TECHNICAL REVIEW DOCUMENT 

For 

RENEWAL / MODIFICATION of OPERATING PERMIT 96OPRO132

Public Service Company – Hayden Station 

Routt County 

Source ID 0010097 

Prepared by Jacqueline Joyce 

July and September 2007, February, June, July, September and December 2008 

I. Purpose: 

This document will establish 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 proposed for this site. The original Operating 

Permit was issued May 1, 2001. The expiration date for the permit was May 1, 2006. 

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. 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 renewal application submitted April 1, 2005, comments on 

the draft permit submitted on September 23, 2008, comments received on the draft 

permit on November 6, 2008 during the public comment period (October 8 – November 

7, 2008), previous inspection reports and various e-mail correspondence, as well as 

telephone conversations with the applicant. A request for a minor modification to this 

Operating Permit was submitted on September 13, 2007. The minor modification and 

renewal are being processed concurrently. Please note that 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 

http://www.cdphe.state.co.us/ap/Titlev.html. This narrative is intended only as an 

adjunct for the reviewer and has no legal standing. 

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. 

Page 1 
II. Description of Source 

This source is classified as an electrical services facility under Standard Industrial 

Classification 4911. This facility consists of two coal fired boilers. Unit 1 is rated at 205 

MW and Unit 2 is rated at 300 MW. The Unit 1 ignitors utilize either natural gas or No. 2 

fuel oil and the Unit 2 ignitors utilize No. 2 fuel oil for startup, shutdown and/or flame 

stabilization. As part of a Consent Decree, entered by the United States District Court 

on August 19, 1996, Civil Action 93-B-1749, the following emission control devices were 

required to be installed on both Units 1 and 2: low NOX burners with over-fire air (to 

control NOX emissions), lime spray dryers (to control SO2 emissions) and fabric filter 

dust collectors (to control PM emissions). The Consent Decree required that startup 

testing of the control devices on Unit 1 commence by December 31, 1998 and that 

startup testing of the control devices on Unit 2 commence by December 31, 1999. As of 

October 18, 1999 all control equipment required by the Consent Decree had been 

placed into service. 

In August 1996 the Colorado Air Quality Control Commission (AQCC) adopted revisions 

to Colorado’s Visibility State Implementation Plan (SIP), specified in a document entitled 

“Long-Term Strategy Review and Revision of Colorado’s State Implementation Plan for 

Class I Visibility Protection Part I: Hayden Station Requirements”, dated August 15, 

1996. The U.S. EPA approved the Visibility SIP revisions at 62 Federal Register 2305 

(January 16, 1997). These revisions, concerning the Hayden Station, implemented and 

enforced requirements identified in the Hayden Consent Decree. Only those provisions 

of the Consent Decree that dealt with visibility impairment (SO2 and opacity) were 

included in the Visibility SIP revisions. 

In addition to the coal fired boilers, other significant sources of emissions at this facility 

include fugitive emissions from coal handling, ash handling and disposal and vehicle 

traffic on paved and unpaved roads. Point source emissions of particulate matter 

include coal crushing and conveying, an ash storage silo, two (2) ash recycle silos 

(recycle ash used with lime in the spray dryer), two (2) lime storage silos, two (2) ball 

mill slakers (prepares lime slurry for spray dryer) and two (2) recycle mixers (prepares 

recycle as slurry for spray dryer). Additional emission units at this facility include two 

(2) cooling towers. 

This facility is located four miles east of Hayden at 13125 U.S. Highway 40, in Routt 

County. The area in which the plant operates is designated as attainment for all criteria 

pollutants. 

Wyoming, an affected state, is within 50 miles of the plant. Flattops and Mt. Zirkel 

National Wilderness Areas, federal class I designated areas, are within 100 km of this 

facility. 

The summary of emissions that was presented in the Technical Review Document 

(TRD) for the original permit issuance has been modified to more appropriately identify 

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the potential to emit (PTE) of both criteria and hazardous air pollutants. Emissions (in 

tons/yr) at the facility are as follows: 

Emission Unit PM PM10 SO2 NOX CO VOC Pb1 HAPS 

Point Sources 

Boiler No. 1 

(Unit 1) 

257.94 237.30 1,17.73 3,955.05 194.3 23.32 0.16 See 

Page 21

Boiler No. 2 

(Unit 2) 

356.36 327.85 1,544.21 4,751.42 268.44 32.21 0.23 

Auxiliary Boiler 1.56 0.78 56.31 15.64 3.91 0.16 

Ash Silo 22.39 22.39 

Coal Handling 

System 

13.14 6.22 

Recycle Ash 

Silos 

0.09 0.09 

Recycle Ash 

Mixers 

0.16 0.16 

Lime Storage 

Silos 

0.01 0.01 

Ball Mill Slakers 0.8 0.8 

Unit 1 Cooling 

Twr 

3.23 3.23 1.2 

Unit 2 Cooling 

Twr 

5.15 5.15 1.9 

Total Point 

Source 

Emissions 

660.83 603.99 2,718.25 8,722.11 466.65 58.79 0.39 32.26 

Fugitive Emissions Sources 

Coal Handling 

and Storage 

27 7.6 Negl. 

Ash Handling 

and Disposal 

27.2 9.8 

Paved and 

Unpaved Roads 

406.6 79.8 

Total Fugitive 

Emissions 

460.8 97.2 

Total 

Emissions 

1,121.68 701.19 2,718.25 8,722.11 466.65 58.79 0.39 32.26 

1

Lead (Pb) emissions are based on emission factors from AP-42, Section 1.1 (dated 9/98), Table 1.1-17.

Potential to emit used in the above table are based on the following information: 

Criteria Pollutants 

Potential to emit for the ash silo, ball mill slakers, lime storage silos, recycle ash storage 

silos, recycle mixers and Unit 2 cooling tower are based on permitted emissions. 

