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TECHNICAL REVIEW DOCUMENT For

DRAFT RENEWAL OF OPERATING PERMIT 95OPEP107

Colorado Springs Utilities – Martin Drake Power Plant El Paso County

Source ID 047-0004

November 2016 – February 2018

Operating Permit Engineer: Danielle Walker Operating Permit Supervisor review: Matt Burgett Compliance Monitoring Unit review: Ben Cappa

Jeremy Murtaugh Permitting Manager review: Roland Hea

I. Purpose

This document establishes the basis for decisions made regarding the applicable requirements, emission factors, monitoring plan and compliance status of emission units covered by the renewed Operating Permit for the Martin Drake Power Plant. The previous Operating Permit for this facility was issued on November 1, 2002, was last revised on April 13, 2004 and expired on October 31, 2007. However, since a timely and complete renewal application was submitted, under Colorado Regulation No. 3, Part C, Section IV.C, all of the terms and conditions of the existing permit shall not expire until the renewal operating permit is issued, and any previously extended permit shield continues in full force and operation.

Prior to submittal of the renewal application, the source submitted applications on March 3, 2004 and July 6, 2005 requesting the permit be modified to update the emission equation for the Drake Unit 7 cooling tower and incorporate a technical correction regarding how the amount of circulating water is determined.

This document is designed for reference during the review of the proposed permit by the EPA, the public, and other interested parties. The conclusions made in this report are based on information provided in the original application submitted on December 20, 1995, the renewal application submitted on October 31, 2006, additional information submitted on December 27, 2006; March 3, 2009; March 31, 2009; February 1, 2010; May 9, 2011;July 2, 2012; April 7, 2014; November 10, 2014; November 30, 2015; May 17, 2016; February 16, 2017; June 14, 2017; September 25; 2017; January 5, 2018; January 31, 2018; and February 5, 2018, comments on the draft permit submitted on January 5, 2018, previous inspection reports and various email correspondence, as well as telephone conversations with the applicant. Please note copies of the Technical Review Document for the original permit and any Technical Review Documents associated with subsequent modifications of the original Operating Permit may be found in the Division files as well as on the Division website at www.colorado.gov/cdphe/airTitleV. This narrative is intended only as an adjunct for the reviewer and has no legal standing.

http://www.colorado.gov/cdphe/airTitleV

Colorado Springs Utilities – Martin Drake Power Plant Operating Permit No. 95OPEP107 Technical Review Document – 1st Renewal Operating Permit

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Any revisions made to the underlying construction permits associated with this facility made in conjunction with the processing of this operating permit application have been reviewed in accordance with the requirements of Regulation No. 3, Part B, Construction Permits, and have been found to meet all applicable substantive and procedural requirements. This operating permit incorporates and shall be considered to be a combined construction/operating permit for any such revision, and the permittee shall be allowed to operate under the revised conditions upon issuance of this operating permit without applying for a revision to this permit or for an additional or revised construction permit. This operating permit, consistent with the Title V program and 42 U.S.C. § 7661c(a) and 40 C.F.R. § 70.1(b), consolidates applicable requirements summarized in this Technical Review Document, and does not impose substantive new requirements not otherwise required at Drake.

II. Description of Source

Colorado Springs Utilities (CSU) Martin Drake Power Plant operates an electricity generation facility as defined under Standard Industrial Classification (SIC) code 4911 consisting of two (2) boilers, the associated equipment for coal and ash handling, cooling towers, and lime storage silos. The boilers fire coal as the primary fuel and use natural gas as a supplementary, secondary, and startup fuel. The boilers utilize low-sulfur, sub-bituminous coal and use Flue Gas Desulfurization (FGD) systems to reduce SO2 emissions. The source began construction of Drake Unit 7’s FGD in April 2014 and began construction of Drake Unit 6’s FGD in April 2015. Drake Unit 7’s FGD began testing in February 2016 and Drake Unit 6’s FGD began testing in September 2016. The FGDs were fully operational on November 3, 2017. The boilers are also equipped with fabric filters to reduce particulate emissions and ultra-low NOX burners and over fire air to reduce NOX emissions. The coal and fly ash handling systems are equipped with baghouses to reduce particulate emissions and the coal is treated with water and a solution of water and concentrated surface active compounds to reduce fugitive emissions. The lime storage silos are equipped with dust collectors to reduce particulate emissions.

This facility is located at 700 South Conejos Street in Colorado Springs, El Paso County. This facility is located in an area classified as attainment/maintenance for carbon monoxide (CO). Under that classification, all SIP-approved requirements for CO will continue to apply in order to prevent backsliding under the provisions of Section 110(l) of the Federal Clean Air Act. The facility is located in an area classified as unclassifiable for sulfur dioxide (SO2).The facility is located in an area classified as attainment for all other criteria pollutants. There are no affected states within 50 miles of the facility. There are no Federal Class I designated areas within 100 kilometers of the facility. Florissant Fossil Beds National Monument is a Federal land within 100 kilometers of the facility, the State has designated this area to have the same sulfur dioxide increment as Federal Class I areas.


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The following table summarizes general information for the boilers at the facility:

Drake Unit 6 Drake Unit 7

Placed in Service 1968 1974

Boiler Rating – MMBtu/hr (Coal)

861 1,336

Boiler Rating – MMBtu/hr (Natural Gas)

850 1,310

Electrical Power Rating, Gross Megawatts

85 142

Pollution Control Device Fabric Filter (particulate)

Flue Gas Desulfurization System (SO2)

Ultra-Low NOX Burners and Over Fire Air (NOX)

Fabric Filter (particulate)

Flue Gas Desulfurization System (SO2)

Ultra-Low NOX Burners and Over Fire Air (NOX)

III. Applicable Requirements

Non-Attainment New Source Review (NANSR) and Prevention of Significant Deterioration (PSD)

This facility is categorized as a major stationary source (Potential to Emit > 100 Tons/Year for CO, SO2, NOX, PM, and PM10.) Future modifications at this facility resulting in a significant net emissions increase (see Reg 3, Part D, Sections II.A.27 and 44) for any pollutant as listed in Regulation No. 3, Part D, Section II.A.44 or a modification which is major by itself (i.e. a Potential to Emit of > 100 TPY of any pollutant listed in Regulation No. 3, Part D, Section II.A.44) may result in the application of the PSD review requirements.


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Criteria Pollutant Emissions at the facility are as follows:

Source Potential to Emit (PTE) and Permitted Emissions (tpy)

NOx VOC CO SO2 PM PM10 PM2.5

Point 005 – Drake Unit 61,2,3 (Coal)

1,170 11 307 490.3 113 113

Point 006 – Drake Unit 71,2,3 (Coal)

1,697 18 340 760.7 175.6 175.6

Point 007 – Coal Handling, Train to Stockpile2 14.14 7.07

Point 019 – Flyash Handling4 7.1 3.6 Point 017 – Unit 6 Cooling Tower1 0.31 2.18 1.09

Point 018 – Unit 7 Cooling Tower1 0.34 267.55 133.77

Point 023 – Coal Crushing4 2.3 0.7 Point 025 – Lime Storage Silos4 1.3 1.3 0.7

Facility Wide Limitations 1,995 GEN 110 – Emergency Gen5 1.3 0.11 0.29 0.09 0.09 0.09 0.09

Total Maximum Emissions 2,868.3 29.8 647.3 1,995 313.5 571.1 135.7 Notes: 1 Emissions of VOC and CO for Point 005 and 006 and emissions of VOC, PM10, and PM2.5 for Point 017 and

018 are based on Potential to Emit, these units do not have a permit limit. 2 Emissions of NOX, SO2, and PM are based on the permitted emission rates and the maximum design rate of each boiler.

3 Emissions of NOX, VOC, CO, SO2, PM, PM10, and PM2.5 above are calculated using coal as the primary fuel to display the most conservative emissions. The Potential to Emit from each boiler using natural gas as the primary fuel is as follows: Drake Unit 6, NOX – 1,154.1 tpy, VOC – 20.1 tpy, CO – 306.6 tpy, SO2 – 2.2 tpy, PM/PM10/PM2.5 – 27.7 tpy; Drake Unit 7 – NOX – 1,778.7 tpy, VOC – 30.9 tpy, CO – 427.5 tpy, SO2 – 3.4 tpy, PM/PM10/PM2.5 – 42.8 tpy. Emissions are calculated using the BART emission limitation for NOX and using emission factors from AP-42, Chapter 1.4 for VOC, CO, SO2, and PM/PM10/PM2.5.

4 Emissions are based on permitted levels. 5 Emissions are based on Potential to Emit at 500 hours per year of Operation per 1995 EPA Memo, emissions are APEN exempt.

Source 2016/2017 Actual Emissions (tpy)

NOx VOC CO SO2 PM PM10 PM2.5

Point 005 – Drake Unit 66 555.5 8.3 192.0 81.6 3.5 3.5 1.8 Point 006 – Drake Unit 76 1,016.4 14.4 246.5 254.4 12.7 12.7 6.3 Point 007 – Coal Handling, Train to Stockpile7 12.5 6.3 6.1

Point 019 – Flyash Handling7 1.8 0.9 0.9 Point 017 – Unit 6 Cooling Tower7

0.3 2.3 1.1 0.9

Point 018 – Unit 7 Cooling Tower7

0.3 1.0 0.5 0.4

Point 023 – Coal Crushing7 1.5 0.5 0.2 Point 025 – Lime Storage Silos7

0.16 0.16 0.09

Notes: 6 Emissions for Point 005 and 006 in the table above are actual emissions from the data year 2017. 7 Emissions for Point 007, 019, 017, 018, 023, and 025 in the table above are actual emissions from the data year 2016.

Emissions from the potential to emit and permitted emission table above are based on permitted emission levels for criteria pollutants and the potential to emit from emission units that are grandfathered from permit limits. Actual emissions of NOX and SO2 for Drake Unit 6 and Drake Unit 7 are from the Acid Rain Program Air Markets Program Data and the VOC, CO, PM, PM10, and PM2.5 emissions provided by the source for the

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year 2017. Please note actual emissions from all other points besides Drake Unit 6 and Drake Unit 7 are from the Division’s inventory system for the year 2016.

Accidental Release Program – 112(r)

Based on the information provided by the applicant, this facility is not subject to the provisions of the Accidental Release Prevention Program (Section 112(r) of the Federal Clean Air Act).

