Colorado

40 CFR Part 52, Subpart G, Section 52.320 (d)

EPA-approved source-specific requirements

June 1, 2015

Part 1 of 1 

U.S. EPA Region 8

Office of Partnership and Regulatory Assistance (OPRA)

Air Program

1595 Wynkoop St

Denver, CO 80202-1129
i

Colorado

40 CFR Part 52, Subpart G, 52.320 (d)

EPA-approved source-specific requirements

June 1, 2015

Part 1 of 1

Table of Contents

Title State 

Effective 

Date

EPA 

Effective 

Date

Final Rule 

Citation/Date

Comments

Long-Term Strategy Review 

and Revision of Colorado's 

State Implementation Plan for 

Class I Visibility Protection: 

Part I: Hayden Station 

Requirements

8/15/1996 2/18/1997 62 FR 2305, 

01/16/97

Revision of Colorado's State 

Implementation Plan for Class I 

Visibility Protection Craig 

Station Units 1 and 2 

Requirements

4/19/2001 8/6/2001 66 FR 35374, 

07/05/01
52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 1
mVISION OF 

COLORADO'S STATE IMPLEMENTATION PLAN 

FOR CLASS I VISIBILITY PROTECTION 

CRAIG STATION UNITS I AND 2 REQUIREMENTS 

HEALTHAND ENVIRO"T 

APRIL 19,2001 

PREPARED BY: 

COLORADO Am POLLUTION CONTROL DIVISION 

. .. 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 2
c 

2 

4 

Factors 

a- 

/ 

,.' 

I 

*.- 

IIL ENFORCEABLE PORTION OF THE SIP REVISION 

19 

20 

24 

33 

38 

40 

Definitions 

Emission Controls and Limitations 

Continuous Emission Monitors 

Construction Schedule 

Emission Limitation Compliance Deadlines 

Reporting ~ h _- -- __-- N. ENDNOTES AND REF'ERENCES - 

44 

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Class I Visibility SIP Revision 

Adopted April 19,2001 

ll 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 3
m. 

REQUIREMENTS 

ENFORCEABLE PORTION OF THE SIP ]REVISION: WG STATION UNITS 1 AND 2 

The following provisions, which are taken fiom the Craig Consent Decree, are being adopted 

as part of this revision to the Long-Term Strategy portion of the Colorado Visibility SP, shall be 

met by the Craig Owners, and are intended to be enforceable. The Craig Consent Decree 

numbering scheme has been retained to avoid confbsion between the Craig Consent Decree and 

the SIP, but only those sections pertinent to visibility, necessary to ensure the enforceability of the 

requirements related to visibility, and to demonstrate reasonable progress are being adopted in 

this SIP revision. Also, some changes have been made to the Craig Consent Decree language to 

conform the Craig Consent Decree requirements to the SIP regulatory fiamework. All changes 

are highlighted in bold. The changes that have been made to language in paragraphs 24 and 25 

below which refer to the force maieure provisions of the Craig Consent Decree have been inserted 

to ensure that a demonstration of reasonable progress can be made at this time. 

IL DEFINITIONS 

1. Unless otherwise expressly provided herein, terns used in this SIP component 

pefined below. “SIP component” replaces Decree wherever it appears] that are defined in 

the Clean Air Act, 42 U.S.C. $5 7401, ef seq., or regulations implementing the Clean Air Act, 

shall have the meaning set forth in the Act or regulations. 

2. Whenever the terms set forth below are used in this SIP component, the following 

definitions shall apply: 

(a) “Act” shall mean the Clean Air Act, 42 U.S.C. $5 7401, et seq. 

(b) “Allowance” shall mean an authorization, under Title N of the Act, allowing 

Craig Units 1 and 2 to emit one ton of SO2 in one year 

(c) “Boiler operating day“ shall mean any calendar day in which coal is cornbusted 

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52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 4
in the boiler of a unit for more than 12 hours. If coal is combusted for more than 12 but less than 

24 hours during a calendar day, the calculation of that day's SO2 emissions for the unit shall be 

based upon the average of coal sampling and hourly CEMS data collected during hours in which 

coal was combusted in the unit, and shall not include any time in which coal was not combusted. 

(d) "Business day" shall mean all work days of the week except Saturday, Sunday 

and all Colorado and federal holidays. 

(e) "Calendar day" shall mean any 24 hour period between 12:OO midnight and the 

following midnight in Colorado. 

(f) "CEMS" shall mean continuous emissions monitoring system, which consists 

of the total equipment used to sample, analyze, and record on a continuous basis SOz, NO, or 

any other emissions-related parameters that may be required. 

(g) "COMS" shall mean continuous opacity monitoring system, which consists of 

the total equipment used to sample, analyze, and record opacity on a continuous basis. 

(h) "Coal" shall mean all solid hels classified as anthracite, bituminous, 

subbituminous, or lignite by the American Society of Testing and Materials, Designation D388- 

77. 

(i) "Colorado" shall mean the State of Colorado and the Colorado Department of 

Public Health and Environment, Air Pollution Control Division. 

(j) "Craig Units 1 and 2" shall mean the fossil-fuel fired steam generating plant 

located near the town of Craig, Colorado, including the two boilers and related electric generators 

and all ancillary process and air pollution emission control equipment known as Unit 1 and Unit 2. 

Craig Station also includes Unit 3 that is not subject to this SIP component. 

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(k) "Day" shall mean a calendar day. In computing any period of time under this 

SIP component, except in computing compliance with emission limitations, where the last day 

would fall on a Saturday, Sunday or federal or Colorado holiday, the period shall run until the 

close of the next business day. 

(1) "Decree" shall mean Consent Decree, and any written modifications of such 

Consent Decree. 

(m) "Craig Owners" [replaces ccDefendants" throughout] shall mean Tri-State 

Generation and Transmission Association, Inc., Public Service Company of Colorado, Salt River 

Project Agricultural Improvement and Power District, PacifiCorp and Platte River Power 

Authority and successor owners of the Craig Station Units 1 and 2. 

(n) "EPA" shaU mean the United States Environmental Protection Agency. 

(0) "Excess opacity reading" shall mean each six-minute period of time during 

which the opacity of emissions &om Unit 1 or Unit 2 at the Craig Station exceeds 20 percent, 

regardless of cause or any regulatory exception, as determined by the existing or any EPA and 

Colorado-approved alternative COMS. 

(p) "FGD shall mean flue gas desufirization system. 

(q) "Fossil-fbel" shall mean natural gas, petroleum, coal, and any form of solid, 

liquid, or gaseous he1 derived from such materials for the purpose of creating useful heat. 

(r) "Malfunction" shall mean any sudden, idkequent, and not reasonably 

preventable failure of air pollution control equipment, process equipment, or of a process to 

operate in a normal or usual manner. Failures that are caused in part by poor maintenance or 

careless operation are not mafinctions. 

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52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 6
(s) "NO," shall mean all oxides of nitrogen, except nitrous oxide. 

