3-Hour Rolling Average Emission Rate

for PM due to Malfunction, Minnesota Power, bearing the burden of proof, has an affirmative

defense to stipulated penalties under this Consent Decree, if Minnesota Power has complied with

the reporting requirements of Paragraph 184 and has demonstrated all of the following:

a. the excess emissions were caused by a sudden, unavoidable breakdown of

technology, beyond Minnesota Power’s control;

b. the excess emissions (1) did not stem from any activity or event that could have

been foreseen and avoided, or planned for, and (2) could not have been avoided

by better operation and maintenance practices in accordance with manufacturers’

specifications and good engineering and maintenance practices;


56

c. to the maximum extent practicable, the air pollution control equipment and

processes were maintained and operated in a manner consistent with good

practice for minimizing emissions in accordance with manufacturers’

specifications and good engineering and maintenance practices;

d. repairs were made in an expeditious fashion when Minnesota Power knew or

should have known that an applicable 30-Day Rolling Average Emission Rate or

3-Hour Rolling Average Emission Rate was being or would be exceeded. Off-

shift labor and overtime must have been utilized, to the extent practicable, to

ensure that such repairs were made as expeditiously as practicable;

e. the amount and duration of the excess emissions (including any bypass) were

minimized to the maximum extent practicable during periods of such emissions in

accordance with manufacturers’ specifications and good engineering and

maintenance practices;

f. all possible steps were taken to minimize the impact of the excess emissions in

accordance with approved plans, QA/QC protocols, manufacturers’ specifications

and recommendations, and good engineering and maintenance practices;

g. all emission monitoring systems were kept in operation if at all possible in

accordance with manufacturers’ specifications and good engineering and

maintenance practices;

h. Minnesota Power’s actions in response to the excess emissions were documented

by properly signed, contemporaneous operating logs, or other relevant evidence;

i. the excess emissions were not part of a recurring pattern indicative of inadequate

design, operation, or maintenance; and


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j. Minnesota Power properly and promptly notified EPA and MPCA as required by

this Consent Decree.

182. To assert an affirmative defense for exceedance of an applicable 30-Day Rolling

Average Emission Rate for NOx or SO2 due to Malfunction under Paragraph 181, Minnesota

Power shall submit all data to EPA demonstrating the actual emissions for the Day the

Malfunction occurs and the 29-Day period following the Day the excess emissions from the

Malfunction occurs. To assert an affirmative defense for exceedance of an applicable 3-Hour

Rolling Average Emission Rate for PM due to Malfunction under Paragraph 181, Minnesota

Power shall submit to EPA all data demonstrating the actual emissions for the 3-hour period

during which the excess emissions from Malfunction occurs. In addition to data Minnesota

Power is otherwise required to submit under this Consent Decree, Minnesota Power may, if it

elects, submit emissions data for the same 30-Day period or 3-hour period, as applicable, but that

excludes the excess emissions.

183. If excess emissions occur due to a Malfunction during routine startup and

shutdown, then those instances shall be treated as other Malfunctions subject to Paragraph181.

184. Minnesota Power shall provide notice to EPA in writing of Minnesota Power’s

intent to assert an affirmative defense for Malfunction under Paragraphs 181 in Minnesota

Power’s semi-annual periodic reports as required by Paragraph 162. This notice shall be

submitted to EPA pursuant to the provisions of Section XIX (Notices). The notice shall contain:

a. the identity of each stack or other emission point where the excess emissions

occurred;

b. the magnitude of the excess emissions expressed in lb/mmBTU and the operating

data and calculations used in determining the magnitude of the excess emissions;


58

c. the time and duration or expected duration of the excess emissions;

d. the identity of the equipment from which the excess emissions emanated;

e. the nature and suspected cause of the excess emissions;

f. the steps taken to remedy the Malfunction and the steps taken or planned to

prevent the recurrence of the Malfunction;

g. the steps that were or are being taken to limit the excess emissions; and

h. if applicable, a list of the steps taken to comply with the permit conditions

governing Unit operation during periods of Malfunction.

185. A Malfunction shall not constitute a Force Majeure Event unless the Malfunction

meets the definition of a Force Majeure Event, as provided in Section XV (Force Majeure).

186. The affirmative defense provided herein is only an affirmative defense to

stipulated penalties for violations of this Consent Decree, and not a defense to any civil or

administrative action for injunctive relief.

XV. FORCE MAJEURE

187. For purposes of this Consent Decree, a “Force Majeure Event” shall mean an

event that has been or will be caused by circumstances beyond the control of Minnesota Power,

its contractors, or any entity controlled by Minnesota Power that delays or prevents compliance

with any provision of this Consent Decree or otherwise causes noncompliance with any

provision of this Consent Decree despite Minnesota Power’s best efforts to fulfill the obligation.

“Best efforts to fulfill the obligation” include using the best efforts to anticipate any potential

Force Majeure Event and to address the effects of any such event (a) as it is occurring, and (b)

after it has occurred, such that the delay or noncompliance, and any adverse environmental effect

of the delay or noncompliance, is minimized to the greatest extent possible.