Compliance Assurance Monitoring (CAM)

The following emission points at this facility use a control device to achieve compliance with an emission limitation or standard to which they are subject and have pre-control emissions that exceed or are equivalent to the major source threshold. They are therefore subject to the provisions of the CAM program as set forth in 40 CFR Part 64 as adopted by reference into Colorado Regulation No. 3, Part C, Section XIV:

Point 005 – Drake Unit 6 Boiler for Particulate Matter Point 006 – Drake Unit 7 Boiler for Particulate Matter

Drake Unit 6 and Drake Unit 7 have uncontrolled emissions of NOX that exceed major source thresholds. Both units are equipped with low NOX burners and over fire air to reduce NOX emissions. Pursuant to the definition of control device in 40 CFR Part 64, §64.1, it states “…For the purposes of this part, a control device does not include passive control measures that act to prevent pollutants from forming, such as the use of seals, lids, or roofs to prevent the release of pollutants, use of low-polluting fuel or feedstocks, or the use of combustion or other process design features or characteristics”. The low NOX burners and over fire air are not considered control devices for the purposes of CAM applicability; see Federal Register, Volume 62, No. 204, Page 54913 for more information. Most emission units equipped with low NOX burners and over fire air already have separate requirements for the use of a CEMS in the operating permit and are considered in certifying compliance with applicable requirements.

Drake Unit 6 and Drake Unit 7 have uncontrolled emissions of SO2 that exceed major source thresholds. Both units have emission limitations for SO2 under the Acid Rain Program (Section V of the Operating Permit). Pursuant to 40 CFR Part 64 §64.2(b)(1)(iii), the CAM requirements do not apply to emission limitations under the Acid Rain Program. Both units also have emission limitations for SO2 under Colorado Regulation No. 3, Part F, Regional Haze Limits – Best Available Retrofit Technology (BART). Pursuant to 40 CFR Part 64, §64.2(b)(1)(vi), the CAM requirements do not apply to emission limitations or standards for which a Part 70 or 71 permit specifies a continuous compliance determination method, as defined in §64.1. In the current Title V permit, both units are subject to short-term Colorado Regulation No. 1 Sulfur Dioxide limitations and the current Title V permit requires the permittee use the SO2 CEMS to monitor compliance with the limitations. It also requires the permittee use the SO2 CEMS to determine annual emissions for purposes of APEN reporting and fees.


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Drake Unit 6 and Drake Unit 7 have uncontrolled emissions of particulate matter that exceed major source thresholds and use control devices to meet the particulate matter emission limitations. Both units are subject to the Colorado Regulation No. 3, Part F, Regional Haze Limits – Best Available Retrofit Technology (BART) particulate limits and are subject to CAM pursuant to Colorado Regulation No. 3, Part C, Section XIV and Part F, Section VII.C.1. Both units are also subject to the Colorado Regulation No. 1, Section II.A.1 and II.A.4 opacity limitations however, the Colorado Regulation No. 1 opacity limitations are not emission limitations that are subject to CAM.

CSU submitted a CAM plan for the baghouses (fabric filters) that control Particulate Matter for Drake Unit 5, Drake Unit 6, and Drake Unit 7 along with their renewal application on October 31, 2006. The source submitted three different CAM plans for each emission unit for the Colorado Regulation No. 1, particulate matter limitation. The Division has combined the CAM plans for Drake Unit 6 and 7 into one plan in Appendix H. The CAM Plan for Drake Unit 5 was not included in the Operating Permit since Drake Unit 5 was retired on December 31, 2016. Since the CAM plan was submitted, the Colorado Regulation No. 1 particulate matter limitations have been streamlined from the Operating Permit in place of MACT UUUUU and now each unit is using a control device to achieve compliance with the Regional Haze requirements. The source identified performance indicators of visible emissions, pressure differential, and daily baghouse inspections. The Division’s review of the CAM plan is as follows:

Visible Emissions

The source will continuously monitor visible emissions with a Continuous Opacity Monitoring System (COMS). An excursion is defined as an opacity value that exceeds 10%. Based on the relationship between particulate matter and opacity, an increase in opacity or visible emissions corresponds to a decrease in baghouse (fabric filter) performance and an increase in particulate emissions. Note the CAM plan submitted by the source was updated by the Division to include a reference to 40 CFR Part 75 under the Performance Criteria, QA/QC Practices and Criteria (III.c) in addition to 40 CFR Part 60 and the Data Collection Procedures and Averaging Period under Performance Criteria (III.e and III.f) were modified to include a reference to 40 CFR Part 60, Subpart A, §60.13.

Pressure Differential

The source requested to monitor the pressure differential as an indicator with an excursion defined as a pressure drop outside of the established range of 5.5 to 8.5 inches of water. The Division has determined it is difficult to determine a specific indicator range for pressure differential and it is not necessarily an indicator of decreased baghouse performance itself. An increase or decrease in the pressure differential from normal level accompanied by a sustained increase in opacity is an indication of potential baghouse problems. The Division has not included pressure differential in the CAM plan as an indicator. The Division believes the opacity monitoring in the plan is appropriate for CAM and does not believe it is necessary to include pressure differential as an additional indicator.

Daily Baghouse Inspections


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The source will conduct daily inspections of the baghouse as an indicator with an excursion defined as detection of a mechanical or operational problem or failure to perform the inspection for two consecutive days. The daily baghouse inspections have replaced the pressure differential in the plan as a second indicator. Daily inspections will consist of checking the ash silo, baghouse valves, compartment vents, fans, switches, and bypass dampers.

The CAM Plan has been included in Appendix H of the permit as submitted for particulate matter except for the revisions indicated above and some language revisions, removal or relocation.

All other emission units at the facility have uncontrolled emissions less than major source thresholds and are not subject to the provisions of CAM.

Hazardous Air Pollutants (HAPs)

This facility is a major source for Hazardous Air Pollutants. Emissions of individual HAPs exceed 10 tons per year and emissions of total HAPs exceed 25 tons per year. This facility is a major source of HAP emissions for the purposes of 40 CFR Part 63, Subpart UUUUU and Subpart ZZZZ.

Potential Emissions and Actual Emissions of Hazardous Air Pollutants at the facility are as follows:

Source Potential HAP Emissions (tpy)

HCl1 HF1 Non-Hg Metals2

Organic HAPs3

Chloroform4

Point 005 – Drake Unit 6 254.24 31.75 0.69 8.77 Point 006 – Drake Unit 7 394.5 49.3 1.10 13.54 Point 017 – Drake Unit 6 Cooling Tower

0.73

Point 018 – Drake Unit 7 Cooling Tower

0.90

Total 648.74 81.05 1.79 22.31 1.63

Notes: 1 Hydrogen Chloride and Hydrogen Fluoride emissions were estimated using emission factors from AP-42, Table 1.1-15.

2 Non-Hg Metals emissions were estimated using emission factors from AP-42, Table 1.1-18 for coal combustion. Non-Hg Metals include emissions of Aresnic, Chromium compounds, Lead, Maganese, Nickel, and Selenium.

3 Organic HAPs emissions were estimated using emission factors from AP-42, Tables 1.1-13 and 1.1-14 for coal combustion and Table 1.4-4 for natural gas. Organic HAPs include emissions of Acetaldehyde, Acrolein, Benzene, Benzyl chloride, Carbon disulfide, Cyanide, Isophorone, Methyl bromide, Methyl chloride, Methyl ethyl ketone, Methyl hydrazine, Methylene chloride, Formaldehyde (natural gas), and Hexane (natural gas).

4 Chloroform emissions were estimated using emission factors established from Wayne C. Micheletti to Tristate Generation and Transmission Association on November 11, 1992.

Source Actual 2016 HAP Emissions (tpy)

HCl HF Non-Hg Metals

Organic HAPs

Chloroform

Point 004 – Drake Unit 5 0.003 0.05 0.003 Point 005 – Drake Unit 6 1.9 8.8 0.5 Point 006 – Drake Unit 7 3.4 15.8 0.8


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0.3


0.3

Total 5.3 24.6 1.3 0.6

The potential HAP emissions are based on the facilities potential to emit. Actual emissions are from the Division’s inventory system for the year 2016. Please note in the year 2016 Drake Unit 5 (Point 004) was still in operation; this unit was decommissioned on December 31, 2016. Emissions from Drake Unit 5 have been included in the 2016 Actual Emissions table and have not been included in the Potential HAP Emissions table because no emissions will be produced from this unit going forward.

Colorado Regulation No. 6, Part B, Section VIII, Standards of Performance for Coal-Fired Electric Steam Generating Units

On October 18, 2007 mercury requirements for electric utility steam generating units were adopted by the Colorado Air Quality Control Commission (AQCC), the requirements were included in the Colorado Regulations under Colorado Regulation No. 6, Part B, Section VIII to specify mercury emission limitations for coal fired utility steam generating units. On February 19, 2015, the Division adopted revisions to the Colorado Regulation No. 6, Part B, Section VIII requirements that align the state-only mercury requirements with the federal mercury requirements for coal-fired electric steam generating units (EGUs). In 2012 EPA promulgated the Mercury and Air Toxics Standards (MATS) (40 CFR Part 63, Subpart UUUUU) which addresses mercury emission limits, work practice standards, monitoring, recordkeeping, and reporting requirements for new and existing affected coal-and oil-fired EGUs. The Commission has aligned the state-only provisions of Colorado Regulation No. 6, Part B, Section VIII with the related provisions in Subpart UUUUU.

Colorado Regulation No. 6, Part B, Section VIII is a state only mercury requirement for electric steam generating units. Drake Unit 6 and 7 are each considered an existing low emitter under Section VIII. An existing unit is defined in Section VIII.B.4 as “an Hg Budget Unit that commenced operation prior to January 1, 2001”. Drake Unit 6 commenced operation in 1968 and Drake Unit 7 commenced operation in 1974. A low emitter is defined under Section VIII.B.10 as “an Hg budget unit with actual Hg emissions of no more than 29 pounds per year, as determined by data collected through the required Hg monitoring pursuant to 40 CFR Part 63, Subpart UUUUU as incorporated by reference into Colorado Regulation No. 8, Part E”. Drake Unit 6 and 7 have actual Hg emissions lower than 29.0 pounds per year at the time of this permit issuance. Drake Unit 5 has been decommissioned at the time of this permit issuance and is not subject to these requirements.

Low emitter units were required to submit a complete permit application to the Division to incorporate the applicable requirements of Section VIII by July 1, 2012. The Martin Drake Power Plant’s permit application was received by the Division prior to July 1, 2012.


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Low emitter status is demonstrated through the required Hg monitoring pursuant to 40 CFR Part 63, Subpart UUUUU. Low emitter units are required to comply with the Hg monitoring and recordkeeping requirements of 40 CFR Part 63, Subpart UUUUU, pursuant to Colorado Regulation No. 6, Part B, Section VIII.E.3.

40 CFR Part 51, Subpart BB – Data Requirements Rule

The Data Requirements Rule (DRR) was published in the Federal Register on August 21, 2015. The DRR was established for air agencies to characterize the air quality around large SO2 sources that emit 2,000 tons per year or greater. Air agencies were required to identify applicable sources based on the most recently available annual SO2 emissions data for each source. Under the DRR, states have three options to characterize the current air quality in areas with large SO2 sources: (1) establish a federally enforceable requirement to limit SO2 to under 2,000 tons per year by January 13, 2017, (2) conduct air quality modeling by January 13, 2017, (3) begin operating an appropriate monitoring network by January 1, 2017.