Page 3 
Potential to emit for NOX, SO2 and PM from the main boilers are based on emission 

limitations included in the permit (SIP/Consent Decree limits for SO2 and PM (0.130 

lb/mmBtu and 0.03 lb/mmBtu, respectively) and Acid Rain limits for NOX (0.46 lb/mmBtu 

for Unit 1 and 0.40 lb/mmBtu for Unit 2)), the design heat input rate and 8760 hours per 

year of operation. PM10 emissions from the main boilers are presumed to be 92% of 

PM emissions (per AP-42, Section 1.1 (dated 9/98), Table 1.1-6). VOC and CO 

emissions from the main boilers are based on AP-42 emission factors (Section 1.1, 

dated 9/98, Tables 1.1-3 and 1.1-19) and maximum coal consumption rate. The 

maximum coal consumption rate is based on the design heat input rate, the heat 

content of the coal from the APEN submitted on April 30, 2008 and 8760 hours per year 

of operation. 

Potential to emit from the auxiliary boiler is based on AP-42 emission factors (Section 

1.3, dated 9/98, Tables 1.3-1, 1.3-3 and 1.3-6), an assumed fuel sulfur content of 0.5 

weight percent and the maximum fuel consumption rate. The maximum fuel 

consumption rate is based on the design heat input rate, an assumed distillate oil heat 

content of 140,000 Btu/gal and 8760 hours per year of operation. It should be noted 

that although this boiler is subject to a Reg 1 PM limitation, that limit has not been used 

to estimate the potential to emit of PM. Since this unit burns a clean fuel and runs 

infrequently, the Division considers that using the Reg 1 PM limit to estimate potential to 

emit is not appropriate for this unit. 

Potential to emit of PM and PM10 from the Unit 1 cooling water tower is based on the 

maximum water circulation rate (design rate in gallons per minute and 8760 hours per 

year of operation), a total solids content of 5602 ppm and 0.001 % drift using the 

equation included in Section II, Condition 6.3.3 of the Title V permit. Potential to emit of 

VOC is based on the maximum water circulation rate and the emission factor included 

in Section II, Condition 6.3.3 of the permit. 

Potential to emit from the coal handling – point sources is based on permitted emissions 

(for Unit 2 equipment) multiplied by 2 to account for an additional 4 transfer points (the 

original Title V permit application, submitted on February 15, 1996, indicated that there 

were 9 transfer points, in permitting the Unit 2 equipment, 5 transfer points were 

identified, one was open and considered a source of fugitive emissions – doubling the 

Unit 2 permitted emissions accounts for the 4 transfer points not considered in 

permitting the Unit 2 equipment). 

Potential to emit from fugitive emissions from haul roads, coal handling and ash 

handling are based on the estimates provided with the source’s comments on the draft 

permit, which were submitted on September 23, 2008. 

Hazardous Air Pollutants (HAP) 

The potential to emit table on page 3 provides total HAPs for the facility. The 

breakdown of HAP emissions by individual HAP and emission unit is provided on page 

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21 of this document. HAP emissions, as shown in the table on page 21, are based on 

the following information: 

Potential to emit of HAPS were only determined for the main boilers, the auxiliary boiler 

and the cooling water towers. HAPS were not estimated for the other emission units as 

HAPs were presumed to be negligible from these sources. 

HAP emissions from the auxiliary boiler are based on AP-42 emission factors (Section 

1.3, dated 9/98, Tables 1.3-9 and 1.3-11) and the maximum fuel consumption rate. 

HAPS from the cooling water tower are based on permitted VOC emissions for the Unit 

2 cooling water tower and calculated potential VOC emissions from the Unit 1 cooling 

water tower (all VOC is assumed to be chloroform). 

Metal HAP emissions from the main boilers are based on AP-42 emission factors 

(Section 1.1, dated 9/98, Table 1.1-18) and the maximum coal consumption rate. 

Mercury emissions from the main boilers are based on the average projected mercury 

emissions that were used in the development of Colorado’s Mercury Rule. HF and HCl 

emission from the main boilers were based on the maximum emission factor, in units of 

lbs/ton, determined from reported HF and HCl emissions and coal consumption on 

several current APENS (2007, 2006 and 2005 data) and the maximum coal 

consumption rate. 

Note that actual emissions are typically less than potential emissions and actual 

emissions are shown on page 22 of this document. 

Compliance Assurance Monitoring (CAM) Requirements

The source addressed the applicability of the CAM requirements in their renewal 

application and is discussed further in the document under Section III – Discussion of 

Modifications Made, under “Source Requested Modifications”. 

MACT Requirements

Case-by-Case MACT - 112(j) (40 CFR Part 63 Subpart B §§ 63.50 thru 63.56)

Under the federal Clean Air Act (the Act), EPA is charged with promulgating maximum 

achievable control technology (MACT) standards for major sources of hazardous air 

pollutants (HAPs) in various source categories by certain dates. Section 112(j) of the 

Act requires that permitting authorities develop a case-by-case MACT for any major 

sources of HAPs in source categories for which EPA failed to promulgate a MACT 

standard by May 15, 2002. These provisions are commonly referred to as the “MACT 

hammer”. 

Owners or operators that could reasonably determine that they are a major source of 

HAPs which includes one or more stationary sources included in the source category or 

subcategory for which the EPA failed to promulgate a MACT standard by the section 

Page 5 
112(j) deadline were required to submit a Part 1 application to revise the operating 

permit by May 15, 2002. The source submitted a notification indicating that Hayden 

Station was a major source for HAPS, with equipment under the source category for 

industrial, commercial and institutional boilers and process heaters). 

Since the EPA has signed off on final rules for all of the source categories which were 

not promulgated by the deadline, the case-by-case MACT provisions in 112(j) no longer 

apply. Note that there is a possible exception to this, as discussed later in this 

document (see under industrial, commercial and institutional boiler and process 

heaters). 