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188. Notice of Force Majeure Events. If any event occurs or has occurred that may

delay or prevent compliance with or otherwise cause noncompliance with any obligation under

this Consent Decree, as to which Minnesota Power intends to assert a claim of a Force Majeure

Event, Minnesota Power shall notify the United States and MPCA in writing as soon as

practicable, but in no event later than fourteen (14) Business Days following the date Minnesota

Power first knew, or by the exercise of due diligence should have known, that the event caused

or may cause such delay or noncompliance. In this notice, Minnesota Power shall reference this

Paragraph of this Consent Decree and describe the anticipated length of time that the delay or

noncompliance may persist, the cause or causes of the delay or noncompliance, all measures

taken or to be taken by Minnesota Power to prevent or minimize the delay or noncompliance, the

schedule by which Minnesota Power proposes to implement those measures, and Minnesota

Power’s rationale for attributing a delay or violation to a Force Majeure Event. Minnesota

Power shall adopt all reasonable measures to avoid or minimize such delays or violations.

Minnesota Power shall be deemed to know of any circumstance which Minnesota Power, its

contractors, or any entity controlled by Minnesota Power knew or should have known.

189. Failure to Give Notice. If Minnesota Power fails to comply with the above notice

requirements regarding a Force Majeure Event, the EPA, after consultation with the MPCA, may

void Minnesota Power’s claim for a Force Majeure Event as to the specific event for which

Minnesota Power has failed to comply with such notice requirement.

190. United States’ Response. The United States shall notify Minnesota Power in

writing regarding Minnesota Power’s claim of a Force Majeure Event as soon as reasonably

practicable. If the United States after consultation with MPCA agrees that a Force Majeure

Event has delayed or prevented, or will delay or prevent, compliance with any provision of this


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Consent Decree, or has otherwise caused or will cause noncompliance with any provision of this

Consent Decree, the United States and Minnesota Power shall stipulate to an extension of

deadline(s) for performance of the affected compliance requirement(s) by a period equal to the

delay or period of noncompliance actually caused by the event. In such circumstances, an

appropriate modification shall be made pursuant to Section XXIII (Modification) of this Consent

Decree.

191. Disagreement. If the United States does not accept Minnesota Power’s claim of a

Force Majeure Event, or if the United States and Minnesota Power cannot agree on the length of

the delay or noncompliance actually caused by the Force Majeure Event, the matter shall be

resolved in accordance with Section XVI (Dispute Resolution) of this Consent Decree.

192. Burden of Proof. In any dispute regarding a Force Majeure Event, Minnesota

Power shall bear the burden of proving that any delay in performance or any other

noncompliance with any requirement of this Consent Decree was caused by or will be caused by

a Force Majeure Event. Minnesota Power shall also bear the burden of proving that Minnesota

Power gave the notice required by this Section and the burden of proving the anticipated duration

and extent of any delay(s) or noncompliance attributable to a Force Majeure Event. An

extension of one compliance date based on a particular event may, but will not necessarily, result

in an extension of a subsequent compliance date.

193. Events Excluded. Unanticipated or increased costs or expenses associated with

the performance of Minnesota Power’s obligations under this Consent Decree shall not constitute

a Force Majeure Event.

194. Potential Force Majeure Events. The Parties agree that, depending upon the

circumstances related to an event and Minnesota Power’s response to such circumstances, the


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kinds of events listed below are among those that could qualify as Force Majeure Events within

the meaning of this Section: construction, labor, or equipment delays; Malfunction of a Unit or

emission control device; unanticipated coal supply or pollution control reagent delivery

interruptions; acts of God; acts of war or terrorism; and orders by a government official,

government agency, other regulatory authority, or a regional transmission organization (e.g. the

Midwest Independent System Operator), acting under and authorized by applicable law, that

direct Minnesota Power to supply electricity in response to a system-wide (state-wide or

regional) emergency (which could include unanticipated required operation to avoid loss of load

or unserved load or to preserve the reliability of the bulk power system). Depending upon the

circumstances and Minnesota Power’s response to such circumstances, failure of a permitting

authority or the Minnesota Public Utilities Commission (“MPUC”) to issue a necessary permit or

order with sufficient time for Minnesota Power to achieve compliance with this Consent Decree

may constitute a Force Majeure Event where the failure of the permitting authority or MPUC to

act is beyond the control of Minnesota Power and Minnesota Power has taken all steps available

to it to obtain the necessary permit (exclusive of submitting the permit application under the

MPCA’s Expedited Permitting Program), including, but not limited to: timely submitting a

complete permit application; responding to requests for additional information by the permitting

authority or MPUC in a timely fashion; and accepting lawful permit terms and conditions after

expeditiously exhausting any legal rights to appeal terms and conditions imposed by the

permitting authority or MPUC.