(t) "Opacity" shall mean the degree to which emissions reduce the transmission of 

light and obscure the view of an object in the background. 

(u) "Paragraph" shall mean a portion of this SIP component identified by an 

arabic numeral. 

(v) [Not applicable to this SIP component] 

(w) [Not applicable to this SIP component] 

(x) "Quarter" shall mean a calendar quarter consisting of three full months, 

beginning on the first day of either January, April, July or October. 

(y) "Rolling average basis" shall mean an average over a period of he consisting 

of the last 30 or 90 boiler operating days, with a new average generated each successive boiler 

operating day, based on the sum of the averages for the last 30 or 90 boiler operating days. 

(2) "Section" shall mean a portion of this SIP component identified by a capital 

roman numeral. 

(aa) "Shutdown" shall mean the cessation of operation of Unit 1 or Unit 2 at Craig 

Station for any purpose or reason. 

(ab) mot applicable to this SIP component] 

(ac) "Startup" shall mean the setting in operation of Unit 1 or Unit 2 at Craig 

Station for any purpose or reason. 

(ad) "S02" shall mean sulfur dioxide. 

(ae) "Title V" shall mean Title V of the Clean Air Act, 42 U.S.C. 5 7661 through 

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52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 7
(af) “Unit 1” shall mean the steam generating unit and related electric generating 

and air pollution emission control equipment that commenced commercial operation at the Craig 

Station in 1980, including all changes made, and to be made, to such equipment thereafter. 

(ag) Wnit 2” shall mean the steam generating unit and related electric generating 

and air pollution emission control equipment that commenced commercial operation at the Craig 

Station in 1979, including all changes made, and to be made, to such equipment thereafter. 

(ah) “Upset condition” shall mean an unpredictable failure of air pollution control 

or process equipment which results in the violation of an emission limit in this SIP component 

and which is not due to poor maintenance, improper or careless operations, or is otherwise 

preventable through exercise of reasonable care. 

(ai) “Consent Decree” or “Craig Station Consent Decree’’ shall mean the 

Consent Decree entered in Sierra Club v. Tri-State Generation & Transmission 

Association, Inc., et al., Civil Action No. 96-N-2368, U.S. District Court for the District of 

Colorado. 

(aj) “SIP Component” shall mean the language from the Craig Station 

Consent Decree, as modified herein, and included in this section ITI of this April 2001 

revision of the Long-Term Strategy portion of Colorado’s Class I Visibility Protection 

Program State Implementation Plan. 

IIL JURISDICTION AND VENUE 

3. 

4. 

[Not applicable to this SIB component.] 

[Not applicable to this SIP component.] 

N. APPLICABILITY 

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5. 

6. 

mot applicable to this SIP component.] 

[Not applicable to this SIP component.] 

V. EMISSION CONTROLS AND LIMITATIONS 

7. Craig Owners shall, at all times including periods of startup, shutdown, and 

malfunction, maintain and operate Craig Units 1 and 2 in a manner consistent with good air 

pollution control practices for minimizing emissions. 

8. Craig Owners shall install the following control equipment, and shall achieve the 

following emission limitations for Craig Units 1 and 2 in accordance with the deadlines set forth in 

Sections VII and VIU: 

(a) Particulate Matter 

(i) Craig Owners shall install and operate fabric filter baghouses 

(“baghouses”) on Craig Units 1 and 2, and make any other capital and operational modifications 

necessary to meet, by the deadlines in Section Wa; the final particulate matter standards and 

limitations described below. 

(ii) The particulate matter limitations for Craig Units 1 and 2 shall be as 

follows: 

(A) 0.03 pounds of particulate matter per million Btu heat input, 

Compliance shall be established by EPA test methods; 

(B) opacity not in excess of 20 percent, as averaged over each 

separate 6-minute period within an hour, beginning each hour on the hour. This limit shall apply 

at all times when air pollutants are being discharged into the atmosphere, but does not apply when 

the boiler and all fans that move flue gas in the unit are off Under this limit, during periods of 

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52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 9
building a new fire, cleaning of fire boxes, startup, soot blowing, any process modification or 

adjustment or occasional cleaning of control equipment, Craig Owners shall not cause or allow 

the emission of air pollutants in excess of 30 percent opacity for a period or periods aggregating 

more than 6 minutes in any 60 consecutive minutes (SIP limit from 5 C.C.R. 1001-3, Section 

II.A.1. and 5 C.C.R. 5 1001-3, II.A4, approved by EPA on December 3, 1986); 

(1) Craig Owners shall not cause or allow the emission of 

air pollutants in excess of 30 percent opacity during any startup, regardless of cause or reason, for 

a period or periods aggregating more than 6 minutes in any 60 consecutive minutes. A startup is 

never an upset condition, however, an upset condition can occur afker initiation of a startup in 

which case only excess emissions caused by such upset condition may be excused. 

(2) Craig Owners shall not cause or allow the emission of 

air pollutants in excess of 20 percent opacity during any shutdown, unless excused by an upset 

condition. 

(C) opacity no greater than 20 percent except for one six-minute 

period per hour of not more than 27 percent opacity, as averaged over each separate 6-minute 

period within an hour, beginning each hour on the hour. Emissions during startup, shutdown and 

malfunction are excused under this opacity limit. The SIP exceptions at 5 C.C.R. $ 1001-3, 

EA4 (approved by EPA on December 3, 1986), including “cleaning of new fire boxes,” “soot 

blowing,” and “any process modification or adjustment or occasional cleaning of control 

equipment,” are not excused. (NSPS limit from 40 C.F.R. 3 60.42(a)(2) and 40 C.F.R. 

5 60.1 l(c)). 

(iii) An opacity reading in excess of the limitations in subparagraph 

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8(a)(ii)(B) may be excused by an upset condition, and an opacity reading in excess of the 

limitations in subparagraph S(a)(ii)(C) may be excused by a malfunction, [deletion] if Craig 

Owners demonstrate [deletion] such reading was the result of an upset condition or 

malfunction. peletion]. If Craig Owners seek to excuse any opacity reading in excess of the 

limitations above, they must note Colorado as soon as possible by telephone, but no later than 

two hours after the start of the next business day. In addition, for purposes of this SIP 

component, any claim of excuse must be made in writing in Craig Owners’ next quarterly report 

following such condition, and must describe: (1) the date and time telephone notification wss 

given to Colorado, including the person to whom notification was given either directly or through 

a voice mailbox, (2) the cause of the condition, (3) all actions Craig Owners took to correct the 

condition, and (4) all actions Craig Owners will take to prevent the condition fiom recurring. 

(iv) Craig Owners shall file quarterly excess emission reports (EERs) that 

set forth all 6-minute average opacity readings in excess of 20 percent in chronological order. 

Craig Owners shd indicate in their EERs the specific times in which the fans that move flue gas 

are on and off. At Craig Owners’ election, periods of “process off and “process on” may be 

identified in a separate document included with, or attached to, the EER. Sufficient explanation 

to support any claim of upset condition or malfbnction shall be provided at the time the EER is 

filed. 