RICE MACT (40 CFR Part 63 Subpart ZZZZ)

The RICE MACT (40 CFR Part 63 Subpart ZZZZ) was signed as final on February 26, 

2004 and was published in the Federal Register on June 15, 2004. An affected source 

under the RICE MACT is any existing, new or reconstructed stationary RICE with a siterating of more than 500 hp.; however, only existing (commenced construction or 

reconstruction prior to December 19, 2002) 4-stroke rich burn (4SRB) engines with a 

site-rating of more than 500 hp were subject to requirements. There are three diesel 

fired engines that are rated at less than 500 hp that are listed in the insignificant activity 

list of the current permit and since all are below 500 hp they are not subject to the RICE 

MACT. 

In addition, revisions were made to the RICE MACT to address engines < 500 hp at 

major sources and all size engines at area sources. These revisions were published in 

the federal register on January 18, 2008. Under these revisions, existing compression 

ignition (CI) engines, 2-stroke lean burn (2SLB) and 4-stroke lean burn (4SLB) engines 

were not subject to any requirements in either Subparts A or ZZZZ (40 CFR Part 63 

Subpart ZZZZ § 63.6590(b)(3)). For purposes of the MACT, for engines < 500 hp, 

located at a major source, existing means commenced construction or reconstruction 

before June 12, 2006. The three engines included in the insignificant activity list are 

considered existing and are therefore not subject to the MACT. Since the source has 

not indicated that any additional engines have been installed at the facility, the Division 

considers that there are no new engines and therefore, no engines subject to the RICE 

MACT. 

Industrial, Commercial and Institutional Boilers and Process Heaters MACT (40 CFR 

Part 63 Subpart DDDDD)

The final rule for industrial, commercial and institutional boilers and process heaters 

was signed on February 26, 2004 and was published in the Federal Register on 

September 13, 2004. There are propane portable heaters included in the insignificant 

activity list in Appendix A of the permit. However, these units do not meet the definition 

of boiler or process heater specified in the rule (the definition of process heater 

excludes units used for comfort or space heat). Therefore the heaters included in the 

insignificant activity list would not be subject to the Boiler MACT requirements. 

Page 6 
In addition, as noted in the renewal application, there is an auxiliary boiler at the facility 

that is not addressed in either Section II of the permit or in the insignificant activity list. 

The boiler is distillate oil-fired, rated at 25 mmBtu/hr and only runs when both of the 

coal-fired units are not running. Since the unit is a large existing liquid fuel unit and is 

therefore only subject to the initial notification requirements as specified in 40 CFR Part 

63 Subpart DDDDD § 63.7506(b)(2). The initial notification was submitted on February 

16, 2005, prior to the March 12, 2005 deadline. 

As of July 30, 2007, the Boiler MACT was vacated; therefore, the provisions in 40 CFR 

Part 63 Subpart DDDDD are no longer in effect and enforceable. The vacatur of the 

Boiler MACT triggers the case-by-case MACT requirements in 112(j), referred to as the 

MACT hammer, since EPA failed to promulgate requirements for the industrial, 

commercial and institutional boilers and process heaters by the deadline. Under the 

112(j) requirements (codified in 40 CFR Part 63 Subpart B §§ 63.50 through 63.56) 

sources are required to submit a 112(j) application by the specified deadline. As of this 

date, EPA has not set a deadline for submittal of 112(j) applications to address the 

vacatur of the Boiler MACT. Although this unit was only subject to initial notification 

requirements, the Division considers that a 112(j) application should be submitted for 

this unit. Therefore, the Division will include this emission unit in Section II of the permit 

and include the requirement to submit a 112(j) application by the deadline set by the 

Division and/or EPA. 

Gasoline Distribution MACTs

A 6,000 gallon underground gasoline tank is included in the insignificant activity list (fuel 

storage and dispensing equipment in ozone attainment areas with a throughput less 

than 400 gal/day, averaged over 30 days are considered insignificant per Reg 3, Part C, 

Section II.E.3.fff). There are potential MACT standards that could apply to this 

operation: Gasoline Distribution (Stage I) – 40 CFR Part 63 Subpart R (final rule 

published in the federal register on December 14, 1994), Gasoline Dispensing Facilities 

– 40 CFR Part 63 Subpart CCCCCC (final rule published in the federal register on 

January 10, 2008) and Gasoline Distribution Bulk Terminals, Bulk Plants, and Pipeline 

Facilities – 40 CFR Part 63 Subpart BBBBBB (final rule published in the federal register 

on January 10, 2008). Both of the rules published on January 10, 2008 only apply at 

area sources. Since this facility is a major source for HAPS, the requirements in those 

rules do not apply to the gasoline tank at this facility. The Gasoline Distribution (Stage 

I) MACT applies to bulk gasoline terminals and pipeline break-out stations. The 

gasoline dispensing equipment at this facility does not meet the definition of a bulk 

gasoline terminal or a pipeline break-out station. Therefore, none of the MACT 

requirements associated with gasoline distribution apply to the equipment at this facility. 

Federal Clean Air Mercury Rule Requirements

The EPA published final rules to address mercury emissions from coal-fired electric 

steam generating units on March 15, 2005. These rules are referred to as the Clean Air 

Page 7 
Mercury Rule (CAMR), which required mercury standards for new and modified 

emission units and provided a trading program for existing units. Under this program, 

sources would be required to get a permit (application due date July 10, 2008) and to 

meet monitoring system requirements (install and conduct certification testing) by 

January 1, 2009. 

However, on February 8, 2008 a DC Circuit Court vacated the CAMR regulations for 

both new and existing units. Therefore, the federal CAMR requirements are not in 

effect, as of the issuance date of this renewal permit. 

State Clean Air Mercury Rule Requirements

Although the Division did adopt provisions from the federal CAMR rule into our Colorado 

Regulation No. 6, Part A, the Division also adopted State-only mercury requirements in 

Colorado Regulation No. 6, Part B, Section VIII. As discussed above the provisions 

from the federal CAMR rule have been vacated and are no longer applicable. While the 

state-only mercury requirements rely in some part of the federal CAMR rule (primarily 

for monitoring and reporting requirements), there are emission limitation and permit 

requirements that do not rely on the federal rule and are still in effect. 