195. As part of the resolution of any matter submitted to this Court under Section XVI

(Dispute Resolution) regarding a claim of Force Majeure, the United States after consultation

with MPCA and Minnesota Power by agreement, or this Court by order, may in appropriate


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circumstances extend or modify the schedule for completion of work under this Consent Decree

to account for the delay in the work that occurred as a result of any delay agreed to by the United

States or approved by the Court. Minnesota Power shall be liable for stipulated penalties

pursuant to Section XIV (Stipulated Penalties) for its failure thereafter to complete the work in

accordance with the extended or modified schedule (provided that Minnesota Power shall not be

precluded from making a further claim of a Force Majeure Event with regard to meeting any

such extended or modified schedule).

XVI. DISPUTE RESOLUTION

196. The dispute resolution procedure provided by this Section shall be available to

resolve all disputes arising under this Consent Decree, provided that the Party invoking such

procedure has first made a good faith attempt to resolve the matter with the other Parties.

197. The dispute resolution procedure required herein shall be invoked by one Party

giving written notice to the other Parties advising of a dispute pursuant to this Section. The

notice shall describe the nature of the dispute and shall state the noticing Party’s position with

regard to such dispute. The Parties receiving such a notice shall acknowledge receipt of the

notice, and the Parties in dispute shall expeditiously schedule a meeting to discuss the dispute

informally not later than fourteen (14) Days following receipt of such notice.

198. Disputes submitted to dispute resolution under this Section shall, in the first

instance, be the subject of informal negotiations between the Parties. Such period of informal

negotiations shall not extend beyond thirty (30) Days from the date of the first meeting between

the Parties’ representatives unless they agree in writing to shorten or extend this period.

199. In the event that the United States and the State make differing determinations or

take differing actions that affect Minnesota Power's rights or obligations under this Consent


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Decree, the determination or action of the United States shall control.

200. If the Parties are unable to reach agreement during the informal negotiation

period, the United States or the State of Minnesota (as applicable) shall provide Minnesota

Power with a written summary of its position regarding the dispute. The written position

provided by the United States (following consultation with the State) shall be considered binding

unless, within forty-five (45) Days thereafter, Minnesota Power seeks judicial resolution of the

dispute by filing a petition with this Court. The United States may submit a response to the

petition within forty-five (45) Days of filing.

201. In addition to any other methods set forth in this Section for altering time periods,

the time periods set out in this Section may be shortened or lengthened upon motion to the Court

of one of the Parties to the dispute, explaining the Party’s basis for seeking such a scheduling

modification filing.

202. This Court shall not draw any inferences nor establish any presumptions adverse

to either Party as a result of invocation of this Section or the Parties’ inability to reach

agreement.

203. As part of the resolution of any dispute under this Section, in appropriate

circumstances the Parties may agree, or this Court may order, an extension or modification of the

schedule for the completion of the activities required under this Consent Decree to account for

the delay that occurred as a result of dispute resolution. Minnesota Power shall be liable for

stipulated penalties pursuant to Section XIV (Stipulated Penalties) for its failure thereafter to

complete the work in accordance with the extended or modified schedule, provided that

Minnesota Power shall not be precluded from asserting that a Force Majeure Event has caused or

may cause a delay in complying with the extended or modified schedule.


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204. The Court shall decide all disputes pursuant to applicable principles of law for

resolving such disputes. In their initial filings with the Court under Paragraph 200, the Parties

shall state their respective positions as to the applicable standard of law for resolving the

particular dispute.

XVII. PERMITS

205. Unless expressly stated otherwise in this Consent Decree, in any instance where

otherwise applicable law or this Consent Decree requires Minnesota Power to secure a permit to

authorize construction or operation of any device, including all preconstruction, construction,

and operating permits required under applicable state law, Minnesota Power shall make such

application in a timely manner. EPA in consultation with MPCA shall use best efforts to review

expeditiously, to the extent applicable, all permit applications submitted by Minnesota Power to

meet the requirements of this Consent Decree.

206. Notwithstanding Paragraph 205, nothing in this Consent Decree shall be

construed to require Minnesota Power to apply for, amend or obtain (1) a PSD or Nonattainment

NSR permit or permit amendment for any physical change in, or any change in the method of

operation of, any Minnesota Power System Unit that would give rise to claims resolved by

Section XI (Resolution of Claims Against Minnesota Power) of this Consent Decree; or (2) any

Title V Permit or other operating permit or permit amendment, or application therefore, related

to or arising from any physical change in, or change in the method of operation of, any System

Unit that would give rise to claims resolved by Section XI (Resolution of Claims Against

Minnesota Power).

207. When permits are required as described in Paragraph 205, Minnesota Power shall

complete and submit applications for such permits to the applicable state agency to allow


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sufficient time for all legally required processing and review of the permit request, including

requests for additional information by the permitting authority. Any failure by Minnesota Power

to submit a timely permit application for Minnesota Power System Units shall bar any use by

Minnesota Power of Section XV (Force Majeure) of this Consent Decree, where a claim of a

Force Majeure Event is based on permitting delays.

208. Notwithstanding the reference to Title V Permits in this Consent Decree, the

enforcement of such permits shall be in accordance with their own terms and the Act and its

implementing regulations. The Title V Permits shall not be enforceable under this Consent

Decree, although any term or limit established by or under this Consent Decree shall be

enforceable under this Consent Decree regardless of whether such term has or will become part

of a Title V Permit, subject to the terms of Section XXVII (Termination) of this Consent Decree.