(v) Craig Owners shall perform particulate matter stack tests at Craig 

Units 1 and 2 within 100 calendar days after flue gas is first passed through the baghouses and 

thereafter as directed by Colorado or EPA, and shall submit all results and a.comglete description 

of the tests to Colorado in the next quarterly report following Craig Owners’ receipt of the 

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results. 

(vi) Compliance with the opacity emission limitations in Section V, 

subparagraph S(a), shall be determined on a continuous basis using data from the current COMS 

or an EPA and Colorado-approved COMS at an alternative location, and may be verified on an 

intermittent basis by EPA Method 9,40 C.F.R. Part 60, Appendix A. 

(vii) Until such time as Craig Owners install baghouses, Craig Owners 

shall, at all times, optimally operate the existing electrostatic precipitators and all other ESPrelated equipment at Craig Units 1 and 2 consistent with good air pollution control practices for 

minimizing opacity and particulate matter emissions. 

(b) Sulfur Dioxide (Sod 

(i) Craig Owners shall treat one hundred percent (100%) of the flue gas 

from Craig Units 1 and 2 in the respective FGDs during all operating conditions except for those 

time periods when an upset condition makes it impossible to treat 100% of the flue gas. 

However, upset conditions do not apply to the SO2 emission limitations in this Sedon and 

emissions of SO2 during any such period shall not be excluded fiom the determination of Craig 

Owners’ compliance with the SO2 emission limitations. 

(ii) Craig Owners shall enhance the current FGDs for Craig Units 1 and 

2 by designing, evaluating, and installing upgrades which will reliably treat 100% of the flue gas. 

Craig Owners shall be generally guided by those enhancements described as “Option 3” in the 

Craig Station FGD System Modifications - Analyses of Potential Alternatives; Project Design 

Basis and Cost Estimates, dated August 3 1, 1999. Craig Units 1 and 2 shall be designed to meet 

at least a 93.7% removal rate as was calculated in the FGD study. In the event that Craig 

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52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 12
Owners intend to deviate fiom Option 3, prior to implementation Craig Owners shall submit 

their complete design plans and required implementation time to [deletion] Colorado and EPA for 

review. 

(iii) Craig Owners shall have the right to evaluate the reliability and 

efficiency of the enhancements described as Option 3 and may, in Craig Owners’ sole discretion, 

replace such upgrades with technology and operations which may better integrate with the current 

operations of Craig Units 1 and 2, includmg the existing FGD and other systems, while still 

designing the upgrades to meet at least the 93.7% removal rate and reliably treat 100% of the flue 

gas for SO2 removal. peletion]. 

(iv) Craig Owners shall design, construct and operate its FGD upgrades 

and related equipment to meet the emission limitations, including the percentage reduction 

requirement, set forth below. 

(v) The sulfur dioxide mass emission limitations for Craig Units 1 and 2 

shall be as follows: 

(1) 0.160 pounds per million Btu heat input on a 30 boiler 

operating day rolling average basis; 

(2) 0.130 pounds per million Btu heat input on a 90 boiler 

operating day roUig average basis. 

(vi) Compliance with the SO2 mass emission limitations in subparagraphs 

(b)(v)(l) and (2) herein shall be determined using data fkom the SO2 CEMS that Craig Owners 

are required to operate and maintain pursuant to Section vl[. The SO2 CEMs shd be placed in a 

location to accurately monitor 100% of the flue gas, including any periods of by-pass. 

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52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 13
(vii) Sulfkr dioxide controls at Craig Units 1 and 2 shall achieve a ninety 

percent (90%) reduction of SO2 on a 90 boiler operating day rolling average basis measured from 

coal to stack as described in subparagraph (viii) below, unless Craig Owners show, for any unit, 

that the SO2 reduction equipment was designed and constructed to meet such limit but that for 

reasons beyond Craig Owners’ control, despite the fact that Craig Owners had designed and 

constructed the SO2 reduction equipment to meet the 90 percent limit, they could not meet such 

limit (hereinafter show in^'). As part of their Showing Craig Owners must establish the 

maximum SO2 reduction attainable, and such maximum amount (minus 2 percentage points if 

Craig Owners elect a 90 day rolling average or minus 3 percentage points if Craig Owners elect 

a 30 day rolling average) shall constitute Craig Owners’ final SO? reduction lit. If Craig 

Owners make this Showing, in no event shall the final limit be less than eighty five percent (85%) 

reduction of SO;? on a 30 boiler operating day rolling average basis, or less than eighty six percent 

(86%) reduction of SO2 on a 90 boiler operating day rolling average basis, measured &om coal to 

stack Craig Owners must make such Showing on or before the dates by which the 90 percent 

limit must be achieved pursuant to paragraph 25fb). In the event Craig Owners present a 

Showing that is disputed in accordance with the Consent Decree, the 90% limit shall be stayed 

and the issue shall be decided as set forth in the Consent Decree. During the pendency of any 

such stay, the limit shall be Craig Owners’ final SO2 reduction limit derived from their Showing 

as described above. [Deletion]. 

(Viii) Compliance with the SO2 percentage reduction requirement shall be 

determined as follows: 

(1) Based on the coal sampling analysis, a daily potential SO2 

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emission rate for coal, expressed in lbs/mmBtu, will be established. Using this daily SO2 emission 

rate, for each boiler operating day an arithmetic average of the potential SO2 emission rates for 

the last 30 or 90 successive boiler operating days (including the boiler operating day for which the 

calculation is being performed) shall be calculated to establish the SO2 rolling average basis that is 

referred to as E, in the equation below. Each dayrs potential S@ emission rate for coal, before 

the calculation above is performed, will be provided in the reports required in paragraph 28(c); 

(2) The rolling average basis SO2 stack emission rate will be 

calculated using CEMS data collected during all operating hours in a boiler operating day. To 

establish the SO2 rolling average basis, all hourly emission rates, as derived from the CEMS data, 

and expressed in lbs/mmBtu, for the last 30 or 90 successive boiler operating days (including the 

boiler operating day for which the calculation is being performed), will be used to calculate that 

day’s SO;! rolling average basis that is referred to as E,, in the equation below. Each day’s SO, 

stack emission rate for the hours that the boiler was operating, before the calculation above is 

performed, will be reported under paragraph 28(c); 

(3) The 30 or 90 day rohg average basis percent SO2 reduction, 

referred to herein as %R, shall be calculated for each boiler operating day as follows: 

%R= 100 ( 1.0 - E&J 

Coal sampling will follow the most current version of ASTM D2234, Stanckrd Practice 

for Collection of a Gross Sample of Coal. Sample preparation will follow the most current 

version of ASTM 2013, StanhrdMethod of Preparing Coal Samples for Analysis. Sufir 

analysis will follow the most recent version of ASTM D4239, Standard Test Methods for SuZficr 

in the Analysis Sample of Coal and Coke Using High Temperature Tube Furnace Combustion 

Class I Visibility SIP Revision 

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52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 15
Mefhodr. 