To that end, as an existing mercury budget unit each of these units are required to 

comply with either of the following standards on a 12-month rolling average basis 

beginning January 1, 2014 (Colorado Regulation No. 6, Part B, Section VIII.C.1.b): 

0.0174 lb/GWh OR 80 percent capture of inlet mercury 

These units would be subject to more stringent mercury standards beginning January 1, 

2018 as set forth in Colorado Regulation No. 6, Part B, Section VIII.C.1.c. 

It should be noted that if either Units 1 or 2 qualify as a low emitter (actual mercury 

emissions of no more than 29 lbs/yr), the mercury standards indicated above do not 

apply. 

Since the mercury limitations do not apply until 2014 and the permit application is not 

due until 18 months prior to commencing construction on the mercury control equipment 

(Colorado Regulation No. 6, Part B, Section VIII.D.2) the renewal permit does not 

include the state-only mercury requirements. 

Regional Haze Requirements

The two coal-fired units at this facility are subject to the regional haze requirements for 

best available retrofit technology (BART) and as such a BART analysis was conducted 

and a permit has been issued to address the BART requirements. The BART 

requirements have been included in Colorado Construction Permit 07RO0113B, which 

was issued September 12, 2008. 

Page 8 
Although the BART permit includes emission limitations for PM, SO2 (30-day and 90-

day rolling averages) and NOX, only the NOX emission limitations are new. The PM and 

SO2 limitations that were included in the BART permit are the same limitations included 

in the current Title V permit, which were based on a Consent Decree, which was 

ultimately rolled into Colorado’s SIP (Long-Term Strategy Review and Revision of 

Colorado’s State Implement Plan for Class I Visibility Protection Part I: Hayden Station 

Requirements (8/15/96), as approved by EPA at 62 FR 2305 (1/16/97)). 

The BART permit specifies that PSCo shall demonstrate compliance with the NOX unitspecific emission limits no later than 180 days after initial startup of the NOX control 

equipment for each unit or as expeditiously as practicable within five years following 

EPA approval of the state implementation plan for regional haze that incorporates these 

BART requirements, whichever is earlier. The BART permit also requires that an 

application be submitted to modify the Title V permit to incorporate the BART 

requirements within 12 months after the startup of the NOX control equipment for the 

last unit. Since startup of the NOX control equipment is set for some time in the future 

and the application to modify the Title V permit to include the BART requirements is not 

due until twelve months after installation of the NOX controls for the last unit, the 

renewal permit does not include the provisions from the BART permit (07RO0113B). 

It should be noted that the BART construction permit requires that the source submit 

BART progress reports with their Title V semi-annual reports. This report shall include: 

1) the installation date (expected or actual) for the BART controls, if any; 2) the 

anticipated date on which the source will achieve the BART emission limits set forth in 

this permit (07RO0113B); 3) a description of progress made since the prior BART 

Progress Report toward the installation of BART controls, if relevant, and toward 

achieving the BART emission limits set forth in this permit (07RO0113B). 

III. Discussion of Modifications Made 

Source Requested Modifications

April 1, 2005 Renewal Application 

The source requested the following changes in their April 1, 2005 renewal application. 

Section II, Conditions 5.1 and 5.2

The source has requested a lower limit on the quantity of materials processed through 

the recycle ash silos in order to keep potential pre-control emissions below the major 

source level. The source has requested that the throughput limits be reduced from 

556,000 tons/yr to 296,000 tons/yr and the emission limits for PM and PM10 be dropped 

from 0.17 tons/yr to 0.09 tons/yr. In addition, the source has requested that the 

throughput limits for the recycle mixers be reduced from 556,000 tons/yr to 296,00 

tons/yr and the PM and PM10 emission limits dropped from 0.3 tons/yr to 0.16 tons/yr to 

Page 9 
reflect the throughput changes made to the recycle ash silos. The changes have been 

made as requested. 

Appendix A – List of Insignificant Activities

Auxiliary Boiler 

The source indicated that they had a distillate oil-fired auxiliary boiler on site that is used 

to supply auxiliary steam and steam heat to the plant and runs only when both main 

coal-fired boilers are down for maintenance. The source indicated that although the 

boiler is rated at 25 mmBtu/hr, actual, uncontrolled emissions are less than 2 tons/yr, 

therefore the boiler is exempt from APEN reporting requirements and can be considered 

an insignificant activity and requested that the boiler be included in the insignificant 

activity list. 

The source also indicated that although the facility is a major source for HAPS and the 

requirements in 40 CFR Part 63 Subpart DDDDD, “National Emission Standards for 

Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and 

Process Heaters” apply. Since the unit is an existing large liquid fuel unit, it is only 

subject to the initial notification requirements in accordance with 40 CFR Part 63 

Subpart DDDDD § 63.7506(b)(2). The initial notification was submitted on February 16, 

2005. 

Under the “catch-all” language in Colorado Regulation No. 3, emission units cannot take 

an exemption from APEN reporting requirements, minor source construction permit 

requirements and/or be considered insignificant activities for Title V permitting purposes 

if they are subject to MACT requirements. Although this unit was only subject to the 

initial notification requirements in the Boiler MACT, as discussed previously in this 

document under Section II – Source Description, the Boiler MACT was vacated and the 

provisions in 40 CFR Part 63 Subpart DDDD are not longer in effect and enforceable, 

consequently a 112(j) application is required for this unit. Therefore, the boiler will be 

included in Section II of the permit. 

In addition, it should also be noted under the “catch-all” language in Colorado 

Regulation No. 3, emission units cannot take an exemption from APEN reporting 

requirements, minor source construction permit requirements and/or be considered 

insignificant activities for Title V permitting purposes, if the potential to emit, taking in 

account the full design rate and continuous operations triggers PSD review 

requirements. 