209. Within one hundred eighty (180) Days after the Date of Entry of this Consent

Decree, Minnesota Power shall modify any applicable Title V Permit application(s), or apply for

amendments of its Title V Permits, to include a schedule for the following Unit-specific and

system-specific performance, operational, maintenance, and control technology requirements

established by this Consent Decree: any applicable (a) Emission Rates, together with their

relevant averaging periods, (b) System-Wide Annual Tonnage Limitations, (c) the requirements

pertaining to the prohibition on netting credits or offsets, and the Surrender of SO2 Allowances

and NOx Allowances, (d) requirements related to the Retirement, Refueling, Repowering, or

Rerouting of any Unit as required or elected under this Decree, (e) the coal limitations required

for Rapids Units 5 and 6 under Paragraph 143, (f) PM Control Device requirements in Paragraph

120, (g) requirements to Continuously Operate pollution control technologies, and to optimize

and Continuously Operate combustion controls, (h) the requirements in Paragraph 131, and (i)


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monitoring and testing requirements.

210. Within one (1) year after the Date of Entry of this Consent Decree, Minnesota

Power shall apply to permanently include the requirements and limitations enumerated in this

Consent Decree as federally enforceable requirements in the Title I/Title V permits for the

Boswell, Taconite Harbor, Laskin, and Rapids Energy Centers. Each such application shall

request that the requirements and limitations enumerated in this Consent Decree become and

remain “applicable requirements” as that term is defined in 40 C.F.R. § 70.2 and be marked in

the permit as non-expiring Title I conditions. The federally enforceable permits shall require

compliance with the following: any applicable (a) Emission Rates, together with their relevant

averaging periods, (b) System-Wide Annual Tonnage Limitations, (c) the requirements








211. Minnesota Power shall provide the United States with a copy of each application

for a federally enforceable permit, as well as a copy of any permit proposed as a result of such

application, to allow for timely participation in any public comment opportunity.

212. Prior to termination of this Consent Decree, Minnesota Power shall obtain

enforceable provisions in its Title V permits that incorporate the following Unit-specific and/or

System-wide performance, operational, maintenance, and control technology requirements


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established by this Consent Decree: any applicable (a) Emission Rates, together with their

relevant averaging periods, (b) System-Wide Annual Tonnage Limitations, (c) the requirements








XVIII. INFORMATION COLLECTION AND RETENTION

213. Any authorized representative of the United States or the State, including, but not

limited to their attorneys, contractors, and consultants, upon presentation of credentials, shall

have a right of entry upon the premises of a Minnesota Power System Unit at any reasonable

time for the purpose of:

a. monitoring the progress of activities required under this Consent Decree;

b. verifying any data or information submitted to the United States in accordance

with the terms of this Consent Decree;

c. obtaining samples and, upon request, splits of any samples taken by Minnesota

Power or its representatives, contractors, or consultants; and

d. assessing Minnesota Power’s compliance with this Consent Decree.

214. Minnesota Power shall retain, and instruct its contractors and agents to preserve,

all non-identical copies of all records and documents (including records and documents in

electronic form) that are now in its or its contractors’ or agents’ possession or control, and that


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directly relate to Minnesota Power’s performance of its obligations under this Consent Decree

for the following periods: (a) until December 31, 2024 for records concerning physical or

operational changes undertaken in accordance with Section IV (NOx Emission Reductions and

Controls), Section V (SO2 Emission Reductions and Controls), and Section VI (PM Emission

Reductions and Controls); and (b) until December 31, 2022 for all other records. This record

retention requirement shall apply regardless of any corporate document retention policy to the

contrary.

215. All information and documents submitted by Minnesota Power pursuant to this

Consent Decree shall be subject to any requests under applicable law providing public disclosure

of documents unless (a) the information and documents are subject to legal privileges or

protection, or (b) Minnesota Power claims and substantiates in accordance with 40 C.F.R. Part 2

that the information and documents contain confidential business information.

216. Nothing in this Consent Decree shall limit the authority of EPA to conduct tests

and inspections at the Minnesota Power System Units under Section 114 of the Act, 42 U.S.C.

§ 7414, or any other applicable federal laws, regulations, or permits

XIX. NOTICES

217. Unless otherwise provided herein, whenever notifications, submissions, or

communications are required by this Consent Decree, they shall be made in writing and

addressed as follows:

As to the United States of America: (if by mail service) Chief, Environmental Enforcement Section Environment and Natural Resources Division U.S. Department of Justice P.O. Box 7611, Ben Franklin Station Washington, DC 20044-7611 DJ# 90-5-2-1-09683