The DRR required the Division to submit a list of sources to EPA by January 15, 2016 that identifies all the applicable SO2 sources. Colorado Springs Utilities, Martin Drake Power Plant had emissions that exceeded 2,000 tons per year of SO2 in 2014 and was included in the January 15, 2016 submittal to EPA. To demonstrate compliance with the DRR, the Division established a facility-wide, federally enforceable limitation to less than 2,000 tons per year of SO2 for the Martin Drake Power Plant which was federally enforceable by January 13, 2017.

Under Colorado Regulation No. 3, Part B, Section II.A.7 it states: “A source that is voluntarily applying for a permit to create state-only or federally enforceable permit conditions, as appropriate, to limit the potential to emit criteria, pollutants, GHG or hazardous air pollutants may request to obtain such limits in a construction permit.” Colorado Springs Utilities voluntarily requested a facility wide SO2 emission limit for the Martin Drake Power Plant below 2,000 tons per year in the initial construction permit application on May 23, 2016 with an application update submitted on August 22, 2016. The Division established the federally enforceable limitation through issuance of Construction Permit 10EP402 on December 27, 2016.

By July 1, 2016, the Division was required to submit to EPA “a description of the planned emission limitation, including identification of the level of the limitation being planned” for the sources from the January 15, 2016 list. This submittal included a description of the SO2 emission limitation for the Martin Drake Power Plant.

Colorado Springs Utilities, Martin Drake Power Plant has a federally enforceable facility-wide emission limitation for SO2 of 1,995 tons per year. This limitation was effective starting January 13, 2017 and thereafter. This emission limitation results in about 50% less actual SO2 emissions based on the 2015 actual emissions and about 90% less potential to emit emissions in the future. In 2018, the Potential to Emit of SO2 emissions has been reduced to 1,430 tons per year once the Colorado Regulation No. 3 Regional Haze Limits became effective.

To ensure compliance with the emission limitations, monthly and annual records of the emission rates shall be maintained by the applicant and made available to the Division


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for review upon request. Note the monthly emission limitations included in Construction Permit 10EP402 were only required for the first twelve (12) months of operation while the annual limit is effective for calendar year 2017 and thereafter. The monthly limitations did not directly correspond to the annual limitation and since the monthly limitations were only required for the first twelve months of operation, they were not included in the Operating Permit. The Martin Drake Power Plant is limited to the annual emission limitations. Compliance with the annual emissions of SO2 shall be determined by recording the facility’s annual emissions for SO2 on a rolling twelve (12) month total starting with January 2017. After twelve (12) months of data are collected, i.e. after December 2017, the twelve (12) month rolling average will be compared to the 1,995 tons per year SO2 limit. By the end of each month thereafter a new twelve month total shall be calculated based on the previous twelve month’s data.

Per the January 5, 2017 source comments, actual monthly emissions of Sulfur Dioxide for Drake Unit 6 and Drake Unit 7 are as follows:

Cumulative SO2 Emissions for 2017

Month Point 005

Drake Unit 6 Point 006

Drake Unit 7

January 8.5 120.9 February 3.0 10.2

March 3.8 10.5 April 3.6 7.6 May 3.8 12.2 June 3.4 6.3 July 4.1 6.6

August 6.5 10.1 September 22.3 32

October 5.1 5.9 November 14.5 19.9 December 3.1 6.8

Total YTD1 81.7 249

Notes: 1 Emissions of SO2 in the table above show emissions monitored using the CEMS. For the purposes of monitoring emissions for the DRR emission limitation, the CEMS complies with the 40 CFR Part 75 monitoring and recordkeeping requirements with the exception of the CEMS bias adjustment requirements. Emissions shown above may differ from the 2017 SO2 emissions reported through the Acid Rain Program Air Markets Program Data that are shown in the Criteria Pollutant Emissions Section above.

Note the rolling twelve month total requirement began on January 1, 2017. The calculation shall not include emissions data prior to January 1, 2017 because the emission controls used to comply with the new emission limit will not be in long-term testing mode on both Drake Units 6 and 7 until after January 1, 2017.

Compliance with the SO2 emission limitation will be monitored using the Continuous Emission Monitoring System (CEMS). The CEMS requirements are specified in the Operating Permit.


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Colorado Regulation No. 3, Part F – Regional Haze Limits – Best Available Retrofit Technology (BART) and Reasonable Progress (RP)

The Regional Haze Limits were adopted by the Colorado Air Quality Control Commission (AQCC) into Colorado Regulation No. 3, Part F in January 2011. The Regional Haze Limits apply to existing stationary facilities (BART eligible sources). An existing stationary facility is a source that is listed in Colorado Regulation No. 3, Part F, Section II.I and was not in operation prior to August 7, 1962 and was in existence on August 7, 1977 and has the potential to emit of 250 tons per year or more of any visibility impairing air pollutant (SO2, NOX, and particulate matter). In regards to particulate matter, PM10 will be used as the indicator because emissions of PM10 include the components of PM2.5 as a subset. The Martin Drake Power Plant falls under the listed source in Section II.I.1 for fossil-fueled fired steam electric plants of more than 250 million British thermal units per hour heat input that generate electricity for sale.

Drake Unit 6 and 7 are subject to the NOX, SO2, and particulate limitations under Colorado Regulation No. 3, Part F, Regional Haze Requirements, Best Available Retrofit Technology. The 30-day public comment period for the Martin Drake Power Plant Regional Haze Compliance Schedule closed on January 16, 2015. The Division finalized the specific compliance dates on March 16, 2015. Drake Unit 6 and 7 at the Martin Drake Power Plant are required to demonstrate compliance with the NOX, SO2, and particulate emission limitations as follows:

Pollutant Emission Limitation Compliance Date

NOX Drake Unit 6 - 0.31 lbs/MMBtu (30-day rolling average)

Drake Unit 7 – 0.29 lbs/MMBtu (30-day rolling average)

December 31, 2014

SO2 Drake Unit 6 - 0.13 lbs/MMBtu (30-day rolling average)

Drake Unit 7 – 0.13 lbs/MMBtu (30-day rolling average)

December 31, 2017

Particulate Drake Unit 6 - 0.03 lbs/MMBtu Drake unit 7 – 0.03 lbs/MMBtu

November 4, 2013

The Division received the Compliance Demonstrations for Drake Units 5, 6, and 7 for the NOX and Particulate emission limitations in February 2015 and May 2013. The Division received the Compliance Demonstration for the Drake Units 5, 6, and 7 for the SO2 emission limitations on November 3, 2017. To demonstrate initial compliance with the emission limitations for SO2, the facility used data from the CEMS from October 3, 2017 – November 2, 2017. The calculation results from October 3, 2017 – November 2, 2017 were as follows: Drake Unit 5 – 0.0 lbs/MMBtu, Drake Unit 6 – 0.021 lbs/MMBtu, and Drake Unit 7 – 0.016 lbs/MMBtu.

The appropriate monitoring/compliance and recordkeeping and reporting requirements from Colorado Regulation No. 3, Part F have been included in the Operating Permit. Colorado Regulation No. 3, Part F, Section VII.C.1 specifies the Monitoring/Compliance Determination: Particulate Regional Haze Limits for all boilers. Section VII.C.1 includes a requirement for annual performance testing except if (1) if any test results indicate emissions are less than or equal to 50% of the emission limit,


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another test is required within five years; (2) if any test results indicate emissions are more than 50%, but less than or equal to 75% of the emission limit, another test is required within three years; and (3) if any test results indicate emissions are greater than 75% of the emission limit, an annual test is required until the provisions of (1) or (2) are met. The performance testing requirements of Section VII.C.1 have been streamlined out in place of the more stringent performance testing requirements of 40 CFR Part 63, Subpart UUUU. Please see Section IX, Streamlining Conditions, below for more detail.

Please note the Regional Haze Requirements for Drake Unit 5 has not been included in the Operating Permit because this unit permanently shut down on December 31, 2016.

40 CFR Part 63, Subpart UUUUU – National Emission Standards for Hazardous Air Pollutants: Coal and Oil Fired Electric Utility Steam Generating Units (Mercury and Air Toxics Standards (MATS) Rule)

The final rule for 40 CFR Part 63, Subpart UUUUU was last revised in the Federal Register on April 6, 2017. In August 2016 the April 2016 revisions of Subpart UUUUU were adopted by the Colorado Air Quality Control Commission (AQCC) into Colorado Regulation No. 8, Part E. This subpart applies to all coal or oil fired Electric Utility Steam Generating Units (EGU). An EGU under Subpart UUUUU is defined as “a fossil fuel-fired combustion unit of more than 25 megawatts electric (MWe) that serves a generator that produces electricity for sale. A fossil fuel-fired unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 MWe output to any utility power distribution system for sale.” Drake Unit 6 and Drake Unit 7 are defined as existing coal fired EGUs designed to burn coal with a heating value greater than or equal to 8,300 Btu/lb under Subpart UUUUU. To classify as an existing EGU, the EGU must have commenced construction on or before May 3, 2011. Drake Unit 6 was placed in service in 1968 and Drake Unit 7 was placed in service in 1974. The initial notification as required in §63.10030(b) was received by the Division on August 14, 2012. Existing EGUs are required to be in compliance with this subpart no later than April 16, 2015. The Division received a request for a one year extension to comply with the provisions of Subpart UUUUU on March 7, 2014, the compliance extension was not granted by the Division. The initial performance testing was completed for Filterable Particulate Matter (PM), Hydrogen Chloride (HCl), and Mercury (Hg) for Drake Unit 6 on September 22, 2015 and for Drake Unit 7 on August 28, 2015. The notification of compliance was received by the Division for PM, HCl, and Hg on October 13, 2015. The notification was received by the Division for SO2 on January 25, 2018.

For existing coal-fired EGUs, Subpart UUUUU regulates mercury, HCl as a surrogate for acid gas HAP with an alternate of SO2 as a surrogate for acid gas HAP if the facilities EGU is equipped with an FGD system, and filterable PM as a surrogate for non-mercury HAP metals with total non-mercury HAP metals and individual non-mercury HAP metals as alternative equivalent standard. All standards are listed in Table 2 to Subpart UUUUU and work practice standards for existing coal-fired EGUs are listed in Table 3 to Subpart UUUUU.


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Currently Drake Unit 6 and 7 are complying with the filterable particulate matter emission limitation with quarterly stack testing (including Low Emitting EGU qualification upon collection of three years of data), sulfur dioxide limitation with CEMS, and the mercury emission limitation with annual 30-day stack test to demonstrate compliance with the Low Emitting EGU provisions. They are not currently utilizing a neural net combustion optimization system and are required to conduct tune-up work practices once every 36 months. The initial tune-ups for Drake Unit 6 and 7 were completed on December 31, 2014 and again for Drake Unit 6 on November 29, 2017 and Drake Unit 7 on December 7, 2017.