Based on AP-42 emission factors (Section 1.3 (dated 9/98), Table 1.3-1 (for boilers < 

100 mmBtu/hr) and table 1.3-3) and assuming a fuel heating value of 140,000 Btu/gal, 

emissions from the boiler are below the PSD significance level for all pollutants except 

SO2. SO2 emissions were calculated at 56.3 tons/yr based on a fuel sulfur content of 

0.5 weight percent (note that at a sulfur content of less than 0.36 weight percent, 

emissions are below 40 tons/yr). To that end, since the facility is a major stationary 

Page 10 
source for purposes of PSD review, the Division must evaluate whether this auxiliary 

boiler triggered PSD review requirements. 

According to information provided by the source, the auxiliary boiler at the facility 

commenced startup October 31, 1974 (note that this auxiliary boiler replaced one that 

had been installed in 1968). The first PSD rules were published as final on December 

5, 1974 and applied to PM and SO2 emissions at certain listed sources, including fossil 

fuel fired steam electric plants of more than 1000 mmBtu/hr. However, these rules only 

applied to sources that commenced construction on or after June 1, 1975. Therefore, 

the auxiliary boiler did not trigger any PSD review requirements. 

Other Equipment 

In their September 23, 2008 comments on the draft permit the source requested the 

following revisions to the insignificant activity list: 

• Revised the description under Reg 3, Part C.II.E.3.b to indicate three (3) 6,500 

gallon 12.5% sodium hydroxide tanks. 

• Added a 330 gallon sodium hydroxide tank under Reg 3, Part C.II.E.3.n 

• Removed the evaporation ponds from Reg 3, Part C.II.E.3.oo, since they have 

been removed from service 

• Added two transformer oil storage tanks under Reg 3, Part C.II.E.3.aaa 

• Added a forklift refueling tank under Reg 3, Part C.II.E.3.ccc 

• Added a diesel fuel tank (coal handling # 1) under Reg 3, Part C.II.E.3.fff 

Compliance Assurance Monitoring (CAM) Assessment

The CAM requirements apply to any emission unit that uses a control device to meet an 

emission limitation or standard and has pre-controlled emissions above the major 

source level. There are several emission points at the facility that could potentially be 

subject to the CAM requirements. The source provided information regarding the 

applicability of the CAM requirements to the emission units at the facility as discussed 

below. 

Emission sources with no emission limitations

The source identified the following activities as units with no emission limitations and 

therefore not subject to the CAM requirements: portions of the coal handling system 

(conveying system from unloading to pile (includes both crushers) and the conveying 

system from pile to Unit 1), Unit 1 cooling tower, and fugitive emissions from coal 

handling and storage, ash handling and disposal and traffic on paved and unpaved 

roads. The Division agrees, that since these emission sources do not have any 

emissions limitations, the CAM requirements do not apply. 

Page 11 
Emission sources with emission limitations 

The remaining sources have emission limitations and would therefore be subject to the 

CAM requirements if they used a control device to meet that emission limitation and 

have pre-control emissions above the major source level. 

Pre-control emissions below the major source level 

The source identified the following emission sources as having pre-control emissions 

below the major source level and therefore not subject to the CAM requirements: the 

ash silo, remaining portions of the coal handling system (conveying from the pile to Unit 

2), the recycle ash silos, recycle mixers, lime storage silos, ball mill slakers and the unit 

2 cooling water tower. The Division agrees that the coal handling system, the lime 

storage silos, ball mill slakers and the recycle ash mixers have uncontrolled emissions 

below the major source level and therefore are not subject to CAM. The Divisions 

agrees that with the requested change in throughput limits for the recycle ash silos, that 

those emission units also have uncontrolled emissions below the major source level and 

therefore are not subject to CAM. The other sources warrant further review and are 

discussed below. 

Unit 2 cooling water tower – the cooling water tower is equipped with drift eliminators 

which reduce drift to 0.001%. Without the drift eliminators, uncontrolled PM and PM10

emissions from the cooling water tower would exceed the major source level. However, 

the Division considers that the drift eliminators are not considered a control device. In 

40 CFR Part 64, § 64.1, control device means “equipment other than inherent process 

equipment that is used to destroy or remove pollutants prior to discharge to the 

atmosphere...For 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”. The Division considers that the drift 

eliminators are considered inherent process equipment and are passive devices and as 

such are not considered control equipment. Therefore, the Division considers that the 

CAM requirements do not apply to the Unit 2 cooling water tower. 

Ash Silo – there are essentially two separate activities conducted at the ash silo, loading 

and unloading. Separate emission factors are used for each activity and the source 

considers that each activity should be considered separately. Emissions from silo 

loading are controlled by a baghouse and uncontrolled emissions from this activity are 

below the major source level. When ash is unloaded from the baghouse, the ash is 

blended with water in a pug mill located at the base of a silo and then released down a 

chute to an open truck. The source considers that the unloading process is inherent to 

the process, because mixing water with the ash is necessary to make it possible to 

handle during the unloading, transport and disposal of the ash. While the Division is not 

necessarily convinced that the unloading process (mixing ash with water) is inherent 

process equipment, we do not think that it meets the definition of control equipment. 

The preamble to the CAM rule provides more insight into the control technology 

Page 12 
definition and provides the following (from October 22, 1997 federal register, page 

54912, 3rd column, under control devices criterion) 

The final rule provides a definition of “control device” that reflects the 

focus of Part 64 on those types of control devices that are usually 

considered as “add-on” controls.” This definition does not encompass 

all conceivable control approaches but rather those types of control 

devices that may be prone to upset and malfunction, and that are most 

likely to benefit from monitoring of critical parameters to assure that 

they continue to function properly. In addition, a regulatory obligation 

to monitor control devices is appropriate because these devices 

generally are not a part of the source’s process and may not be 

watched as closely as devices that have a direct bearing on the 

efficiency or productivity of the source. 

The Division considers that for the unloading process the operation of the pug mill to 

mix the ash with water is not considered an add-on control device and is not the type of 

device that would benefit from monitoring critical parameters. Therefore, the Division 

agrees that based on the specific provisions in the CAM requirements that unloading 

ash from the silo is an uncontrolled activity. Therefore, the Division considers that the 

CAM requirements do not apply to the ash silo unloading operations. 