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(if by commercial delivery service) Chief, Environmental Enforcement Section Environment and Natural Resources Division U.S. Department of Justice ENRD Mailroom, Room 2121 601 D Street, NW Washington, DC 20004 DJ# 90-5-2-1-09683 and (if by mail service) Director, Air Enforcement Division Office of Enforcement and Compliance Assurance U.S. Environmental Protection Agency Mail Code 2242A 1200 Pennsylvania Avenue, NW Washington, DC 20460 (if by commercial delivery service) Director, Air Enforcement Division Office of Enforcement and Compliance Assurance U.S. Environmental Protection Agency Ariel Rios South Building, Room 1119 1200 Pennsylvania Avenue, NW Washington, DC 20004 and (by mail or commercial delivery service) Director, Air Division U.S. Environmental Protection Agency, Region 5 77 W. Jackson Blvd. (AE-17J) Chicago, IL 60604 As to the MPCA: (if by mail service or commercial delivery service) Steve Palzkill Pollution Control Specialist Air Quality Compliance & Enforcement Minnesota Pollution Control Agency 525 Lake Avenue South, Suite 400 Duluth, MN 55802


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As to MINNESOTA POWER: Minnesota Power Attn: Vice President, Generation 30 W. Superior St. Duluth, MN 55802 and Minnesota Power Attn: General Counsel 30 W. Superior St. Duluth, MN 55802

218. All notifications, communications, or submissions made pursuant to this Section

shall be sent either by: (a) overnight mail or overnight delivery service with signature required

for delivery, or (b) certified or registered mail, return receipt requested. All notifications,

communications, and transmissions sent by overnight, certified, or registered mail shall be

deemed submitted on the date they are postmarked, or, if sent by overnight delivery service, they

shall be deemed submitted on the date they are delivered to the delivery service.

219. Any Party may change its notice recipient or the address for providing notices to

it by serving the other Parties with a notice setting forth such new notice recipient or address.

220. Upon future written agreement of the sending and receiving Parties, notifications,

communications, or submissions required under this Consent Decree may be submitted

electronically in lieu of by mail or commercial delivery service. The Parties will determine the

procedures for electronic submittal at that time.

XX. SALES OR TRANSFERS OF OPERATIONAL OR OWNERSHIP INTERESTS

221. If Minnesota Power proposes to sell or transfer an Operational or Ownership

Interest in its Boswell Energy Center, Laskin Energy Center, Taconite Harbor, and Rapids


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Energy Center to an entity unrelated to Minnesota Power (a “Third Party Purchaser”), Minnesota

Power shall advise the Third Party Purchaser in writing of the existence of this Consent Decree

prior to such sale or transfer, and shall send a copy of such written notification to the United

States and MPCA pursuant to Section XIX (Notices) of this Consent Decree at least sixty (60)

Days before such proposed sale or transfer.

222. No sale or transfer of an Operational or Ownership Interest, whether in

compliance with the procedures of this Section or otherwise, shall relieve Minnesota Power of its

obligation to ensure that the terms of this Consent Decree are implemented, unless (1) the

transferee agrees to undertake all of the obligations required by this Consent Decree that may be

applicable to the transferred or purchased Operational or Ownership Interests, and to be

substituted for Minnesota Power as a Party under the Decree pursuant to Section XXIII

(Modification) as to the applicable requirements of this Consent Decree and thus be bound

thereby, and (2) the United States after consultation with MPCA consents to relieve Minnesota

Power of such obligations. The United States may refuse to approve the substitution of the

transferee for Minnesota Power if it determines that the proposed transferee does not possess the

requisite technical abilities or financial means to comply with the applicable Consent Decree

requirements. Minnesota Power shall provide the United States and MPCA with notice of the

date of the planned sale or transfer of an Operational or Ownership Interest before such sale or

transfer occurs, and shall provide the United States and MPCA a copy of any written agreement

to transfer an Operation or Ownership Interest prior to or within 30 Days after such transfer, in

accordance with Section XX (Notices).

223. This Consent Decree shall not be construed to impede the transfer of any

Operational or Ownership Interests between Minnesota Power and any Third Party Purchaser so


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long as the requirements of this Consent Decree are met. This Consent Decree shall not be

construed to prohibit a contractual allocation as between Minnesota Power and any third party

purchaser of Operational or Ownership Interests of the burdens of compliance with this Consent

Decree. Any transfer of an Operational or Ownership Interest in Minnesota Power’s Boswell

Energy Center, Laskin Energy Center, Taconite Harbor, or Rapids Energy Center without

complying with this Section constitutes a violation of this Consent Decree.

224. Minnesota Power may not assign, and may not be released from, any obligation

under this Consent Decree that is not specific to the purchased or transferred Operational or

Ownership Interests, including the obligations set forth in Sections IX (Environmental Mitigation

Projects) and X (Civil Penalty).

225. Paragraphs 221 through 224 of this Consent Decree do not apply if an

Operational or Ownership Interest is sold or transferred solely as collateral security in order to

consummate a financing arrangement (not including a sale-leaseback), so long as Minnesota

Power: (a) remains the operator (as that term is used and interpreted under the Clean Air Act) of

the subject Unit(s); (b) remains subject to and liable for all obligations and liabilities of this

Consent Decree; and (c) supplies EPA and MPCA with the following certification within thirty

(30) Days of the sale or transfer:

“Certification of Change in Ownership Interest Solely for Purpose of Consummating Financing.

We, the Chief Executive Officer and General Counsel of ALLETE, Inc.