(k) Regardless of Craig Owners' compliance with (and without relieving 

Craig Owners of the obligation to comply with) the emission limitations and other requirements 

set forth in this Section, in no event shall Craig Owners operate any boiler for more than 72 

consecutive hours at a unit without an SO2 control system achieving some reduction of SO2 

emissions at that unit. Following shutdown pursuant to this subparagraph, Craig Owners shall 

only restart the boiler on a unit when the SO2 control equipment is operating normally. 

(c) Nitrogen Oxides 

(i) Craig Owners shall select, install and operate state-of-the-art lowNO, burners utilizing two stage combustion with supplemental overfire air on Craig Units 1 and 

2. Craig Owners shall design and construct such control equipment to meet the emission 

limitations set forth below. 

(i) Craig Units 1 and 2 shall meet a NO, limit of 0.30 pounds per million 

Btu heat input on a calendar year annual average basis. Upset conditions do not apply to this limit 

and emissions of NO, during any such period shall not be excluded &om the determination of 

Craig Owners' compliance with the NO, emission limit. Compliance shall be determined on a 

unit-specific basis using data from NO, CEMS that Craig Owners are required to maintain, 

calibrate and operate. 

9. Craig Owners have the burden of proof to demonstrate the application of any 

exception to any applicable emission limit, and must provide sufficient demonstration of the 

application of any exception in their contemporaneous excess emission reports (EERs). 

VI. C0IV"UOUS EMISSION MONITORS 

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10. At all tirnes [deletion] Craig Owners shall maintain, calibrate and operate COMS to 

measure accurately the opacity of emissions at Craig Units 1 and 2 in full compliance with the 

requirements found at 40 C.F.R. Part 60, Appendix B, Specification 1, and 5 C.C.R. 1001-3, 

W.A and B. 

1 1. Craig Owners are currently monitoring opacity with COMS located at the 300 foot 

level in the stacks of Craig Units 1 and 2. Craig Owners intend to change the current location of 

the COMS to a location after the baghouses and before the FGDs. Craig Owners shall seek 

approval fiom EPA and Colorado for any such alternative COMS location, and approval from 

EPA and Colorado to install and thereafter operate a continuous monitoring system to measure 

pressure differential across the mist eliminator that indicates whether FGD generated particulate 

matter emissions are minimized. Any request for approval described above shall be submitted to 

EPA and Colorado no later than 60 days after completion of the FGD design activities set forth at 

paragraphs 24(a)(iii) and 24(b)(Z). li)eletion]. Until EPA and Colorado grant final approval for 

an alternative location, the current COMS will be used for compliance purposes with all opacity 

standards, and at no time shall Craig Units 1 and 2 be operated without an approved method of 

continuous opacity monitoring. 

In addition to any other requirements that may apply to an alternative location of opacity 

monitoring, Craig Owners shall ensure after installation of the baghouse and FGD upgrades that 

the new system is reading comparable opacity to what is read by the current COMS under dry 

stack conditions. Flue gas may be by-passed around the FGD as necessary during the test in 

order to achieve dry stack conditions. Comparability will be determined based on simultaneous 

readings &om the COMS at the current and new locations during the COMS recertification 

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process required at paragraphs 16 and 17. This comparability analysis may take into account the 

allowable variation associated with the measurements of opacity by each COM after each CON is 

calibrated to minimize any such variation. Peletion]. 

In any request for approval of an alternative COMS location and FGD monitoring system, 

Craig Owners shall provide the manufacturer's specified normal operating pressure drop range 

across the mist eliminator at given operating gas flow rates and supporting documentation that 

demonstrates that such range will most effectively minimize particulate matter emissions fkom the 

FGD. The pressure drop range submitted by Craig Owners shall be shown to be consistent with 

the normal range established for other similar mist eliminator systems. Within 180 days after flue 

gas first passes through the upgraded FGDs, Craig Owners may submit to EPA and Colorado for 

approval [deletion] a revised pressure drop range based on actual testing data from the applicable 

unit that will more effectively minimize particulate matter emissions compared to the 

manufacturer's specified range. 

Craig Owners shall continuously and accurately monitor and report to Colorado, 

pursuant to Section IX, the hourly average pressure drop across the mist eliminator and the 

hourly average flow rate for each unit at Craig Units 1 and 2. Craig Owners" pressure 

monitoring system shall be of sufficient sensitivity and reliability to enable consistent, continuous 

and effective monitoring of the pressure drop range. Craig Owners shall take alI necessary 

corrective actions to maintain the pressure drop within the applicable range. [Deletion]. 

12. Craig Owners shall provide to Colorado on a quarterly basis all excess emission 

reports (EERs) for Craig Units 1 and 2 that describe in the form required by this SLP component 

all excess readings, all claimed exceptions, and all other information required by law. 

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13. At all times [deletion] Craig Owners shall maintain, calibrate and operate CEMS at 

Craig Units 1 and 2 to measure accurately SO2 and NO, emissions &om each unit, as well as flow 

and COZY in full compliance with the requirements found at 40 C.F.R. Parts 60 and 75. Nothing 

herein shall preclude Craig Owners fiom installing, certifying and operating integrated CEMS 

equipment to measure S02, NO,, C02 or opacity, or any combination thereof 

14. Craig Owners shall maintain, calibrate and operate a method of coal sampling and 

analysis to determine accurately, pursuant to methods identified in paragraph S(b)(viii), the 

potential emissions fiom sufir in the coal entering the boiler reported in pounds of SO2 per 

million Btu heat input. 

15. Craig Owners shall ensure that any modifications to any COMS or CEMS 

necessitated by Craig Owners' actions under or in fbrtherance of this SIP component shall be 

completed prior to the completion of construction of the SO2, NO,, and particulate control 

systems for Unit 1 and Unit 2, respectively. 

16. Craig Owners shall recerti@ all COMS and CEMS or? Craig Units 1 and 2 by the 

following dates: 

Opacitv COMS: Within 60 boiler operating days after passing flue-gas through the 

baghouses for each unit, and within 60 boiler operating days after passing flue gas through the 

upgraded scrubber and NO, control systems for each unit. 

SO? CEMS: Within 60 boiler operating days after passing flue gas through the upgraded 

scrubber system for each unit. 

NO, CEMS: Within 60 boiler operating days after the NO, burner and overfire air 

upgrades become operational on each unit. 

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17. In recertlfjrlng such COMS and CEMS, Craig Owners shall meet all requirements in 

40 C.F.R. Parts 60 and 75 for initial certification. In particular, Craig Owners shall demonstrate 

that the SO2 and NO, CEMS are accurately monitoring 100 percent of the flue gas, including any 

periods of by-pass, and are accurately reflecting SO2 and NO, concentrations exiting the stack, 

that the COMS are accurately monitoring the opacity of emissions, and that Craig Owners have 

resolved any problems with laminar or cyclonic flow, uncombined water droplets, or any other 

problem that may be affecting the performance of the CEMS or COMS. On at least a quarterly 

basis during the first year after recertification of the SO2 CEMS, Craig Owners shall contract 

with a private laboratory to analyze a split sample fiom a composite coal sample to ensure that 

Craig Owners’ coal analysis system is accurately reporting Btu, subr and potential SO2 

emissions. Craig Owners shall report the results of such analyses in their quarterly reports. 