Pre-control emissions above the major source level 

The source identified both boilers as having pre-control emissions above the major 

source level. The boilers are both subject to PM, SO2 and NOX emission limitations. 

Controlled emissions of these pollutants exceed the major source level and these units 

use emission controls (baghouse for PM, lime spray dryer for SO2 and low NOX burners 

and over-fire air for NOX) to meet their emission limitations. Therefore, the boilers are 

potentially subject to the CAM requirements. 

The boilers are subject to SO2 and NOX emission limitations under the Acid Rain 

Program (Section III of the current permit). Pursuant to 40 CFR Part 64 § 64.2(b)(1)(iii), 

the CAM requirements do not apply to Acid Rain Program emission limitations. 

Both boilers are subject to several SO2 emission limitations and Unit 2 is subject to a 3-

hour NOX limitation. The current Title V permit requires that the source use continuous 

emission monitoring systems to demonstrate compliance with the SO2 and NOX

emission limitations. Therefore, since the Title V permit specifies a continuous 

compliance method for these emission limitations, the CAM requirements do not apply 

in accordance with the provisions in 40 CFR Part 64 § 64.2(b)(1)(iv). 

CAM does apply to the boilers with respect to the PM emission limitations. Note that 

although the units are both subject to opacity limits, they are not emission limitations 

subject to CAM requirements. The source submitted a CAM plan with their renewal 

application. In their CAM plan, the source proposed visible emissions, pressure 

Page 13 
differential and preventative maintenance as indicators. For visible emissions, 

excursions are identified as an opacity value exceeding 15% for more than 10 seconds 

and any long term increase in opacity of 10% above baseline levels for normal 

operation. For pressure differential, an excursion is defined as an increase in 

differential pressure of 3 inches of water column or greater from normal baseline levels 

accompanied by a sustained increase in opacity over 10%. 

The Division has reviewed the CAM plan submitted and while we accept the plan in 

part, we consider that changes to the plan are necessary. The Division considers that 

the following changes are necessary to the plan. 

Visible Emissions 

The Division accepts the indicator range of 15% opacity for more than 10 seconds and 

will include this in the permit. In their September 23, 2008 comments on the draft 

permit, the source requested that the 15% opacity indicator be revised to specify the 

duration as 60 seconds, rather than 10 seconds. The Division has revised this indicator 

as requested. 

The second indicator range of “a long term increase in opacity emissions from baseline 

conditions during normal operations to opacity emissions greater than 10% over an 

extended period of time” is non-specific as to the time frame and it is not clear that the 

10% opacity represents an acceptable opacity level as an indicator range. Therefore, 

the Division will include as CAM, the compliance provisions required for new 

(constructed after February 28, 2005) electric utility steam generating units subject to 

PM fuel based emission limitations (i.e. units of lb/mmBtu) in 40 CFR Part 60 Subpart 

Da, since such monitoring represents presumptively acceptable monitoring in 

accordance with the provisions in 40 CFR Part 64 § 64.4(b)(1)(4). The compliance 

provisions required by Subpart Da requires that a baseline opacity level be set during a 

performance test and then requires monitoring on a 24-hour average. If the opacity 24-

hour average exceeds the baseline level, then the source must investigate and take the 

appropriate corrective action. Note that as provided for in 40 CFR Part 60 Subpart Da § 

60.48Da(o)(2)(iv), periods of startup, shutdown and malfunction may be excluded from 

the 24-hour average. 

The baseline opacity level determined under the provisions of NSPS Subpart Da specify 

that 2.5% opacity be added to the average opacity determined during the performance 

test, although the baseline opacity level can be no lower than 5% opacity. In their 

September 23, 2008 comments on the draft permit, the source indicated that they 

considered the 2.5% addition to the opacity determined during the performance test to 

be overly stringent, since the units required to conduct this monitoring under NSPS 

Subpart Da are subject to more stringent particulate matter limitations. The Division 

agreed with the source in part and has revised the opacity add-on based on the results 

of the performance test. However, in no case would the baseline opacity be set lower 

than 5%. 

Page 14 
Pressure Differential 

The source has indicated that an excursion would be “an increase in differential 

pressure across a baghouse of 3 inches of water column or greater from the unit’s 

normal specific operating load during normal operating conditions, as well as a 

sustained increase in opacity greater than 10%”. While the proposed language does 

not specifically define the pressure differential for the “unit’s normal specific operating 

load”, in their justification the source indicates that the normal pressure differential 

varies based on the operating load. While the Division understands that it may be 

difficult to identify specific ranges since the appropriate pressure differential varies 

depending on the load, failure to identify the specific range makes it difficult for the 

Division to independently determine whether an excursion has occurred. In addition, as 

indicated in the source’s September 23, 2008 comments on the draft permit, an 

increase or decrease in the pressure differential from the normal level at a specific 

operating load is not necessarily considered an indicator of decreased baghouse 

performance by itself. However, an increase or decrease in the pressure differential 

from the normal level, accompanied by a sustained increase in opacity is an indication 

of potential baghouse problems. 

Since the normal pressure differential is specific to load and cannot be easily defined 

and because pressure differential by itself is not necessarily an indicator of potential 

problems with the baghouse, the Division will not include pressure differential in the 

CAM plan as an indicator. In accordance with 40 CFR Part 64 § 64.4(b)(4), 

presumptive CAM is monitoring included for standards that are exempt from CAM (i.e. 

NSPS standards promulgated after November 15, 1990) to the extent that such 

monitoring is applicable to the performance of the control device (and associated 

capture system). As discussed previously, the Division has revised the source’s CAM 

plan to require that visible emissions be monitored in accordance with the monitoring 

required for new boilers subject to 40 CFR Part 60 Subpart Da. The emission 

limitations and monitoring for new boilers were published as final in the February 27, 

2006 federal register, although changes to the monitoring requirements were published 

as final in the federal register on June 13, 2007. New boilers subject to the revised PM 

emissions limits in 40 CFR Part 60 Subpart Da are required to monitor compliance with 

the PM emission limitation using their COM by establishing a baseline opacity. 