Previously CSU was complying with the HCl emission standard, once compliance with the Regional Haze limitation for SO2 was certified, they transitioned to complying with the alternate SO2 standard listed in Table 2 instead of the HCl standard that required quarterly stack testing. Compliance with the SO2 standard is monitored using the SO2 CEMS and they maintain the CEMS according to 40 CFR Part 75, Continuous Emission Monitoring.

CSU is relying on paragraph (1) in the definition of “startup” for Boilers in §63.10042 – specified in Notification of Compliance Status received on 10/13/2015.

A request to incorporate the applicable requirements associated with 40 CFR Part 63, Subpart UUUUU in to the Operating Permit 95OPEP107 was received by the Division on May 17, 2016.

40 CFR Part 63, Subpart A – General Provisions

Since Drake Unit 6 and 7 are subject to 40 CFR Part 63, Subpart UUUUU, they are subject to 40 CFR Part 63, Subpart A, General Provisions. The applicable general provisions have been included in the operating permit and are discussed in detail of Table 9 to 40 CFR Part 63, Subpart UUUUU.

Since GEN 110, the diesel fired emergency generator, is subject to 40 CFR Part 63, Subpart ZZZZ, it is subject to 40 CFR Part 63, Subpart A, General Provisions. The applicable general provisions have been included in the operating permit and are discussed in detail in §63.6665 and Table 8 to 40 CFR Part 63, Subpart ZZZZ.

40 CFR Part 63, Subpart ZZZZ – National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines (RICE)

The final rule for Subpart ZZZZ was initially published in the Federal Register on June 15, 2004. The requirements in the Operating Permit reflect the most current rule language published in the Federal Register on February 27, 2014. Subpart ZZZZ applies to stationary RICE located at a major or area source of HAP emissions.

On January 18, 2008, Subpart ZZZZ was revised in Federal Register to include requirements for existing stationary compression ignition reciprocating internal combustion engines that are either located at an area source of HAPs or have a site rating less than or equal to 500 HP and are located at a major source of HAPs.

Under Subpart ZZZZ, the Martin Drake Power Plant is defined as a major source of HAP emissions. GEN 110 is defined as an existing emergency compression ignition


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(CI) engine less than 500 HP located at a major source of HAPs. GEN110 was put in service in 1997 and was manufactured in September 1992. Stationary RICE with a site rating less than or equal to 500 brake HP located at a major source of HAP emissions are considered existing if you commenced construction or reconstruction of the stationary RICE before June 12, 2006. GEN 110 was required to be incompliance with all requirements by May 3, 2013. Under §63.6602 and Table 2c to Subpart ZZZZ all existing emergency stationary CI RICE located at a major source of HAPs are required to change oil and filter every 500 hours of operation or annually, whichever comes first; inspect air cleaner every 1,000 hours of operation or annually, whichever comes first, and replace as necessary; and inspect all hoses and belts every 500 hours of operation or annually, whichever comes first, and replace as necessary.

The requirements included in Section II, Condition 9 are federally enforceable only. As of the date of the renewal permit issuance, the applicable requirements of 40 CFR Part 63, Subpart ZZZZ have not been adopted into the Colorado Regulation No. 8, Part E by the Division and are therefore not state-enforceable. In the event the Division adopts the requirements, the requirements will become state-enforceable.

40 CFR Part 60, Subpart OOO – Standards of Performance for Nonmetallic Mineral Processing Plants

The New Source Performance Standards (NSPS) for Nonmetallic Mineral Processing Plants apply to new, modified, and reconstructed facilities in nonmetallic mineral processing plants. This subpart applies to the following affected facilities in fixed or portable nonmetallic mineral processing plants: each crusher, grinding mill, screening operation, bucket elevator, belt conveyor, bagging operation, storage bin, enclosed truck or railcar loading station. The Drake Power Plant receives pebble lime and soda ash (sodium carbonate), which are used in the SO2 scrubbers for Drake Unit 6 and 7. A by-product of this process is gypsum. The definition of nonmetallic mineral in NSPS OOO includes limestone, sodium carbonate, and gypsum (natural or synthetic). Pebble lime is the product of the calcination of limestone and does not fall under the definition of a nonmetallic mineral in NSPS OOO. The sodium carbonate and gypsum are considered nonmetallic minerals per NSPS OOO; however, the provisions of NSPS OOO do not apply to wet material processing operations. Drake meets the definition of a wet material processing operation (§60.671) and is not subject to the provisions of NSPS OOO.

IV. Modifications Requested by the Source

The source submitted the following information to be incorporated into the renewal of the Operating Permit.

The renewal application received on October 31, 2006 requested the following modifications:

Section I, Condition 1 – Addition of clarifying statement regarding the nameplate rating of the boilers.

Section I, Condition 1 – Update attainment designations for the area in which the plant is located.


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Section I, Condition 1 – Removal of Permit 02EP0253 from permitted activities, this source has been removed from the plant.

Section I, Condition 5 – Update Compliance Assurance Monitoring (CAM) language for applicable and non-applicable units.

Section I, Condition 6 – Removal of AIRS Stack Number 022 – Temporary Coal Crushing System – 02EP0253.

Section II, Condition 2.4.2 – Revise standard stack testing language.

Section II, Condition 3.3.1, 3.3.2, and 3.3.5 – Rephrase language to include masonry block walls and wet suppression systems were installed.

Section II, Condition 4.3 – Change the visible emission monitoring frequency from daily to weekly for the coal handling grandfathered sources.

Section II, Condition 5.4.1 – Change the visible emission monitoring frequency from weekly to monthly for the flyash handling system.

Section II, Condition 6.1 – Revise the language of how total water circulated is monitored.

Section II, Condition 6.3 – Update Drake Unit 7 Cooling Tower’s emission factor from 0.002 gal drift/gal water circulated to 0.00002 gal drift/gal water circulated to accurately reflect the installed drift eliminator technology.

Section II, Condition 7.4.2 – Revise the Continuous Opacity Monitoring (COM) System language to specify the COM only needs to be calibrated when the unit is operating.

Section II, Condition 10.1 – Revise reporting langue to officially confirm the dates of when reports are due to the Division.

Section II, Condition 11 – Add the coal sampling/testing plan to the permit.

Section II, Condition 12 – Remove Temporary Coal Crushing/Conveyor system from the permit, this point has been removed from the plant.

Section V, Acid Rain – Update designated representative and alternate designated representative to M. Thomas Black and David Padgett.

Section V, Acid Rain – Update the Sulfur Dioxide Emission Allowances and Nitrogen Oxide Emissions Limitations table to reflect the next permit term.

Appendix B – Removal of Temporary Coal Crushing System/Handling System from the Monitoring and Permit Deviation Reporting Table.

Appendix C – Removal of Temporary Coal Crushing System/Handling System from the Annual Compliance Certification Report.


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Appendix E – Addition of Compliance Assurance Monitoring (CAM) to the Permit Acronyms.

The minor modification received on March 3, 2004 requested the following modifications:

Update to emission equation for Drake Unit 7 Cooling Tower to reflect current emissions at the facility.

Technical correction for how amount of circulating water in cooling towers is determined.

Request to use reclaimed waste water as make-up to the cooling towers.

The minor modification received on July 6, 2005 requested the following modifications:

Section II, Condition 6.1 – Revise how total water circulated is determined.

Section II, Condition 6.3 – Update PM emission equation for Drake Unit 7 Cooling Tower.

Request to use reclaimed waste water as make-up to the cooling towers.

The revision of Certificate of Representation forms for the Martin Drake Power Plant received on December 27, 2006 requested the following:

Change the Designated Representative for the Acid Rain Program from Jerome A. Forte to M. Thomas Black.

The significant modification received on March 3, 2009 requested the following modifications:

Section I, Condition 3.3 – Request for operational flexibility to allow for application of water as a dust suppressant.

The significant modification received on March 31, 2009 requested the following modifications:

Section I, Condition 1.1 – Addition of language specifying Drake Unit 5 and 6 can use a coal/woody biomass blend as fuel.

Section II, Condition 2 – Addition of Coal/woody biomass blend to title of section.

Section II, Condition 2.1 – Addition of coal/woody biomass blend for Drake Unit 5 and 6 where the condition references the type of fuel burned.

The administrative permit amendment received on February 1, 2010 requested the following:

Update the facility contact and responsible official to Kevin Weiner and Bruce McCormick.


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The minor modification received on May 9, 2011 requested the following modifications:

Section II, Condition 6.2 – Request to update the drift value for Drake Unit 7 Cooling Tower to reflect a more accurate emission factor from 0.00002 gallons of drift/gallons of water circulated to 0.00001 gallons of drift/gallons of water circulated following a cooling tower repair in January 2009.

The minor modification received on July 2, 2012 requested the following modifications:

Request to incorporate Colorado Regulation No. 6, Part B, Section VIII.D.2 requirements for Drake Unit 5, 6, and 7.

The administrative permit amendment received April 7, 2014 requested the following:

Update the responsible official to George Luke.

The administrative permit amendment received November 10, 2014 requested the following:

Update the responsible official to Eric Tharp.

The Designated Representative Change form received on June 26, 2015 requested the following:

Update the Designated Representative to Aram Benyamin.

The modification received on November 30, 2015 requested the following modifications:

Request to incorporate the activated carbon injection (ACI) silo bin vent filter for Drake Unit 6 and 7 into the insignificant activities list in Appendix A.

The significant modification received on May 17, 2016 requested the following modifications:

Request to incorporate the applicable requirements from 40 CFR Part 63, Subpart UUUUU – Mercury and Air Toxics Standards (MATS) rule.

The significant modification received on July 21, 2016, and updated on January 5, 2018 requested the following:

Request to incorporate Construction Permit 13EP1789 into the Operating Permit.

The significant modification received on January 5, 2018 requested the following:

Request to incorporate Construction Permit 10EP402 into the Operating Permit.

The comments provided by the source on January 5, 2018 and January 30, 2018 requested the following modifications:

Removal of all Alternative Operating Scenarios from the Operating Permit.


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Update the fuel sampling plan.

Update indicator #2 on the Compliance Assurance Monitoring Plan.

Update 40 CFR Part 63, Subpart UUUUU requirements to include only SO2 emission limitation.