Craig Owners shall provide at least 30 days prior written notice to Colorado and EPA of the 

date@) Craig Owners intend to perform the recertification tests required by this paragraph and 

shall allow Colorado and EPA to be present for such tests. 

18. Beeg within 30 and 90 boiler operating days (depending on the applicable SO2 

limit in Section V) from the date flue gas is first passed through the upgraded SO2 control 

equipment for each unit, Craig Owners shall calculate the following: 

(a) For each boiler operating day, the percentage of SO2 removal consistent with 

paragraph 8(b)(Viii), and 

(b) For each boiler operating day, the SO2 mass emission rate for 30 and 90 boiler 

operating days calculated consistent with paragraph 8(b)(v&)(2). 

19. Craig Owners shall report to Colorado on a quarterly basis each 30 day rolling 

35 

Class I Visibility SIP Revision 

Adopted April 19,2001 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 20
average and each 90 day rolling average during the prior quarter that exceeded or fded to 

comply with the SO2 emission limitations contained in this SIP component. Each quarterly 

report shall include a list of the hours excluded for any reason from the determination of Craig 

Owners’ compliance with the SO2 limits, and a list of times in which flue gas is by-passed around 

the FGD. 

20. Beginning within 30 boiler operating days of the date of the first startup of a unit 

following installation of the upgrades to the NO, reduction systems for each unit, Craig Owners 

shall calculate hourly average NO, concentrations in pounds per million Btu, in accordance with 

the requirements of 40 C.F.R. Part 75. Craig Owners shall use the hourly averages to calculate 

calendar year averages in accordance with the requirements of 40 C.F.R. Part 75. 

21. Craig Owners shall report to Colorado on a quarterly basis Craig Owners’ year-todate average NO, emission rate for that calendar year. 

22. For any hour that valid, quality-assured continuous emission monitor data for a unit 

is unavailable, SO, NO, and C02 emissions shall be calculated in accordance with the missing 

data substitution procedures contained in 40 C.F.R. Part 75. For any day in which daily coal 

sample data are not available, the average potential SO2 emission rate of coal from the previous 

30 days as calculated in paragaph S(b)(Viii) shall be substituted. 

23. Craig Owners shall be bound by the data from their COMS, SO2 CEMs and coal 

sampling data, and NO, CEMS. Craig Owners may not challenge the accuracy or credibility of 

their COMS, SO2 CEMs and coal sampling data, and NO, CEMS in any enforcement action 

unless otherwise expressly allowed by statute or regulation. 

VIL CONSTRUCTION SCHEDULE 

36 

Class I Visibility SIP Revision 

Adopted April 19,200 1 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 21
24. Craig Owners shall design, contract, construct and complete all particulate matter, 

SOZ, and NO, control systems required by this SIP component according to the following 

schedule, subject to a force majeure determination pursuant to the Craig Station Consent 

Decree, including a decision by the Court to limit force maieure pursuant to paragraph 50 

of the Craig Station Consent Decree. However, if any schedule has been extended or will 

be extended pursuant to such a force maieure determination or determinations by more 

than 12 months beyond the particular deadline, the Division shall request the Commission 

reopen (with public notice and hearing) the Long-Term Strategy element, of Colorado’s 

Class I Visibility Protection Program State Implementation Plan to reevaluate the 

demonstration of reasonable progress, and to revise the State Implementation Plan as may 

be necessary to ensure that the emission limitations are met. In no event shall these force 

maieure provisions be construed to authorize or create any preemption or waiver of any 

State or federal air quality law, or of any requirement contained in the Consent Decree and 

incorporated into this STP. 

Activity 

(i) Initiate design activities for baghouses, 

FGD and NO, upgrades 

Deadline 

l/O l/O 1 

(ii) Issuance of binding contract to construct, or contracts 

to design and construct: 

For baghouses 

For FGD upgrades 

For NO, upgrades 

(iii) Substantial completion of design activities 

37 

Class I Visibility SIP Revision 

Adopted April 19,2001 

7/3 1/01 

313 1/02 

113 1/03 

1/01/03 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 22
required for commencement of 

construction of baghouses, FGD and NOx 

control equipment 

Commencement of physical, on-site construction of 

baghouse, FGD and NO, upgrades. Dates from contracts 

described at (i) above to be provided by Craig Owners 

to Colorado. within 15 days of execution of each contract, 

and shall become enforceable deadlines under this SIP Component. 

Completion of Construction and initiation of startup 

of all upgrades 1 213 1 I03 

Provide an opportunity for on-site inspection 12/3 1/03 - 6/30/04 

by Colorado and EPA of control equipment 

installation 

ACtiviQ Deadline 

Initiate design activities for baghouses, 

FGD and NO, upgrades 

110 1/0 1 

Issuance of binding contract to construct, or contracts 

to design and construct: 

For baghouses 713 1/01 

For FGD upgrades 313 1/02 

For NO, upgrades 113 1 I03 

Substantial completion of design activities 

required for commencement of 

construction of baghouses, FGD and NO, 

control equipment 

1/01/03 

Commencement of physical, on-site construction of 

baghouse, FGD and NO, upgrades. Dates from contracts 

described at (ii) above to be provided by Craig Owners 

to Colorado within 15 days of execution of each contract, 

and shall become enforceable deadlines under this SIP component. 

Completion of construction and initiation of startup 

of all upgrades 6/3 0/04 

38 

Class I Visibility SIP Revision 

Adopted April 19,2001 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 23
(vi) Provide an opportunity for on-site inspection 

by Colorado and EPA of control equipment 

installation 

6/30/04 - 12/3 1/04 

VIIL EMISSION LIMITATION COMPLIANCE DEADLINES 

25. Craig Owners' obligation to meet the particulate matter, SOz, and NO, emission 

limitations set forth in Section V shall commence on the dates listed below, subject to a force 

maieure determination pursuant to the Craig Station Consent Decree, including a decision 

by the Court to limit force maieure pursuant to paragraph 50 of the Craig Station Consent 

Decree. However, if any schedule has been extended or will be extended pursuant to such a 

force maieure determination or determinations by more than 12 months beyond the 

' 

particular deadline, the Division shall request the Commission reopen (with public notice 

and hearing) the Long-Term Strategy element of Colorado's Class I Visibility Protection 

Program State Implementation Plan to reevaluate the demonstration of reasonable 

progress, and to revise the State Implementation Plan as may be necessary to ensure that 

the emission limitations are met. In no event shall these force maieure provisions be 

construed to authorize or create any preemption or waiver of any State or federal air 

quality law, or of any requirement contained in the Consent Decree and incorporated into 

this SIP. 