(“Minnesota Power”), hereby jointly certify under Title 18 U.S.C. Section 1001, on our own behalf and on behalf of Minnesota Power, that any change in Minnesota Power’s Ownership Interest in any Unit that is caused by the sale or transfer as collateral security of such Ownership Interest in such Unit(s) pursuant to the financing agreement consummated on [insert applicable date] between Minnesota Power and [insert applicable entity]: a) is made solely for the purpose of providing collateral security in order to consummate a financing arrangement; b) does not impair Minnesota Power’s ability, legally or otherwise, to comply


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timely with all terms and provisions of the Consent Decree entered in United

States v. ALLETE, Inc., et al., Civil Action______; c) does not affect Minnesota Power’s operational control of any Unit covered by that Consent Decree in a manner that is inconsistent with Minnesota Power’s performance of its obligations under the Consent Decree; and d) in no way affects the status of Minnesota Power’s obligations or liabilities under that Consent Decree.”

XXI. EFFECTIVE DATE

226. The effective date of this Consent Decree shall be the Date of Entry.

XXII. RETENTION OF JURISDICTION

227. The Court shall retain jurisdiction of this case after entry of this Consent Decree

to enforce compliance with the terms and conditions of this Consent Decree and to take any

action necessary or appropriate for the interpretation, construction, execution, or modification of

the Consent Decree, or for adjudication of disputes. During the term of this Consent Decree, any

Party to this Consent Decree may apply to the Court for any relief necessary to construe or

effectuate this Consent Decree.

XXIII. MODIFICATION

228. The terms of this Consent Decree may be modified only by a subsequent written

agreement signed by the Parties. Where the modification constitutes a material change to any

term of this Consent Decree, it shall be effective only upon approval by the Court.

XXIV. GENERAL PROVISIONS

229. When this Consent Decree specifies that Minnesota Power shall achieve and

maintain a 30-Day Rolling Average Emission Rate, the Parties expressly recognize that

compliance with such 30-Day Rolling Average Emission Rate shall commence immediately

upon the date specified, and that compliance as of such specified date (e.g., December 30) shall

be determined based on data from that date and the 29 prior Unit Operating Days (e.g.,


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December 1-29).

230. When this Consent Decree specifies (a) that Minnesota Power shall achieve and

maintain a 12-Month Rolling Average Emission Rate by a certain compliance date or (b) that

Minnesota Power shall operate a Rapids Unit to achieve a specified 12-Month Percent Heat Input

from Coal by a certain compliance date, then the Month containing that date if that date is the

first Day of the Month, or if that date is not the first Day of the Month then the next complete

Month, shall be the first Month used in the calculation of the specified 12-Month limitation. For

example, if the specified 12-Month Rolling Average Emission Rate is to be achieved starting

January 1, 2013, then January 2013 is the first Month used in the calculation of the first

applicable 12-Month Rolling Average Emission Rate, such that the first complete 12-Month

Rolling Average Emission Rate period would, provided that the Unit fires Fossil Fuel in each

Month, include January 2013 through December 2013.

231. This Consent Decree is not a permit. Compliance with the terms of this Consent

Decree does not guarantee compliance with all applicable federal, state, or local laws or

regulations. The Emission Rates and removal efficiencies set forth herein do not relieve

Minnesota Power from any obligation to comply with other state and federal requirements under

the Clean Air Act. In any subsequent administrative or judicial action initiated by the United

States for injunctive relief or civil penalties relating to any of the facilities in the Minnesota

Power System as covered by this Consent Decree, Minnesota Power shall not assert any defense

or claim based upon principles of waiver, res judicata, collateral estoppel, issue preclusion, claim

preclusion, or claim splitting, or any other defense based upon the contention that the claims

raised by the United States in the subsequent proceeding were brought, or should have been

brought, in the instant case; provided, however, that nothing in this Paragraph is intended to


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affect the validity of Section XI (Resolution of Claims Against Minnesota Power).

232. Nothing in this Consent Decree shall relieve Minnesota Power of its obligation to

comply with all applicable federal, state, and local laws and regulations, including, but not

limited to, the Clean Water Act and the National Pollutant Discharge Elimination System

(NPDES) implementing regulations, National Ambient Air Quality Standards, the National

Emission Standards for Hazardous Air Pollutants From Coal and Oil-Fired Electric Utility Steam

Generating Units (Utility MACT), and Standards of Performance for Fossil-Fuel-Fired Electric

Utility, Industrial-Commercial-Institutional, and Small Industrial Commercial-Institutional

Steam Generating Units (Utility NSPS). Nothing in this Consent Decree shall be construed to

provide any relief from the emission limits or deadlines for the installation of pollution controls

or the implementation of other pollution control-related measures specified in these regulations.

233. Subject to the provisions in Section XI (Resolution of Claims Against Minnesota

Power), Section XVI (Dispute Resolution), and XIV (Stipulated Penalties), nothing contained in

this Consent Decree shall be construed to prevent or limit the rights of the United States or

MPCA to obtain penalties or injunctive relief under the Act or other federal, state, or local

statutes, regulations, or permits.

234. Each limit and/or other requirement established by or under this Consent Decree

is a separate, independent requirement.