Update emission factor for Point 007, stockpile emissions to include specific emission estimates from wind erosion and pile maintenance as follows:

Coal Stockpile Emissions

𝑆𝑡𝑜𝑐𝑘𝑝𝑖𝑙𝑒𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑠

(tons

month) =

𝑊𝑖𝑛𝑑 𝐸𝑟𝑜𝑠𝑖𝑜𝑛𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑠

(𝑡𝑜𝑛𝑠

𝑚𝑜𝑛𝑡ℎ) +

𝑃𝑖𝑙𝑒 𝑀𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑠

(𝑡𝑜𝑛𝑠

𝑚𝑜𝑛𝑡ℎ)

Wind Erosion

𝑊𝑖𝑛𝑑 𝐸𝑟𝑜𝑠𝑖𝑜𝑛𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑠

(𝑡𝑜𝑛𝑠

𝑚𝑜𝑛𝑡ℎ) =

𝐸𝐹 (

𝑙𝑏𝑠𝑑𝑎𝑦𝑎𝑐𝑟𝑒

) × 𝑑𝑎𝑦𝑠 (𝑑𝑎𝑦𝑠

𝑚𝑜𝑛𝑡ℎ) × 𝑝𝑖𝑙𝑒 𝑠𝑖𝑧𝑒(𝑎𝑐𝑟𝑒𝑠)

2000 (𝑙𝑏𝑠𝑡𝑜𝑛

)

Where: pile size = 6 acres EF = emission factor (lb/day/acre) from “Control of Open Fugitive Dust Sources” EPA-450/3-98-008, dated September 1998

𝐸𝐹 (

𝑙𝑏𝑑𝑎𝑦

𝑎𝑐𝑟𝑒) = 1.7 × (

𝑠

1.5) × [

365 − 𝑝

235] × (

𝑓

15)

s = silt content of material (%) = 2.2%, from AP-42, Section 13.2 (dated 11/06), Table 13.2.4-1 p = number of days with > 0.01 inches of precipitation per year = 105 days, data from AP-42, Section 13.2 (dated 11/06), Figure 13.2.2-1 f = percentage of time that wind speed exceeds 5.4 m/s at mean pile height = 11.28% from meteorological tower data from 10/18/2015 to 01/31/2017

A control percentage of 85% was applied to the emission factor for wind erosion for application of a solution of water and concentrated surface active compound.

Pile Maintenance (bulldozing coal)

𝑃𝑖𝑙𝑒 𝑀𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑠

(𝑡𝑜𝑛𝑠

𝑚𝑜𝑛𝑡ℎ) =

𝐸𝐹 (𝑙𝑏ℎ𝑟

) × ℎ𝑜𝑢𝑟𝑠 𝑜𝑓 𝑝𝑖𝑙𝑒 𝑚𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 (ℎ𝑟𝑠

𝑚𝑜𝑛𝑡ℎ)

2000 (𝑙𝑏𝑠𝑡𝑜𝑛

)

Where: EF = emission factor (lb/hr) from AP-42, Section 11.9, Table 11.19-1 (dated 7/98)

𝑃𝑀 𝐸𝐹 (𝑙𝑏

ℎ𝑟) =

78.4 × 𝑠1.2

𝑀1.3

𝑃𝑀10 𝐸𝐹 (𝑙𝑏

ℎ𝑟) = 0.75 ×

18.6 × 𝑠1.5

𝑀1.4

s = silt content of material (%) = 2.2% from AP-42, Section 13.2 (dated 11/06), Table 13.2.4-1 M = moisture content of coal (%), to be determined by coal sampling required by Condition 2.4.


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A control percentage of 50% was applied to the emission factor for pile maintenance for application of water and/or a solution of water and concentrated surface active compound.

Note as requested by the source on February 5, 2017, a safety factor has been included for PM of 17.3% and PM10 of 74.6% to account for variability of wind velocity, dry/wet days, coal moisture, and silt content.

V. Incorporation of Modifications Requested by Source

The source’s requested modifications were addressed as follows:

Page Following Cover Page

Update the Responsible Official to Eric Tharp and the Permit Contact to Kevin Weiner.

Section I – General Activities and Summary

Condition 1.1 – A clarifying statement explaining the nameplate rating of the boilers is not necessarily reflective of the heat-input to the boiler under actual operating condition has not been added to the operating permit. Specifics on heat-input were not provided by the source.

Condition 1.1 – The attainment area status was updated to reflect the current attainment status of area and to reflect current Division language.

Condition 1.3 – Removal of Construction Permit 02EP0253 from the list of incorporated construction permits.

Condition 2.1 – Removal the Alternative Operating Scenario.

Condition 5 – The CAM language in the permit has been replaced with the Division’s updated standard language, please see the CAM section above for more information.

Condition 6 – Removal of Point 004 (Drake Unit 5), Point 016 (Drake Unit 5 Cooling Tower), and Point 022 (temporary coal crushing/conveyor system) from the summary of emission units table. Addition of the Flue Gas Desulfurization System (FGD) to the pollution control column for Point 005 and 006 (Drake Units 6 and 7) and addition of Point 025 (lime silos) to the summary of emission units table.

Section II – Specific Permit Terms

Per email with the source received on February 16, 2017, the requirement for Drake Unit 6 to burn a coal/woody biomass blend has not been included in the permit.

Previously Condition 2.4.2 - The stack testing requirement for particulate emissions of previous Condition 2.4.2 has been removed from the Operating


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Permit. The previous stack testing requirement in the Operating Permit based the frequency of stack testing on the results of past performance tests.

Under the MATS rule (40 CFR Part 63, Subpart UUUUU), quarterly performance testing is required for the first three years for units that qualify as low emitters for PM. The performance testing requirement in the MATS rule is more stringent than the previous performance testing requirement in the Operating Permit and has been included in place of previous Condition 2.4.2.

Condition 2.11 – Addition of the Colorado Regulation No. 6, Part B, Section VIII, Standards of Performance for Coal- Fired Electric Steam Generating Units for Drake Unit 6 and Unit 7. Please see Colorado Regulation No. 6, Part B, Section VIII above for more information.

Condition 2.13 – Addition of the 40 CFR Part 63, Subpart UUUUU, Coal and Oil Fired Electric Utility Steam Generating Units requirements, please see 40 CFR Part 63, Subpart UUUUU – National Emission Standards for Hazardous Air Pollutants: Coal and Oil Fired Electric Utility Steam Generating Units (Mercury and Air Toxics Standards (MATS) Rule above for more information.

Condition 3.2 – Update the emission factor and emission calculation for the coal stockpile.

Condition 3.3.1, 3.3.2, and 3.3.5 – Removal of language “shall be installed” and replaced with “shall be maintained” to represent installation of the masonry block walls and wet dust suppression system and replace “will” with “shall”.

Condition 3.3.1.2 and Condition 3.3.2.4 – Addition of using just water as a suppressant instead of only a chemical stabilizer or water and concentrated surface active compound as needed.

Condition 4.3 – Addition of the opacity requirement language from Colorado Regulation No. 1, Section II.A.1 and II.A.4. In the previous issuance of this permit, the source was required to conduct daily visual observations for the first year of permit issuance. If no visible emissions and no Method 9 observations were required during the first year of permit issuance, the visible observation monitoring frequency was switched to weekly. At the time of permit issuance and according to the 2015 source inspection, the source is conducting visible emission observations on a weekly basis. This requirement has been altered to require weekly visible emission observations and if a Method 9 observation is required two months in a row or one Method 9 observation results in non-compliance the source’s visible observation monitoring frequency will switch back to daily.

Condition 5.4 – Addition of the opacity requirement language from Colorado Regulation No. 1, Section II.A.1 and II.A.4. Per the 2015 source inspection, the source was conducting visible emission observations on a weekly basis as was previously indicated in the operating permit. If the source does not conduct a Method 9 opacity observation during any twelve calendar months, visible emission observations can be relaxed to once per month.


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Condition 6.1 – Removal of make-up water from this condition to correct for the double-counting of make-up water.

Condition 6.3 – Updated the drift factor for Drake Unit 7 Cooling Tower to 0.00001 gal drift/gal water circulated.

Condition 11.4.2 (previously 7.4.2) – Addition of operating day to specify calibration is only required when the unit is in operation.

Previously Condition 10 – Removed the reporting and records condition, the reporting and record requirements are included in Section IV, General Permit Conditions in the Operating Permit.

Previously Condition 12 – Removal of all conditions associated with the temporary coal crushing/conveyor system from the permit.

Section III – Acid Rain Requirements

Update the Designated Representative to M. Thomas Black and the Alternate Designated Representative to David Padgett.

Update the Sulfur Dioxide Emission Allowances and Nitrogen Oxides Emissions Limitation Table with the years for next permit term.

Appendices

Appendix A – Addition of the Activated Carbon Injection (ACI) Silo Bin Vent Filters for Drake Unit 6 and 7, sorbent processing system building vent, and sodium silos to the insignificant activities list.

Appendix A – Removal of T112, Unit 5 Turbine Lube Oil System from Insignificant Activities list

Appendix B and C – Removal of Temporary Coal Crushing System/Handling System from the tables.

Appendix E – Addition of Compliance Assurance Monitoring (CAM) to the permit acronyms list.

Appendix G - Addition of the fuel sampling plan.

VI. Incorporation of Construction Permit 13EP1786

Construction Permit 13EP1786 covers the lime storage and preparation system to support the SO2 scrubbers on Drake Unit 6 and Drake Unit 7. The initial approval construction permit was issued on January 21, 2014 and the final approval was issued on November 3, 2016. CSU requested the construction permit be incorporated into the operating permit on July 25, 2016 with additional information received on January 5, 2018. Pebble lime is delivered to the plant and unloaded into the lime silos, material is then transferred to an indoor lime slaker where it is mixed with water. The lime slaker tank overflows into separation tank where a feed pump delivers the slurry into a ball


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mill where it is broken down into smaller pieces. The product is then classified in a hydro cyclone separator that delivers the slurry mixture to be used in the SO2 scrubbers. Soda ash is used to pH balance and is delivered and unloaded into the other silo. Both silos are equipped with dust collectors. The table below lists the major components used in the lime storage and preparation system.

Equipment Description Make Model Serial Number

Pump Wifley Standard K Pro 1.5 N/A Soda Ash Storage Silo PTC 12’- 0” TK-4120

Sodium Solution Storage Tank PTC 12’- 0” Tk-4126 Soda Ash Silo Dust Collector Nederman SiloSafe 24 PI-41203

Silo Dehumidifier Dry-Air MP-175 N/A

Lime Storage Silo PTC 14’ – 0” TK-4110 TK-4210

Lime Slurry Storage Tank PTC 14’ – 0” TK-4116 TK-4216

Lime Silo Dust Collector Nederman SiloSafe 24

F-4118 M-4118 F-4218 M-4218

Lime Slaker Chemco DSS5000 TK-4111 TK-4211

Process Vertical Ball Mill Union C20

SL-4114 M-4114 SL-4214 M-4214

The appropriate applicable requirements from Colorado Construction Permit 13EP1786 for the two Chemco Systems have been directly incorporated into this operating permit as follows:

Condition 1 – Notice of Startup (NOS) Requirement

This condition has not been included in the operating permit. The Division received the NOS on December 3, 2015 with operation beginning on November 19, 2015.

Condition 2 – Self Certification Requirement

This condition has not been included in the operating permit. The Division received the self-certification on July 25, 2016.

Condition 3 – Permit Expiration Requirement

This condition was not included in the operating permit. Construction commenced on November 19, 2015.

Condition 4 - Initial Compliance Testing and Sampling Requirement

This condition was not included in the operating permit. The initial compliance testing and sampling was submitted to the Division along with the self-certification requirements on July 25, 2016.