(a) Particulate Matter: 

(i) For Unit 1, within 180 days after completion of construction of 

baghouse system, or by April 30,2004, whichever date is earlier. 

(ii) For Unit 2, within 180 days after completion of construction of 

39 

Class I Visibility SIP Revision 

Adopted April 1 9,200 1 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 24
baghouse system, or by October 3 1,2004, whichever date is earlier. 

@> s82: 

(i) For Unit 1, within 180 days after completion of construction of the 

additional SO2 control equipment, or by June 30,2004, whichever date is earlier, Craig Owners 

shall achieve the SO2 mass emission Iits at paragraph S(b)(v), and shall achieve an 85 percent 

reduction of SO2 emissions on a 30 boiler operating day rolling average basis measured from coal 

to stack. Within 270 days of the initial compliance date above, but no later than March 3 1,2005, 

Craig Owners shall achieve the 90 percent SO2 reduction limit, subject to the provisions of 

subparagraph S(b)(vii); and 

(ii) For Unit 2, within 180 days after completion of construction of the 

additional SO2 control equipment, or by December 3 1,2004, whichever date is earlier, Craig 

Owners shall achieve the SO2 mass emission limits at paragraph S(b)(v), and shall achieve an 85 

percent reduction of SO2 emissions on a 30 boiler operating day rolling average basis measured 

from coal to stack. Within 270 days of the initial compliance date above, but no later than 

September 30,2005, Craig Owners shall achieve the 90 percent SO2 reduction limit, subject to 

the provisions of subparagraph S(b)(vii). 

(c) NO,: Design, construction, installation, and testing of overfire upgrades must 

be completed by June 30,2004 for Unit 1 and December 3 1,2004 for Unit 2. 

K. REPORTING 

26. Within thuty days after the end of each quarter, beginning with the report for the 

first quarter of 2001 [deletion], Craig Owners shall provide a quarterly report to Colorado 

regarding the immediately preceding quarter that contains all of the information this Slop 

Class I Visibility SIP Revision 

Adopted April 1 9,200 1 

40 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 25
component requires Craig Owners to report on a quarterly basis. 

27. 

28. In specific, each quarterly report shall include: . 

[Not applicable to this SIP component.% 

(a) A description of construction deadlines achieved, progress made toward 

meetkg fbture deadlines, and any actual, expected or reasonably likely delays; 

@) AU elements of the opacity, SO2 and NO, quarterly excess emission and 

monitoring report [deletion]; 

(c) After installation of the SO2 control equipment upgrades, ‘the required 

quarterly reports for SO2 emissions (including emissions during alI excluded periods as well as 

SO2 content calculated fiom coal for each day, the SO;! stack emissions for each day, and each 

day’s SQ2 percent removal rate), coal s&r analyses, pressure drop and flow data relating to the 

mist eliminators, and quarterly reports required under 40 C.F.R. Part 60 containing CEMS quality 

assurance information; 

(d) After installation of the NO, control equipment upgrades, the required yearto-date quarterly reports for NO, emissions; and, 

(e) [Not applicable to this SIP component] 

29. pot applicable to this SIP component,] 

30. Craig Owners’ requirement to provide quarterly reports is in addition to any other 

notification or report required by this SIP component, unless such notitication or report is 

required on a quarterly basis. Furthermore, nothing in this SIP component shall be interpreted to 

either excuse or diminish Craig Owners’ obligation to provide any other reports, notices or other 

documents to the public, or local, state or federal officials. 

Class I Visibility SIP Revision 

Adopted April 19,2001 

41 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 26
52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 27
Rule: 

State Colorado 

State Agency Department of Public Health and Environment 

Affected Area EPA-approved source specific requirements 

Regulation Visibility 

Rule Number 

Rule Title Long-Term Strategy Review and Revision of Colorado's State 

Implementation Plan for Class I Visibility Protection: Part 1: Hayden 

Station Requirements 

State Effective Date 08/15/1996 

State Adoption Date 08/15/1996 

EPA Effective Date 02/18/1997 

Notice of Final Rule Date 01/16/1997 

Notice of Final Rule Citation 62 FR 2305 

Comments 

~ 

Hayden Station .12S!t 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 28
NOTICE OF lF*INAL 

Pollution Prevention and C 

NOTICE IS HEREBY GIVEN that 

2001, and in compliance With the re 

the Colorado Air Quality Control Co 

aking hearing was held on Apd 19, 

ns 25-7-105(1), 109, and 1002 C.R.S., 

‘TcIass I Visiiility Prot emat of the State Implementation Plan”. 

The amendmeats adopted by th 

decree that will limit the emissi 

ten microns andless. The 

ofate the rquirements of a fedesal consent 

mission represent reasonable 

deraf Clean Air Act and resolve the 

orest Service far the Mount Zirkel 

Wdderness Area. 

rrY CONTROL COMMISSioN 

k 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 29
52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 30
LONG-TERM STRATEGY REVIEW AND .REVISION OF 

COLORADO'S STATE IMPLEMENTATION PLAN 

FOR CLASS IVISIBILITY PROTECTION 

PART I: HAYDEN STATION REQUIREMENTS 

COEOUDO DEPARTMENT OF ., 

PUBLIC HEALTH AND ENVIRONMENT 

AUGUST 15,1996 

PREPARED BY: 

COLORADO AIR POLLUTION CONTROL DIVISION 

TECHNICAL SERVICES PROGRAM 

VISIBILITY, RESEARCH, AND QUALITY ASSURANCE UNIT 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 31
52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 32
TABLE OF CONTENTS 

1 

I. EXECUTIVESUMMARY.. ................ '-, A. LTS ASSESSED IN SEVEN AREAS ...... 

1. Progress Achieved in Remedying Existing I 

a. Mount Zirkel Wilderness ........... 

\. 

\ 

(i). Hayden Consent Decree and a Ch 

(ii). Emission Limitations, Equipment 

(iii). Reasonable Progress and the H 

11. INTRODUCTION.. ..... 

111. NATIONAL REGULATO 

A. PHASE I REGULATIO 

B. INTEGRAL VISTA C 

C. EDFMPCA LAWSUI 

IV. STATE OF COLORADG's STATE IMPLEME~ATION PLAN FOR CLASS I VISIBILITY 

/ PROTECTION ... ./. .................... :..,<. ........................... 10 

A. EXISTING IMP~RMENT ............... ..: .......................... 10 

B. NEW S0UR~'~REVlEV;' .............................................. ...'::I6 

c. CONSULT~ION w171-r: FEDERAL LAI~I MANAGERS .................. 

D. MONIT@G STRATEGY. ............. ~. ............................. 

~ ., . ., 

E. LONG- ERM STRATEGY ............................................... 12 

'\ v. 7f OF COLORADO'S LONG-TERM STRATEGY ....... .':,: .............. 14 

A, TATE AND EPA REQUIREMENTS ..................... \,; ............ 14 

I. Progress in Remedying Existing Impairment of Visibility in Any Class ['Area ..... 14 

STEP-BY-STEP REVIEW .................................. ':\,. .......... 14 

a. Visibility Impacts in the Mt. Zirkel Wilderness ................. .''.?., ....... 15 

(i). Activities Prior to Certification ...................................... 15 

(ii). Activities After Certification ....................................... 17 

(iii). The Hayden Settlement. .................................. '?, 21 \ 

(iv). Reasonable Attribution, BART, and the Hayden Settlement ........... 