235. Performance standards, emissions limits, and other quantitative standards set by

or under this Consent Decree must be met to the number of significant digits in which the

standard or limit is expressed. For example, an Emission Rate of 0.100 is not met if the actual

Emission Rate is 0.101. Minnesota Power shall round the fourth significant digit to the nearest

third significant digit, or the third significant digit to the nearest second significant digit,


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depending upon whether the limit is expressed to three or two significant digits. For example, if

an actual Emission Rate is 0.1004, that shall be reported as 0.100, and shall be in compliance

with an Emission Rate of 0.100, and if an actual Emission Rate is 0.1005, that shall be reported

as 0.101, and shall not be in compliance with an Emission Rate of 0.100. Minnesota Power shall

report data to the number of significant digits in which the standard or limit is expressed.

236. This Consent Decree does not limit, enlarge, or affect the rights of any Party to

this Consent Decree as against any third parties.

237. This Consent Decree constitutes the final, complete, and exclusive agreement and

understanding among the Parties with respect to the settlement embodied in this Consent Decree,

and supercedes all prior agreements and understandings among the Parties related to the subject

matter herein. No document, representation, inducement, agreement, understanding, or promise

constitutes any part of this Consent Decree or the settlement it represents, nor shall they be used

in construing the terms of this Consent Decree.

238. Each Party to this action shall bear its own costs and attorneys' fees.

XXV. SIGNATORIES AND SERVICE

239. Each undersigned representative of Minnesota Power, the State of Minnesota, and

the Assistant Attorney General for the Environment and Natural Resources Division of the

United States Department of Justice, certifies that he or she is fully authorized to enter into the

terms and conditions of this Consent Decree and to execute and legally bind to this document the

Party he or she represents.

240. This Consent Decree may be signed in counterparts, and such counterpart

signature pages shall be given full force and effect.

241. Each Party hereby agrees to accept service of process by mail with respect to all


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matters arising under or relating to this Consent Decree and to waive the formal service

requirements set forth in Rule 4 of the Federal Rules of Civil Procedure and any applicable Local

Rules of this Court including, but not limited to, service of a summons.

242. Unless otherwise ordered by the Court, the United States agrees that Minnesota

Power will not be required to file any answer or other pleading responsive to the Complaint in

this matter until and unless the Court expressly declines to enter this Consent Decree, in which

case Minnesota Power shall have no less than thirty (30) Days after receiving notice of such

express declination to file an answer or other pleading in response to the Complaint.

XXVI. PUBLIC COMMENT

243. The Parties agree and acknowledge that final approval by the United States and

entry of this Consent Decree is subject to the procedures of 28 C.F.R. § 50.7, which provides for

notice of the lodging of this Consent Decree in the Federal Register, an opportunity for public

comment, and the right of the United States to withdraw or withhold consent if the comments

disclose facts or considerations which indicate that this Consent Decree is inappropriate,

improper, or inadequate. Minnesota Power shall not oppose entry of this Consent Decree by this

Court or challenge any provision of this Consent Decree unless the United States has notified

Minnesota Power, in writing, that the United States no longer supports entry of this Consent

Decree.

XXVII. TERMINATION

244. Once Minnesota Power has:

a. completed the requirements of Sections IV (NOx Emission Reductions and

Controls), V (SO2 Emission Reductions and Controls), VI (PM Emission


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Reductions and Controls), VII (Retire, Refuel, Repower, or Reroute Option and

Fuels and Renewable Energy), and IX (Environmental Mitigation Projects);

b. maintained substantial compliance with this Consent Decree, including

continuous operation of all pollution controls required by this Consent Decree, for

a period of at least 24 months;

c. paid the civil penalty and any stipulated penalties for which demand has been

made under Paragraph 168 as required by this Consent Decree;

d. included the requirements and limitations enumerated in this Consent Decree in

federally enforceable permits, as described in Paragraph 212, such that the

requirements and limitations enumerated in this Consent Decree become and

remain “applicable requirements” as that term is defined in 40 C.F.R. Part 70.2;

and

e. certified that the date of Minnesota Power’s Request for Termination is later than

December 31, 2020,

Minnesota Power may serve upon the United States and the State of Minnesota a

Request for Termination, stating that Defendant has satisfied those requirements,

together with all necessary supporting documentation.

245. Following receipt by the United States and the State of Minnesota of Defendant’s

Request for Termination, the Parties shall confer informally concerning the Request and any

disagreement that the Parties may have as to whether the Defendant has satisfactorily complied

with the requirements for termination of this Consent Decree. If the United States, after

consultation with the State of Minnesota, agrees that the Decree may be terminated, the Parties

shall submit, for the Court’s approval, a joint stipulation terminating the Decree.


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246. If the United States, after consultation with the State of Minnesota, does not agree

that the Decree may be terminated, Defendant may invoke Dispute Resolution under Section

XVI of this Decree. However, Defendant shall not seek Dispute Resolution of any dispute

regarding termination, under Paragraph 197 of Section XVI, until 60 days after service of its

Request for Termination or receipt of an adverse decision from the United States and the State of

Minnesota, whichever is earlier.