Condition 5 – Operating and Maintenance (O&M) Plan


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This condition was not included in the operating permit. The source submitted a revised O&M plan to the Division along with the self-certification package on July 25, 2016 and was approved by the Division on October 27, 2016. The appropriate provisions from the O&M plan have been included in the operating permit.

Condition 6 - The permit number and AIRS ID number shall be marked on the subject equipment for ease of identification.

This is a construction permit only requirement, it has not been included in the specific requirements for Point 025 in the Operating Permit.

Condition 7 – The model number and serial number of the subject equipment shall be provided to the Division within one hundred and eighty (180) days after commencement of operation.

This condition has not been included in the operating permit, the Division received the model number and serial numbers of all subject equipment along with the final approval in the O&M Plan received on July 25, 2016. Please see table above for the list of subject equipment.

Condition 8 – Emission Limitations: PM – 1.3 tons per year, PM10 – 1.3 tons per year, PM2.5 – 0.7 tons per year.

The PM, PM10, and PM2.5 emission limitations for Point 025 have been included in the permit. Compliance shall be determined on a rolling twelve month total.

Condition 9 – This point shall be equipped with cartridge filters to control PM, PM10, and PM2.5 by 80.0%. The owner or operator shall monitor compliance with this condition through the results of approved compliance tests (when required), compliance with the O&M Plan, compliance records, and other methods as approved by the Division.

This condition has not been included in the operating permit. The silos were defined with dust collectors on the self-certification received on July 25, 2016 and the operating permit application received on January 5, 2018.

Condition 10 – Process Limitations: Materials Stored – 20,630 tons per year.

This condition has been included in the operating permit. Compliance with the material throughput will be monitored with each shipment of material. The date of each shipment, the type of material delivered, and how much material was delivered shall be recorded for each shipment and used in a twelve month rolling calculation.

Condition 11 – Visible emissions shall not exceed twenty percent (20%) opacity during normal operation of the source. During periods of startup, process modification, or adjustment of control equipment visible emissions shall not exceed 30% opacity for more than six minutes in any sixty consecutive minutes. Opacity shall be determined using EPA Method 9.


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The 20% and 30% opacity requirements of Colorado Regulation No. 1, Section II.A.1 and II.A.4 have been included in the operating permit. Compliance with the opacity standards is presumed whenever the dust collectors are controlling emissions in accordance with the O&M requirements.

Condition 12 – Odor Requirements of Regulation No. 2.

This condition is included in the General Conditions of Section IV in the Operating Permit and was not included in the specific conditions for Point 025.

Condition 13 – O&M Plan

This condition was not included in the operating permit. The Division received the O&M Plan on July 25, 2016 and was approved by the Division on October 27, 2016. The approved requirements from the O&M Plan have been incorporated into the Operating Permit.

The silos and dust collectors shall be operated and maintained in accordance with the manufacturer’s recommendations and good engineering practices. In addition, daily checks on the filter pressure, compressed air pressure, operation of the cleaning valves in the dust collectors, and continuous monitoring with an alarm system of the cleaning air pressure and the differential pressure.

Condition 14 - Within 180 days of startup, the owner or operator shall demonstrate compliance with visible emission limit above using EPA Method 9 to measure opacity from the silo stacks. This measurement shall consist of a minimum twenty-four consecutive readings taken at fifteen second intervals over a six minute period.

This condition was not included in the operating permit. The source submitted a compliance demonstration with the visible emission limitation using EPA Method 9 along with the self-certification package received on July 25, 2016.

Condition 15 – Periodic testing is not required for this source.

There were no requirements associated with this condition, this condition has not been included in the operating permit.

Condition 16 – The permit number and/or AIRS ID number shall be marked on the subject equipment for east of identification.

This is a construction permit only requirement, it has not been included in the specific requirements for Point 025 in the Operating Permit.

Condition 17 – APEN Reporting Requirements

This condition has not been included in the operating permit. The APEN reporting requirements are included in the General Conditions of Section IV in the operating permit.

Condition 18 - This permit and any attachments must be retained and made available for inspection upon request. The permit may be reissued to a new


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owner by the Division as provided in Regulation No. 3, Part B, Section II.B upon a request for transfer of ownership and the submittal of a revised APEN and the required fee.


Condition 19 – This permit is issued in reliance upon the accuracy and completeness of information supplied by the applicant and is conditioned upon conduct of the activity, or construction, installation and operation of the source, in accordance with this information and with representations made by the applicant or applicant’s agents. It is valid only for the equipment and operations or activity specifically identified on the permit.


VII. Incorporation of Construction Permit 10EP402

Construction Permit 10EP402 covers Drake Unit 7 (Point 006) at the facility. The initial approval construction permit for Modification No. 2 was issued on 12/27/2016 and the final approval was issued on 09/06/2017. Modification No. 2 consisted of incorporating a facility wide sulfur dioxide (SO2) emission limitation as required by 40 CFR Part 51, Subpart BB, Data Requirements Rule (DRR) for the 2010 1-hour Sulfur Dioxide Primary National Ambient Air Quality Standard (NAAQS). Construction Permit 10EP402 was first issued on December 13, 1973 as Construction Permit P10-,402 and was renamed 10EP402 in 2007. In addition to the facility wide sulfur dioxide emission limitation the Construction Permit modification incorporated applicable requirements from 40 CFR Part 63, Subpart UUUUU, Colorado Regulation No. 6, Part B, Section VIII, and Colorado Regulation No. 3, Part F requirements.

The appropriate requirements from Colorado Construction Permit 10EP402 for Drake Unit 7 have been directly incorporated into this operating permit as follows:

Condition 1 – Self Certification Requirement

This condition was not included in the operating permit, the Division received CSU’s self-certification on June 26, 2017.

Condition 2 – Initial Testing Requirement

This condition was not included in the operating permit, the Division received the results from the initial compliance testing and sampling along with the self-certification package on June 26, 2017.


This condition was not included in the operating permit. The Division received the O&M Plan on 06/26/2017 and it was approved by the Division on 08/31/2017. The approved requirements from the O&M Plan have been incorporated into the Operating Permit.


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Condition 4 – Facility Wide SO2 Emission Limitation: 1,995.0 tons per year and 410 tons per month.

This condition was included in the Operating Permit under new Condition 10. Please see above under 40 CFR Part 51, Subpart BB – Data Requirements Rule for more information on this emission limitation. Note the monthly emission limitation is only required for the first twelve (12) months of operation while the annual limit is effective for calendar year 2017 and thereafter. The monthly emission limitation was not included in the Operating Permit since the Operating Permit was issued after the first twelve (12) months of operation.

Condition 5 – Drake Unit 7 shall be equipped with Fabric Filter Baghouse to control PM, PM10, and PM2.5, a Wet Dual Alkali Flue Gas Desulfurization (FGD) system to control SO2, and Ultra Low NOX Burners and Over Fire Air to control NOX.

Drake Unit 7 has been defined with a Fabric Filter Baghouse, a Wet Dual Alkali Flue Gas Desulfurization (FGD) system, and Ultra Low NOX Burners and Over Fire Air and this condition has not been included in the operating permit.

Condition 6 – Fuel consumption shall be monitored and recorded on an annual basis. The fuel consumption shall be determined from belt scales, invoices, and inventory on hand as specified in the Title V Operating Permit 95OPEP107. Copies of all records shall be kept onsite and made available to the Division review upon request.

This condition was already in the Operating Permit prior to this renewal and has remained in the Operating Permit. The Facility is also required to monitor natural gas consumption from the boiler on an annual basis.

Condition 7 – The heat content of the coal fuel shall be calculated from the emissions recorded by the carbon dioxide CEMS or measured by testing as specified in the fuel sampling plan in the Title V Operating Permit 95OPEP107 and Appendix A of this Construction Permit.

This condition was already in the Operating Permit prior to this renewal and has remained in the Operating Permit.

Condition 8 – The fuel sampling shall be conducted in accordance with the requirements identified in the most recent Division approved coal sampling/monitoring plan as specified in Appendix A of this Construction Permit.

The fuel sampling plan has been included in the Operating Permit in Appendix G and a condition requiring all fuel sampling be conducted in accordance with the fuel sampling plan has been included in the Operating Permit.

Condition 9 and 10 – Except as provided for in Condition 10 below, no owner or operator of a source shall allow or cause the emission into the atmosphere of any air pollutant which is in excess of twenty percent (20%) opacity. No owner


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or operator of a source shall allow or cause to be emitted into the atmosphere any air pollutant resulting from startup or process modifications which is in excess of thirty percent (30%) opacity for a period of periods aggregating more than six (6) minutes in any sixty (60) consecutive minutes (Colorado Regulation No. 1, Section II.A.1 and II.A.4).

This condition was already in the Operating Permit prior to this renewal and has remained in the Operating Permit. Compliance with the opacity standard shall be monitored using the Continuous Opacity Monitoring (COM) system.

Condition 11 – Odor Requirements of Regulation No. 2.

This condition is included in the General Conditions of Section IV in the Operating Permit and was not included in the specific conditions for Drake Unit 7.

Condition 12 – 40 CFR Part 63, Subpart UUUUU, National Emission Standards for Hazardous Air Pollutants for Coal- and Oil- Fired Electric Utility Steam Generating Units.

These requirements were included in the Operating Permit. Please see above under 40 CFR Part 63, Subpart UUUUU for more information.

Condition 13 – 40 CFR Part 63, Subpart A, General Provisions

This requirement has been included in the Operating Permit. Since Drake Unit 7 is subject to 40 CFR Part 63, Subpart UUUUU, it is also subject to Subpart A – General Provisions, see §63.10040. The appropriate general provisions have been included in the Operating Permit.

Condition 2.14 – Colorado Regulation No. 1, Emission Control Regulations for Particulate Matter for the State of Colorado, Particulate Matter for Fuel Burning Equipment, Section III.A.1.

This condition was not included in the operating permit. The particulate matter limitations in 40 CFR Part 63, Subpart UUUUU and from Regional Haze are considered to be more stringent than the particulate matter limitations in Colorado Regulation No. 1, Section III.A.1. Please see below under the Streamlining (Section IX) for more information.

Condition 15 – Colorado Regulation No. 1, Emission Control Regulations for Sulfur Dioxide Emissions for the State of Colorado, Sulfur Dioxide Emission Regulations for Existing Sources, Section VI.A.

This condition was included in the Operating Permit.

Condition 16 – A Continuous Emission Monitoring (CEM) System shall be installed, calibrated, maintained, and operated to accurately measure and record opacity, sulfur dioxide (SO2) (including diluent gas carbon dioxide (CO2) or oxygen (O2)), carbon monoxide (CO), nitrogen oxides (NOX), and volumetric flow for Drake Unit 7 (Colorado Regulation No. 1, Section IV and 40 CFR Part 75).


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Each CEMs shall meet the requirements specified in the Title V Operating Permit 95OPEP107.