,,' 

/' 

/" 

/ 

/' 

,; 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 33
... c . 

\ (v) . Reasonable Attribution, BART. Reasonable Progress. and the4 

yden Settlement. Force Majeure. Thin 

proval by the Colorad bly ............ 

. that may be Necessary to Ensure 

.................. 33 

Other Schedules Set Forth 

........... 33 

VI . COLORADO'S CLASS I VISIBILITY PROTECTION PROGRAM STATE 

IMPLEMENTATION PLAN REVISIONS TO THE LONG-TERM STRATEGY. PART I: 

HAYDEN STATION REQUIREMENTS ...................................... 34 

A . PREAMBLE ........................................................ 34 

B NON-ENFORCEABLE PARTS OF THE SIP REVISION 34 

1 Existing Impairment and the Mount Zirkel Wilderness 34 

a Introduction 34 

b . Summary of the Decree ........................................... 35 

. ...................... 

. ...................... 

. .................................................... 

(i) . SO, Emission Limitations ..................................... 35 

(ii) . Particulate Emission Limitations .............................. 

(iii) . Compliance with Emission Limits ............................... 36 

(iv) . Hayden's Decision on Coal vs Natural Gas ........................ 36 

(vi) . Schedule --Natural Gas as ~~~~~~~~ Fuel ................ 

(vii) . Force Majeure .................................. 

c . Regulatory Tools ...................................... 

d . Reasonable Progress and the Hayden Requirements ..................... 38 

(i) . Cost of Compliance .......................................... 38 

(ii) . Time Necessary for Compliance 

(jij) . Energy and Non-Air Quality Environmental Impacts 

(iv) . Remaining Usehl Life of thc Source 

(v) . Visibility Benefits and Level of Emission Reduction 

(vi) . Reasonable Progress 

e . TheSixFactors ............................................... 46 

(i) . Ongoing &r Pollution Programs ................................. 46 

(ii) . Smoke Management Practices ................................. 46 

(iii) . Additional Emission Limitations and Schedules for Compliance ...... 46 

(iv) . Source Retirement and Replacement Schedules ................... 46 

(v). Schedule --Coal as Primary Fuel ................................ 36 

................................ 42 

................ 42 

............................ 44 

................. 44 

........................................ 45 

(v) . Measures to Mitigate the Impacts of Construction Activities ........... 46 

52.320(d), EPA-approved source-specific 

11 

requirements Part 1 of 1, Page 34
(vi). Enforceability of Emission Limitations . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 

C. ENFORCEABLE PARTS OF THE SIP REVISION: HAYDEN STATION 

REQUIREMENTS ...................................... :............47 

- 

-vI. CONSULTATION WITH FEDE 

NOTES AND REFEREN 

APPENDICES 

Map I Map of Colorado Class I 

'\ ', 

1977 CM 

BACM ailahlc Control Measure 

Available Retrofit Twhnolog~ 

mosphcric rstinction is a measure of the level of light scattcnng nndnhsc)rplion hv 

\ 

pariiculatrs arid gscs in the atmosphere '. 

\ Black Canyon of the Gunniwn National Monument 

U.S.D.I. Bureau of Land Management 

Class I Federal areas are congressionally designated large national parks and wildmess crcatcd 

as of Auw 7. 1977 \ 

'\ Colorado Air Quality Control Commission \\ 3 c.+. Colorado Revid Statutes 

'~ 

\ '\ 1 ---c 

... 

111 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 35
Colorado Air Pollution Control Division 

Environmental Defense Fund 

U.S. Environmental Protection Agency 

Federal Implementation Plan 

Federal Land Manager (USFS, NPS, BLM, USFBrWS) 

Fine Particle Mass or portion of the mass which is 

Great Sand Dunes National Monument 

comprehensive "global xttlement" betw owners of the Hayden Gcncrating Station, the 

t. Of Justice concerning Sierra Cluh's lawsuit 

'S Notice of Violation 

, and nitrogen oG&) 

w was sign4 by a]] 

Club, the State of Colorado, and the 

ct court on May 22.1996 

IMPROVE Interagency Monito 

national parks. \\ ilde 

MOU Memarand 

MOU Study 

Smoke MOU Mcmorpdum \ of Understanding 

Zirkcl Keascmahlc Almnbuli Study cf Visibility Impairment. Mcmormdm of 

'\, 

Zukel MOU 

North Eastern States for Coordinated Air Use 

National Parks ad Coiiscn.ation Assrriation 

Mt. Zirkel Wildcmess Area 

Nibopen OsiJcs 

National Park Scn'ice 

Particulatc matter under I0 microns in diamctcr 

Particulate matter uncic~ 2.5 microns in diamctcr 

Prevention of Siplificant Dc'ta-ioration 

Reasonahly A\.ailahlc Control Mcasure 

Rocky Mountain National Park 

Snowmass/Mwwn Bclls Wildcrncss 

State Implementation Plan for Class I Visibility Protection 

agcment 

\ +/ 

1 \ 

\ 

SIp and Visibility 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 36
/ 

i 

Standard Visual Range 

Tons per year. (tpy) 

U.S.D.A. Forest Service 

U.S. Fish & Wildlife Service 

.S. Geological Survey 

WESTAR 

the While River National Forest 

'\ \ 

'\ 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 37
3 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 38
VL COLORADO’S CLASS I VISIBILITY PROTEmON PROGRAM STATE IMPLEMENTATION 

REVISIONS TO THE LONG-TERM STRATEGY, PART I: HAYDEN STATION REQUIREMENTS. 

A. PREAMBLE. 

The State is conducting its Long-Term Strategy (LTS) review and revision in two phases: the first deals solely \vih 

visibility impacts in the Mt. Zirkel Wilderness area (MZWA) from emissions from the Hayden generating station, and 

the second deals with all other visibility issues in Class I areas in Colorado including other visibility impacts in the Mt. 