Therefore, the baseline opacity monitoring that the Division is including in the CAM plan 

represents presumptive CAM and the Division does not believe that it is necessary to 

include pressure differential as an additional indicator. 

It should be noted that new sources subject to the NSPS Da PM limitation are also 

required to conduct annual performance tests. While the Division has not included 

annual performance testing in the permit as part of the CAM plan, the Division does 

require performance tests as periodic monitoring to demonstrate compliance with the 

PM limitations. Frequency of testing is annual, unless the results of the testing are 

much lower than the standard, then less frequent testing is allowed. 

Preventative Maintenance 

Page 15 
The Division accepts PSCo’s proposal for semi-annual internal baghouse inspections 

and will include this in the permit. 

In general, the CAM plan has been included in Appendix G of the permit as submitted, 

except that the corrections indicated above have been made to the plan and some 

language has been omitted, revised or relocated in order to streamline the plan. 

September 13, 2007 Minor Modification 

In their modification request received on September 13, 2007, the source requested that 

the permit be revised to increase the VOC emission limit from the Unit 1 cooling water 

tower from 1.8 tons/yr to 1.9 tons/yr. In their application, the source indicated that this 

modification met the requirements for a minor permit modification and requested that 

the minor permit modification procedures in Colorado Regulation No. 3, Part C, Section 

X be used. 

Colorado Regulation No. 3, Part C, Section X.A identifies those modifications that can 

be processed under the minor permit modification procedures. Specifically minor permit 

modification “are not otherwise required by the Division to be processed as a significant 

modification” (Colorado Regulation No. 3, Part C, Section X.A.6). The Division requires 

that “any change that causes a significant increase in emissions” be processed as a 

significant modification” (Colorado Regulation No. 3, Part C, Section I.A.7.a). The 

increase in permitted (potential) emissions associated with this modification is 0.1 ton/yr 

which is below the PSD significance level of 40 tons/yr. Therefore, the Division aggress 

that this modification qualifies as a minor modification. 

No modeling was required for this modification. In general accurate and cost effective 

methods for modeling ozone impacts from stationary sources are not available. 

Therefore, individual source ozone modeling is not routinely requested for construction 

permits. 

Section II, Condition 6.3

The VOC emission limit for the Unit 2 cooling water tower was increased from 1.8 

tons/yr to 1.9 tons/yr as requested. 

Other Modifications

In addition to the modifications requested by the source, 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. 

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The Division has made the following revisions, based on recent internal permit 

processing decisions and EPA comments, to the Hayden Station Operating Permit with 

the source’s requested modifications. These changes are as follows: 

Section I - General Activities and Summary

• Added a column to the Table in Condition 5.1 for the startup date of the 

equipment. 

Section II.1 – Boilers, Coal-Fired

• Removed the note in Condition 1.1.2 that says no further testing is required 

during this permit term 

• Revised the language in Condition 1.1.2 to specify that the performance tests 

shall be used to set the baseline opacity for the CAM plan and specified how the 

baseline opacity shall be determined. 

• Revised the language in Condition 1.2 to specify that the emission factor used 

shall be the emission factor determined from the most recent performance test. 

This change is needed since currently the source is calculating emissions based 

on the results of the 1999 performance test. 

• Revised the table column “Monitoring – Interval” for Condition 1.17 by replacing 

“quarterly” with “annually” 

• Added the CAM language as “new” Condition 1.18. 

Section II.3 – Particulate Matter Emissions – Fugitive Sources 

• In the summary tables, the permit condition numbers listed for the Missile 3B – 

coal unloaded (first table) and ash disposed (second table) were corrected. 

Section II.4 – Particulate Matter Emissions – Ash and Coal Handling

• In their September 23, 2008 comments on the draft permit, the source indicated 

that the Division should indicate either in the permit or the technical review 

document that a control efficiency of 90% is applied to emission calculations for 

the crushers since they are enclosed. Therefore, the Division added language in 

Condition 4.2.1 to indicate that a control efficiency of 90% could be applied to the 

emission calculations for the crusher. 

Section II.9 – Catastrophic Failure (for Purposes of SO2 Emissions)

• Added “malfunction” in parentheses after the word “upsets” in Condition 9.2. 

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Section II.11 – Particulate Matter Emission Periodic Monitoring Requirements

• Removed the language in Condition 11.1 regarding the COMS and opacity 

spikes. The Division considers that with the CAM plan requirements this 

language is no longer necessary. 

• Revised the stack testing language in Condition 11.3 to clarify the frequency of 

testing. The language in the permit addresses testing within the expected fiveyear permit term. The permit terms may be extended, provided a timely and 

complete renewal application has been submitted. For the most part, complete 

and timely renewal applications have been submitted and the term of the permits 

have been extended beyond the originally anticipated five-year permit term. 

Therefore, the language has been revised to set specific deadlines for testing, 

which more appropriately reflects the Division’s intent to require testing for 

particulate matter at a minimum of every five years. To that end, the language 

regarding waiving testing within the last two years of the permit term, in the event 

that annual testing was triggered, has been removed. In general, the results of 

the initial tests have not been above 75% of the standard and annual testing has 

not been triggered. Therefore, the Division considers that the language is not 

necessary. 

Section II.12 – Continuous Emission Monitoring System Requirements

• Some formatting changes were made which affect the numbering of conditions 

under Condition 12.3. 

• Removed the phrase “and the traceability protocols of Appendix H” from 

Condition 12.3.2, since Appendix H of the current version of 40 CFR Part 75 is 

“reserved”. Note that Condition 12.3.1 specifies that the continuous emission 

monitoring systems are subject to the requirements of 40 CFR Part 75 and that 

would include any applicable appendices, regardless of whether or not they are 

specifically called out in this condition. 