This condition has been included in the operating permit under Condition 2.10. The CEMS are also required to meet the specific requirements in Condition 11 of the Operating Permit.

Condition 17 – Colorado Regulation No. 6, Part B, Section VIII, Standards of Performance for Coal-Fired Electric Steam Generating Units.

This condition has been included in the Operating Permit. Please see above under Colorado Regulation No. 6, Part B, Section VIII, Standards of Performance for Coal-Fired Electric Steam Generating Units for more information.

Condition 18 – This facility is subject to the Title IV Acid Rain Requirements.

This condition was already in the Operating Permit prior to this renewal and has remained in the Operating Permit. The language has been updated to reflect current Division language.

Condition 19 – Colorado Regulation No. 3, Part F, Regional Haze Limits – Best Available Retrofit Technology (BART) and Reasonable Progress (RP).

This condition has been included in the Operating Permit. Please see Colorado Regulation No. 3, Part F, Regional Haze Limits – Best Available Retrofit Technology (BART) and Reasonable Progress (RP) above for more information.


This condition was not included in the operating permit. The Division received the O&M Plan on 06/26/2017 and it was approved by the Division on 08/31/2017. The approved requirements from the O&M Plan have been incorporated into the Operating Permit.

Condition 21 – The owner or operator shall operate, calibrate, and maintain continuous in-stack monitoring device for the measurement of opacity. Unless otherwise specified in this permit, the Continuous Opacity Monitoring (COM) Systems shall be used to monitor compliance with Conditions 9 and 10. The requirements for the COMs are defined in the Title V Operating Permit 95OPEP107.

This condition has been incorporated in to the Operating Permit.

Condition 22 – The owner or operator shall monitor compliance with the Colorado Regulation No. 1, Section III.A.1 requirements in Condition 14 as defined in the Title V Operating Permit 95OPEP107.

This condition was not included in the Operating Permit, Colorado Regulation No. 1, Section III.A.1 particulate matter standards have been streamlined out of the permit in favor of 40 CFR Part 63, Subpart UUUUU. Please see Section IX, Streamlining Conditions, below for more detail.


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Condition 23 – The owner or operator shall monitor compliance with the Colorado Regulation No. 1, Section VI.A.3 requirements in Condition 15 as defined in the Title V Operating Permit 95OPEP107.

The compliance monitoring for Colorado Regulation No. 1, Section VI.A.3 requirements have been included in the Operating Permit in Condition 2.7.

Condition 24 – A compliance test shall be conducted on Drake Unit 7 to measure the emission rates of PM and PM10 in order to monitor compliance with the Colorado Regulation No. 1 particulate limits found in Condition 14. Testing shall be performed using the appropriate EPA Reference Methods to measure filterable particulate matter. Testing shall be conducted as described below.

If the most recent test or any subsequent test results indicate emissions are less than or equal to 50% of the emission limit, another test is required within five years;

If the most recent test or any subsequent test results indicate emissions are more than 50%, but less than 75% of the emission limit, another test is required within three years;

If the most recent test or any subsequent test results indicate emissions are greater than 75% of the emission limit, tests are required every twelve (12) months until the provisions of (1) or (2) are met.

This condition was already in the Operating Permit and has not been included in the Operating Permit renewal. The Colorado Regulation No. 1 particulate limits have been streamlined from the Operating Permit and the stack testing requirement has also been streamlined from the Operating Permit in favor of the testing requirements in 40 CFR Part 63, Subpart UUUUU. Please see Section IX, Streamlining Conditions, below for more detail.

Condition 25 – The owner or operator shall submit a cancelation notice to the Division for Drake Unit 5, AIRS ID: 041-0004-004 no later than December 31, 2016 with shutdown on or before January 1, 2017.

This condition was not included in the Operating Permit, the Division received the cancelation notice for Drake Unit 5 on December 23, 2016. The cancelation notice indicated Drake Unit 5 ceased operation on December 31, 2016.

Condition 26 – All previous versions of this permit are cancelled upon issuance of this permit.

This condition applies only to the construction permit issuance and was not included in the operating permit.

Condition 27 – APEN Reporting Requirements

The APEN reporting requirements are included in the General Conditions of Section VI, this condition was not included in the Operating Permit.


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Condition 28 – All equipment currently covered by an existing Title V permit must comply with all monitoring, reporting, and recordkeeping requirements outlined in the current Title V Operating Permit.

This condition is a construction permit only condition and was not included in the Operating permit.

Condition 29 – This source is subject to the provisions of Regulation No. 3, Part C, Operating Permits (Title V of the 1990 Federal Clean Air Act Amendments). The provisions of this construction permit must be incorporated into the operating permit. The application for the modification to the Operating Permit is due within one year of the issuance of this permit.

The application to incorporate Construction Permit 10EP402 was received by the Division on January 5, 2018. This condition was not included in the Operating Permit.

Condition 30 – This permit and any attachments must be retained and made available for inspection upon request. The permit may be reissued to a new owner by the Division as provided for in Regulation No. 3, Part B, II.B upon a request for a transfer of ownership and the submittal of a revised APEN and the required fee.

This requirement is included in the General Conditions of Section VI, this condition was not included in the Operating Permit.

Condition 31 - If this permit specifically states that final approval has been granted, then the remainder of this condition is not applicable. Otherwise, the issuance of this construction permit is considered initial approval and does not provide “final” approval for this activity or operation of this source. Final approval of this permit must be secured from the APCD in writing in accordance with the provisions of 25-7-114.5(12)(a) C.R.S and AQCC Regulation No. 3, Part B, III.G. Final approval cannot be granted until the operation or activity commences and has been verified by the APCD as conforming in all respects with the conditions of the permit. Once self-certification of all points has been reviewed and approved by the Division, it will provide written documentation of such final approval. Details for obtaining final approval to operate are located in the Requirements to Self-Certify for Final Approval section of this permit. The operator shall retain the permit final approval letter issued by the Division after completion of self-certification with the most current construction permit.

This condition was not included in the Operating Permit and the final approval for this construction permit was issued on September 6, 2017.

Condition 32 – This permit is issued in reliance upon the accuracy and completeness of information supplied by the applicant and is conditioned upon conduct of the activity, or construction, installation and operation of the source, in accordance with this information and with representations made by the applicant or applicant’s agents. It is valid only for the equipment and operations or activity specifically identified on the permit.


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This requirement is included in the General Conditions of Section VI, this condition was not included in the Operating Permit.

VIII. Other Modifications

In addition to the source requested modifications, the Division has included changes to make the permit more consistent with recently issued permits, include comments made by EPA on other Operating Permits, as well as correct errors or omissions identified during inspections and/or discrepancies identified during review of this renewal. These changes are as follows:

Page Following Cover Page

It should be noted the monitoring and compliance periods and report and certification due dates are shown as examples. The appropriate monitoring and compliance periods and report and certification due dates will be filled in after permit issuance and will be based on permit issuance date. Note the source may request to keep the same monitoring and compliance periods and report and certification due dates as were provided in the original permit. However, it should be noted with this option, depending on the permit issuance date, the first monitoring period and compliance period may be short (i.e. less than 6 months and less than 1 year).

Section I – General Activities and Summary

Condition 1.1 – Update the description of the source and removal of Unit 5 from the boiler summary table.

Condition 1.3 – Renamed C-10,381 to reflect updated Construction Permit name 10EP402, addition of Construction Permit 13EP1786 and removal of Construction Permit C-10,381.

Condition 1.4 - Revised the language to include current conditions that are state-only enforceable.

Condition 2.1.2 – Removal of Unit 5 due to cancelation of Drake Unit 5 on December 31, 2016.

Condition 3 – Removal of area classification from the Prevention of Significant Deterioration condition, this is included in Section I, Condition 1.1. Update the language to reflect the Division’s current standard language for PSD.

Section II – Specific Permit Terms

Condition 1.1 – Removal of “Fuel use records shall be maintained on-onsite and made available to the Division for review upon request” and created a new condition 1.2 that is specific to natural gas consumption monitoring.

Condition 1.2 – Addition of natural gas consumption monitoring requirement. The facility shall monitor their natural gas consumption using fuel meters or billing records on an annual basis to aid in emissions calculations.


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Condition 1.3 – Update condition for annual emission calculation to reflect updated language at the Division and to include emission calculation equation.

Addition of the requirement for the source to use the CEMS to monitor CO emissions. The source is required to follow the most current version of the QA/QC plan developed. If the source plans to permanently switch from monitoring CO emissions from using the CEMS to an alternative method, they need to notify the Division and then use the Division approved method to monitor emissions.

Condition 1.4 – Update the language for particulate emissions from fuel burning equipment in Colorado Regulation No. 1, Section III.A.1.

Condition 1.5 – Update the language for the Acid Rain Requirements.

Condition 1.6 – Removal of the reference to the Opacity Standards and addition of the Opacity requirements from Colorado Regulation No. 1, Section II.A.1 and II.A.4.

Condition 1.7 – Addition of the Colorado Regulation No. 3, Part F, Regional Haze Limits, see discussion above.

Condition 1.8 – Addition of Colorado Regulation No. 3,

Condition 2, Table – Removal of Drake Unit 5 from the title, change Fuel Usage to Coal Consumption

Condition 2.1 – Removal of “Fuel usage shall be determined from belt scales, invoices and inventory on hand. Copies of the records shall be kept on-site and made available for Division review upon request” and created a new condition 2.2 that is specific to the coal consumption.

Condition 2.2 – Addition of coal consumption monitoring requirement. The facility monitors coal consumption using belt scales, invoices, and inventory on hand.

Condition 2.3.1 – Removal of “Other appropriate emission factors (i.e. current versions of EPA’s Compilation of Emission Factors (AP-42)) and appropriate control equipment collection efficiencies may also be used as noted in Section II, Condition 9 of this permit”. The former Condition 9 has been removed from the operating permit, emission factors are as defined by each individual condition and treatment of and changes of errors found in emission factors will be addressed as needed.

Condition 2.3.3 - Addition of the requirement for the source to use the CEMS to monitor CO emissions. The source is required to follow the most current version of the QA/QC plan developed. If the source plans to permanently switch from monitoring CO emissions from using the CEMS to an alternative method, they need to notify the Division and then use the Division approved method to monitor emissions.


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Condition 2.3.4 – Addition that emissions of lead for the purposes of APEN reporting shall be based on the information submitted in the annual Toxic Release Inventory (TRI) report, when available, or determined using a method consistent with TRI reporting.

Condition 2.4 and 2.5 (previously Condition 2.3) – Separated the coal heat content calculation requirement to its own Addition of heat, moisture, sulfur and lead to clarify what else shall be monitored in addition to ash content in the fuel sampling.

Previously Condition 2.4.2 – Removal of the PM and PM10 stack testing requirement in Condition 2.4.2 from the Operating Permit, this requirement has been streamlined out of the permit in favor of testing requirements of 40 CFR Part 63, Subpart UUUUU. Please see Section IX, Streamlining Conditions, below for more detail.