XXVIII. FINAL JUDGMENT

247. Upon approval and entry of this Consent Decree by the Court, this Consent

Decree shall constitute a final judgment regarding the Parties.


Signature Page for United States of America and the State of Minnesota v. ALLETE, Inc., d/b/a

Minnesota Power Consent Decree

FOR THE UNITED STATES DEPARTMENT OF JUSTICE: s/ Sam Hirsch_________________ SAM HIRSCH Acting Assistant Attorney General Environment and Natural Resources Division United States Department of Justice s/ David Rosskam______________ DAVID ROSSKAM Senior Counsel Environmental Enforcement Section Environment and Natural Resources Division United States Department of Justice P.O. Box 7611 Washington, DC 20044-7611 (202) 514-3974




FOR THE UNITED STATES DEPARTMENT OF JUSTICE: s/ Andrew M. Luger____________ ANDREW M. LUGER United States Attorney District of Minnesota s/ Friedrich A.P. Siekert_________ FRIEDRICH A. P. SIEKERT Assistant United States Attorney District of Minnesota 600 United States Courthouse 300 South Fourth Street Minneapolis, MN 55415 (612) 664-5697




FOR THE UNITED STATES ENVIRONMENTAL PROTECTION AGENCY: s/ Cynthia Giles______________ CYNTHIA GILES Assistant Administrator Office of Enforcement and Compliance Assurance United States Environmental Protection Agency s/ Phillip A. Brooks____________ PHILLIP A. BROOKS Director, Air Enforcement Division United States Environmental Protection Agency s/ Sara Froikin________________ SARA FROIKIN Attorney-Advisor

United States Environmental Protection Agency 1200 Pennsylvania Ave, N.W. (2242A) Washington, DC 20460




FOR THE UNITED STATES ENVIRONMENTAL PROTECTION AGENCY: s/ Susan Hedman________________ SUSAN HEDMAN Regional Administrator United States Environmental Protection Agency, Region 5 s/ Cynthia N. Kawakami___________ CYNTHIA N. KAWAKAMI Associate Regional Counsel United States Environmental Protection Agency, Region 5 77 W. Jackson Blvd. (C-14J) Chicago, IL 60604




FOR THE STATE OF MINNESOTA: s/ John Linc Stine_______________ JOHN LINC STINE Commissioner Minnesota Pollution Control Agency




FOR ALLETE, INC. D/B/A MINNESOTA POWER: By: s/ Alan R. Hodnik_____________________ Alan R. Hodnik Chief Executive Officer


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APPENDIX A ENVIRONMENTAL MITIGATION PROJECTS

Minnesota Power shall spend at least $4,200,000 implementing approved Environmental Mitigation Projects (“Project” or “Projects”) as described below, and shall comply with the requirements of this Appendix and with Section IX of the Consent Decree (Environmental Mitigation Projects) to ensure that the environmental benefits from those Environmental Mitigation Projects described below that it implements are achieved. Nothing in the Consent Decree or this Appendix shall require Minnesota Power to spend any more than a total of $4,200,000 on Environmental Mitigation Projects. I. Overall Schedule and Budget for Environmental Mitigation Projects

A. Within one hundred twenty (120) days of the Date of Entry, unless otherwise specified by this Appendix, Minnesota Power shall (1) submit proposed plans (“Project Plans”) for the Projects specified in Sections II and III to EPA for review and approval pursuant to Section XIII of the Consent Decree (Review and Approval of Submittals) and in accordance with the deadlines established in this Appendix, and (2) select additional Projects to fund and implement from those presented in Sections IV through VII of this Appendix and submit proposed Project Plans for those projects to EPA for review and approval pursuant to Section XIII of the Consent Decree (Review and Approval of Submittals) and in accordance with the deadlines established in this Appendix. The Projects for which Project Plans are submitted must total at least $4 million in Project Dollars. EPA reserves the right to disapprove any Project should EPA determine, after an analysis of Minnesota Power’s Project Plan and the associated potential environmental impacts that the Project is not consistent with the Consent Decree’s objective to achieve substantial environmental benefits for the Project Dollars expended. If Minnesota Power opts not to submit a Project Plan for a Project described in Sections IV through VII of this Appendix, Minnesota Power will not have any obligations for such Project pursuant to the Consent Decree, including performance, reporting, or closure requirements for that Project, provided that Minnesota Power is otherwise in compliance with the Environmental Mitigation Project requirements of the Consent Decree. Minnesota Power is not required to complete a Project Plan for the Voyageurs National Park Restoration Project described at Section VIII of this Appendix.

B. Minnesota Power may, at its election, consolidate the Project Plans required by

this Appendix into one or more Project Plans.

C. Unless otherwise specified by this Appendix, Minnesota Power may, at its election, spread its payments for Environmental Mitigation Projects over the five-year period commencing upon approval of each Project Plan. Minnesota Power may also accelerate its payments to better effectuate a Project Plan, but Minnesota Power shall not be entitled to any reduction in the nominal amount of the required payments by virtue of the early expenditures. Any funds designated for a specific