• Inserted the phrase “as specified in” between “Part 75” and “Condition 12.3.3.2” 

in Condition 12.3.4.6. 

• Based on citizen comments received on November 6, 2008 during the public 

comment period, the following sentence was added after Condition 12.4.5 (98% 

COMS availability): “Note that compliance with the 98% availability requirement 

is not a shield against enforcement with respect to the continuous emission 

monitoring system requirements in 40 CFR Part 75.” 

• Based on citizen comments received on November 6, 2008 during the public 

comment period, Condition 12.4.6 (monitoring opacity when the COM is down) 

was removed from the permit. 

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• Replaced the phrase “concerning upset conditions and breakdowns” with 

“concerning affirmative defense provisions for excess emissions during 

malfunctions” in Condition 12.5.5 to reflect revisions made to the Division’s 

Common Provisions Regulation. 

“New” Section II.16 – Auxiliary Boiler

As discussed previously in this document, although this boiler has actual uncontrolled 

emissions below the APEN de minimis level, since a case-by-case 112(j) MACT 

application will be required for this emission unit, it must be included in Section II of the 

permit. Although this unit is being included because of the case-by-case 112(j) MACT 

application, the Division considers that it is appropriate to include all applicable 

requirements for this unit, which include the following: 

• APEN reporting requirement - in the event that emissions from this unit exceed 

the de minimis level. The permit will include a requirement to record annual fuel 

consumption and calculate emissions annually to determine whether submittal of 

an APEN is required. 

The permit will include emission factors from AP-42, Section 1.3, dated 

September 1998, Tables 1.3-1 (for boilers < 100 mmBtu/hr burning distillate fuel), 

1.3-3 (for industrial boilers burning distillate fuel) and 1.3-6. The emission factors 

that will be included in the permit are shown in the table below: 

Pollutant Emission Factor (lb/103 gallon) 

PM 2 

PM10 1 

SO2 144S 

NOX 20 

CO 5 

VOC 0.2 

S = weight percent sulfur 

• Reg 1 opacity requirements in Section II.A.1 and 4 (20% / 30%) 

The permit will require that the source conduct method 9 readings annually in 

order to monitor compliance with the opacity standards. The 30% opacity 

requirement applies during certain specific conditions, if the duration of the 

specific condition is less than one hour, then a method 9 is not required for the 

30% opacity standard. 

• Reg 1 particulate matter requirements in Section III.A.1.b (PE = 0.5 x (FI)-0.26, 

where PE = PM limit in lbs/mmBtu and FI = fuel input rate in mmBtu/hr). 

Based on the heat input rate the calculated PM emission limit is 0.216 lb/mmBtu. 

Based on calculation using the AP-42 emission factor, use of No. 2 fuel oil 

Page 19 
ensures compliance with the PM limit provided the heat input of the No. 2 fuel is 

no less than 9,260 Btu/gal. 

• Reg 1 SO2 requirements in Section VI.A.3.b.(i) (1.5 lb/mmBtu) 

Based on calculation using the AP-42 emission factor and assuming a fuel sulfur 

content of 0.5 weight percent, use of No. 2 fuel ensures compliance with the PM 

limit provided the heat input of the No. 2 fuel is no less than 48,000 Btu/gal. 

Section III – Acid Rain Requirements

• Revised the table to include calendar years corresponding to the relevant permit 

term for the renewal. 

• Minor changes were made to the standard requirements, based on changes 

made to 40 CFR Part 72 § 72.9. 

• Removed the requirement in Section 4 to submit a copy of any revised certificate 

of representation to the Division. Submitting a copy of the certificate of 

representation to the permitting authority is not required under the regulations. 

Appendices

• Added the auxiliary boiler to the tables in Appendices B and C.

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PSCo Hayden Total HAP Emissions 

Unit HCl HF Mercury Metals Formaldehyde Hexane chloroform BTEX Boiler 1 (Unit 1) 1.13 6.82 2.86E-02 5.34 Boiler 2 (Unit 2) 1.56 6.82 1.40E-02 7.38 Auxiliary Boiler 4.54E-02 2.58E-02 5.02E-03 Unit 1 Cooling Tower 1.20 Unit 2 Cooling Tower 1.90 Total 2.68 13.64 4.26E-02 12.76 2.58E-02 0.00 3.10 5.02E-03 HAP emissions from cooling tower based on all VOC equal chloroform emissions. 
PSCo Hayden Actual Emissions (tons/yr)

Unit PM PM10 SO2 NOX CO VO

Boiler 1 (Unit 1) 101.1 93 1248.4 4081.5 188.9 22Boiler 2 (Unit 2) 118.9 109.3 1470 3692 246.9 29Aux. Blr* Coal - fugitive 23.45 6.17 Coal - pt source 3.99 1.32 Ash - fugitive 6.8 2.5 Ash - pt source (silo) 12 12 Haul Roads - fug 297.5 58.3 Ball mill slakers 0.584 0.584 Lime storage silos 0.005 0.005 Recycle ash silos 0.009 0.009 Recycle Mixers 0.016 0.016 Unit 1 Cooling Twr** 6.5 6.5 2.Unit 2 Cooling Twr** Total 570.85 289.70 2,718.40 7,773.50 435.80 55.Total - Fugitive 327.75 66.97 0.00 0.00 0.00 0.0Total - Point source 243.10 222.73 2,718.40 7,773.50 435.80 55.*Emissions below APEN de minimis **Emissions are for both cooling towers together Actual emissions from Boilers 1 and 2, lime storage silos, recycle ash silos,recycle mixers and ball mill slakers from APEN 

(2007 data) Actual emissions coal handling based on APEN submitted 4/19/07 (2006 data) Actual emissions from haul roads and cooling towers from APEN submitted 4/19/05 (2004 data) Actual emissions from ash handling based on APEN submitted April 27, 2004 (2003 data) HAP emissions from Units 1 and 2 consist of HCl, HF and selenium 

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