Note, PM and PM10 emissions are calculated using the emission factor established from the most recent source compliance test. The most recent March 2017 MATS test had the following results:

Drake Unit 6 Drake Unit 7

PM Emissions (lbs/MMBtu)

0.0013 0.0024

Condition 2.6 (previously Condition 2.4) – Separated the baghouse operation and maintenance requirements from the stack testing requirement.

Condition 2.6 – Addition of the Division’s updated good engineering practices standard language to the baghouse operation and maintenance requirement.

Condition 2.7 (previously Condition 2.5) – Update Colorado Regulation No. 1, Sulfur Dioxide emission regulation to the Division’s updated standard language.

Condition 2.8 (previously Condition 2.8) – Updated the Acid Rain language to represent the Division’s updated standard language.

Condition 2.9 – Removal of the reference to the Opacity Standards and addition of the Opacity requirements from Colorado Regulation No. 1, Section II.A.1 and II.A.4.

Condition 2.10 – Addition of CO to the pollutants monitored by the CEMS.

Condition 3.1 – Revision and addition of language to include rolling twelve month total language.

Condition 3.2 – Update the rolling twelve month language to standard Division language. Addition of emission calculation equations to the condition to aid in calculation of emissions.

Condition 3.3 – Update standard language referencing the particulate emission control plan and added Colorado Regulation No. 1, Section III.D reference. Replacement of 20% opacity and no off property transport emissions with


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specific language from Colorado Regulation No. 1, Section III.D. If emissions are observed from the daily non-Method 9 checks, the source is required to conduct observations in accordance with Colorado Regulation No. 1, Appendix A and B and notify the Division if the observation results in emissions in excess of the 20% opacity or emissions are being transported off the property.

Previously Condition 4.1 – Removal of the condition stating the sources are subject to the General Conditions in Section IV. This condition is not necessary.

Condition 4.1 – Updated the language for emissions calculations to standard Division language. Addition of the emission calculation used to calculate emissions.

Condition 4.2 – Addition of language to monitor and record the amount of coal processed annually and addition of language that the coal processed is determined using weighing belt conveyors and records of coal quantities processed.

Condition 4.3, 5.4, 7.3 – Addition of Colorado Regulation No. 1, Section II.A.4, 30% opacity requirement for periods of building a new fire, cleaning of fire boxes, soot blowing, start up, process modifications, or adjustment or occasional cleaning of control equipment.

Condition 5.1 – Updated the language for monitoring the flyash throughput/production to the Division’s updated standard language.

Condition 5.2 – Addition of emission calculation equation to the condition to aid in calculation and updated the rolling twelve month total language to the Division’s updated standard language.

Condition 5.3 – Addition of the operating and maintenance procedures for the flyash handling system, including separator filter bag and silo bin vent bag inspection and replacement procedures from Construction Permit 95EP590. Addition of the Division’s updated standard language for good engineering practices.

Condition 6.1 – Addition of the design rates for each cooling tower and specification the source uses the hours of operation and design rates to calculate the quantity of water circulated.

Condition 6.3 – Revision of emission calculation language to reflect the Division’s updated standard language and addition of an equation for VOC emission calculation.

Condition 6.4 – Addition of requirement to track hours of operation on a monthly basis for each cooling tower to aid in calculation of the total water circulated.

Condition 6.5 – Addition of Colorado Regulation No. 1, Section II.A.1, twenty percent opacity requirement. Compliance with the opacity shall be presumed provided the drift eliminators on the cooling towers are maintained and


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operated in accordance with manufacturer’s requirements and good engineering practices.

The thirty percent opacity requirement of Colorado Regulation No. 1, Section II.A.4 has not been included. The Division has determined none of the special conditions under Section II.A.4 are applicable to the cooling towers.

Condition 7 – Addition of language for all requirements listed in the table into the permit.

Condition 11, Previously Condition 7 – The CEMS and COMS requirements have been revised to include the 40 CFR Part 60, Subpart A Reporting and Recordkeeping requirements instead of the Colorado Regulation No. 1, requirements that were included in the original Operating Permit. The Regulation No. 1 requirements have been streamlined out of the permit. Please see Section IX, Streamlining Conditions, below for more detail.

Previously Condition 9 – The emission factor condition has been removed from the permit, emission factors are addressed in each point.

Previously Condition 11 – The coal sampling/testing plan condition has been removed from this location in the permit. The plan is included in Appendix G and is referenced elsewhere in the Operating Permit.

Previously Condition 8 – Removal of the opacity condition and added the opacity requirements of Colorado

Condition 9.1 – Addition of Colorado Regulation No. 1, Section II.A.1 and II.A.4 opacity standards for the diesel emergency generator. Compliance with the opacity standards shall be determined by conducting one annual Method 9 observation while the emission unit is in operation. If the generator operates more than 250 hours per year, a second Method 9 observation is required.

Condition 9.2 – Addition of hours of operation tracking requirement for the emergency generator. If hours of operation exceed 768 hours per year, the permittee shall determine if an APEN is required to be filed for the emergency generator. Note the potential to emit from the emergency generator is below the APEN reporting threshold based on 500 hours per year of operation per 1995 EPA memo.

Condition 9.3 – Addition of 40 CFR Part 63, Subpart ZZZZ requirements for the emergency generator.

Condition 9.4 – Addition of 40 CFR Part 63, Subpart A, General Provisions for the emergency generator.

Section III – Permit Shield

Updated the Colorado Regulation No. 3 citation for the permit shield.

Updated the emission unit descriptions in the table.


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Removal of 40 CFR Part 64, Compliance Assurance Monitoring from the Permit Shield. This facility is subject to the provisions of CAM and CAM has been included in this permit renewal.

Removal of Prevention of Significant Deterioration, 40 CFR §52.21 and Colorado Regulation No. 3, Part B, §IV.D.3 from the table. The provisions of §52.21 are applicable to any project at an existing major stationary source in an area designated as attainment or unclassifiable.

Removal of emission unit S005 and P206 from the table. These points have been canceled.

Section IV – General Permit Conditions

Updated the general permit conditions to the current version (5/22/2012).

Section V – Acid Rain Requirements

Updated Designated Representative to Aram Benyamin.

Removal of the sentence “For NOX, the source is not subject to the emission limitations in Section 2 until January 1, 2000. For SO2, the source is not required to hold allowances to account for SO2 emissions until the year 2000.” from section 2 of this section.

Removal of all requirements in Section V for Drake Unit 5, Drake Unit 5 falls under the Retired Unit Exemption of §72.8.

Addition of a Section 5 for Comments, Notes and Justifications to specify the Retired Unit Exemption form for 40 CFR 72.8 for Drake Unit 5 was received and the Unit was permanently retired on December 31, 2016. This form was received by the Division on December 23, 2016.

Revised the tables for Drake Unit 6 and 7 to include calendar years corresponding to the relevant permit term for the renewal.

Updated the SO2 allowances for Drake Unit 6 and 7 per 40 CFR Part 73.10(b), Table 2 to include the years 2010 and beyond, Total Annual Phase II Allowance Allocations.

Added a requirement to Section 1 (directly under ADR and DR), specifying changes to the DR and ADR shall be made according to 40 CFR Part 72 § 72.23.

Updated the reference to §72.84(a) in the footnotes to the tables in Section 2 to show the most recent version.

Minor changes were made to the standard requirements, based on changes made to 40 CFR Part 72 § 72.9.

Appendices


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Update Appendix A insignificant activity list and facility plot plan.

Updated Appendices B and C (Monitoring and Permit Deviation Reports and Compliance Certification Reports) to the newest versions (2/20/2007).

EPA’s mailing address was revised (Appendix D). Removed the Acid Rain addresses in Appendix D, since annual certification is no longer required and submittal of quarterly reports/certifications is done electronically.

Cleared the list of modifications from Appendix F related to the previous issuance.

Addition of Fuel Sampling Plan in Appendix G.

Addition of Compliance Assurance Monitoring Plan in Appendix H.

Addition of Retired Unit Exemption form in Appendix I.

IX. Streamlined Conditions

Colorado Regulation No. 1, Section III.A.1 Particulate Matter for Fuel Burning Equipment, 0.1 lbs/MMBtu, limitation has been streamlined out for the Regional Haze Particulate Emission Limitation. The Regional Haze limitation is considered, by the Division, to be more stringent than the Colorado Regulation No. 1 Particulate Limitation at 0.03 lbs/MMBtu. The stack testing requirement of previous Condition 2.4.2 has been streamlined out of the permit in favor of the particulate matter performance testing requirements from 40 CFR Part 63, Subpart UUUUU (MATS). The MATS performance testing is considered by the Division to be more stringent than the performance testing of the previous Condition 2.4.2.

Colorado Regulation No. 3, Part F, Section VII.C.1, Regional Haze Requirements, Monitoring/Compliance Determinations - Particulate Regional Haze Limits has been streamlined out for Drake Unit 6 and Drake Unit 7. This requirement has been streamlined out in favor of the particulate performance testing requirements in 40 CFR Part 63, Subpart UUUUU (MATS). The Regional Haze Particulate Monitoring/Compliance Requirement requires an annual performance test except if (1) if any test results indicate emissions are less than or equal to 50% of the emission limit, another test is required within five years; (2) if any test results indicate emissions are more than 50%, but less than or equal to 75% of the emission limit, another test is required within three years; and (3) if any test results indicate emissions are greater than 75% of the emission limit, an annual test is required until the provisions of (1) or (2) are met. 40 CFR Part 63, Subpart UUUUU requires quarterly particulate performance testing for the first three years for units that qualify as low emitters for PM. The MATS performance testing is considered by the Division to be more stringent than the performance testing of Colorado Regulation No. 3, Part F, Section VII.C.1.


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Colorado Regulation No. 3, Part F, Section VII.D, Regional Haze Requirements, Recordkeeping, the recordkeeping requirement in Section VII.D to retain records for at least five (5) years has been streamlined for the five (5) year recordkeeping and reporting requirements already in the permit in the General Permit Conditions, Section IV, Condition 22.

Colorado Regulation No, 3, Part F, Section VII.E, Regional Haze Requirements - the paragraph to submit performance stack test reports to the Division within 60 days and the paragraph for semi-annual reports of CAM excursions. The 60 day submittal requirement was streamlined from the permit since the facility is conducting performance testing under Subpart UUUUU, and Subpart UUUUU requires submittal of performance test results within 60 days as well. The reporting of excursions from CAM indicators was streamlined from the permit since the reporting of excursions is already required under the CAM requirements.

Colorado Regulation No. 1, Section IV.G reporting requirements were removed and streamlined out for the requirements of 40 CFR Part 60, Subpart A reporting and recordkeeping requirements. In the Regional Haze recordkeeping and reporting requirements, Regulation No. 3, Part F, Section VII.E references the excess emission reports should include the information in 40 CFR Part 60.7(c).