Zirkel Wilderness. This phased approach will allow for an expedited consideration and adoption of Visibility Protection 

Program State hplementation Plan (SIP) amendments that afkt the Hayden generating station only. Timely adoption 

of these SIP amendments and Environmental Protection Agency (EPA) approval will enable the owners of Hayden to 

begin activities that will lead to significant reductions at the generating station. Delays in the regulatory process may 

lead to cornspondkg delays in the schedule of activities for Hayden. In addition, reuntly enacted State law exempts 

specific visibility SIP amendments hat implement and enforce conlrol strategies agrcwd to in a consent dccrw from 

legislative review pursuant to Colorado Revid Statutes section 25-7-133. The SIP amendments contained herein that 

affect the Hayden generating station implcmcnt and enforce such a consent decree, and are. therefore. cscmpt from the 

provisions of section 25-7-133. At this time, no oher potential visibility SIP amendments are cs~mpt from this 

legislative review. Adopting the visihility SIP ammdment~ for the Hayden generating station sqarately from the 

remaining visibility SIP amendments will help avoid conbion during the legisiatiw review proccss For thcx reasons, 

the State believes it is prudent to phase the LTS rcvision prows. The sccond pan ofthc revision will he completed hy 

the end of 1996. This LTS SIP rcvistgn is Part 1 Haydm Station RcquiremcnLs and rcplaccs the previous c\istinp 

impairment portion of the LTS as it relates to the MWA. Below is the SIP revision that contains 

*An inlroduction (scxtion VI B. I A). 

*Summary ofthe port~ons OC the Ffaydcn C~nmt Decree that will hc included in the SIP luncndlncnt (krction 

VI.B. I .b); 

*Discussion ofreplaton. tcwls (scxtton VI B. I c); 

*Discussion ofreaxmahk progress and hc Haydm requirements (scxtion VI B. 1 A), 

,of,@e 6 factors that EPA requires be in a L 

uirements including emission limitations 

Scctions a tkr bclow arc provided for information, co 

enforccahle pans of the SIP S~~tioii VI C is intend4 to hc: Lhc enforceable part of the SII’ revision 

B. NON-ENFORCEABLE PARTS OF TI1E SIP REVISION. 

1. Existing Impairment and the hlount Zirkcl ~ilderncsi. The following suhseiions provide infimiiation, contest, 

beck& and explanation of Lhc Slate’s positions regarding existing visibility impairment in the Mt. Zirkcl Wilderness 

in relation to the Hayden penmating station. 

a. Introduction. In July 1993. he U.S.D.A. Forest Scntice (USFS) axtilied visibility impairment in the MI. Zirkel 

Wilderness area (MZWA) and named the Craig and Haydrn coal-fired generating stations as possihlc contrihutors to 

the problem. The State of Colorado has hwn engagd in a cooperative study (Mt. Zirkcl Visibility Study) to provide 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 39
3 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 40
(J additional information for the State to utilize in determining whether impairment can he reasonably attributed to one or 

both generating stations. The study was completed on July 15, 1996. 

In December 1995, the State, Sierra Club, and the owners of the Hayden generating station entered into negotiations 10 

attempt to resolve Hayden's potential contribution to visibility impairment in the M-ZWA, Hayden's contributions to acid 

deposition in MWA, and a citizen suit brought by the Sierra Club against Hayden for violations of opacity s&&m&. 

EPA joined these negotiations in Jm"ary 19% after issuing a Notice of Violation against Hayden alleging violatiom 

of the Clean Air Act. Atter many hours of negotiations in over 50 separate sessions. Sierra Club. State of Colorado, 

United States, Public Service Company of Colorado, Salt River Project Agricultural Improvement and Power District, 

and PacifiCorp reached settlement. and on May 22, 19%. lodged a consent decree with thc U.S. District Court for the 

District of Colorado. This settlement is ground breaking in many respects and addresses additional pollutants on a fa= 

schedule than the August 1991 visibility settlement ftacheed for the Navajo Generating Station. Notice of the Consent 

Decree has been published in the Federal Register and the public has had an opportunity wholly independent of this SIP 

revision to comment on the ternis of the settlement. 

Among other things. the Consent Decree requires the owners of Hayden station to significantly reduce missions of 

particulates and SO,. The State helievs it is appropriate and necessary to adopt certain parts of the Consent Decree 

nquirements as elemen& of the Long-Term Strategy component of the Visibility SIP and chat the imposition of 

requirements represents rcasanahle progress toward remedying Hayden station's likely contrihuiion to visibility 

impairment in MZWA. 

3 b. Summary of the Deem The major provisions of the Hayden Consat Dcrrw that arc hcing incorporated into 

Long-Term Strategy are sunun~zd klow for information purposes. The actual language from the Decree that is king 

incorporated ES an enlorceable cicnisnt of the SIP is contained in section I.F of this SIP amendment. 

(1). 

Havden station. These reductions w~ll reduce visibility pr 

, Vallcy. Acid dcposition in the area \\ill also be r 

(LSD) system to mect the cmission limitations or 

regardless of the fuel usld at I iaydcn. 

SO, Emission Limitations. The SO, cmission limitations will result in at ]cast an 82% reduction in SO, from 

irkel Wilderness as well as in the Ymp3 

on ownrrs must install a Lime Spray Dryer 

Ilowing cmission limitations shall apply 

*no more than .I60 lbs SO? iwr million Btu heat input on a 30 boiler operating day rolling average hsis (85% 

reduction from thc histonc highcr values of sulfur in the coal); 

*no more than .I30 Ibs SO? per million Btu heat input on a 90 boiler operating day rolling avcrags basis (85% 

reduction from the historic average values of sulfur in the coal); 

*at least an 82% reduction of SO, on a 30 boiler operating day rolling average hasis (to make sure that substantial 

reductions occur and that control equipment is run optimally even if bwer sulfur coal is used at Hayden Station); 

and 

LTS Rnirw & Rnurcn. Auwf IS. 1996 35 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 41
J 

*a unit cannot operate for more than 72 consecutive hours without any so, emission reductions; that is, it must shut 

down if the control equipment is not working at all for 3 days (this is 10 prevent the build-up of SO, emissions that 

may lead to visibility events). 

(ii). Particulate Emission Limitations. The Hayden ~wners must install and operate a Fabric Filter Dust Collector 

mown as an FFDC or baghouse) on each unit unless the owners switch to natural gas. Baghouses are extremely 

effective devices for removing particles from flue pas and should virtually eliminate particulate plumes from the plant. 

The existing particulate controls. Electro-Static Precipitators (ESPs). are older systems &at do not oper-- 3 c?thally 

during start-up and shutdown of the plant. Performance also tends to degade during periods between mi-smual 

major maintenance. The result has been frequent excursions over the 20% opacity limit and psrticulate plumes in the 

Yampa Valley from the power plant. Opacity is a measure of the density of smoke. 

The new equipment is intended to eliminate these problems which were largely rewnsihle for the USFS certification 

of visibility impairment and the Stalc's continuing regulatory process regarding visihility impairment in the Mi. Zirkel 

Wilderness. Particulate emission limitations for each unit are: 

00.03 Ibs of primary particulate matter per million Btu heat input; and 

monitors. 

-20.0 YO opacity, as averaged over each separate 6-minute pen& within an hour as measured hy continuous opacity 3 

(M). Compliance with Emission limits. All controls required hv the Decree shall he designed to meet cnforu.ahle 

-on limits. Compliance with the SO,. NOS. and opacity emission limits shall hc. dctcrmined hy continuous cmisqion 

monitors. 

Hmyden'r Derision on Ctzab a's Natural Gas. No later than I80 days 

notifjr the other pa.rre:1; (Sicma Club, Sratc of Colorado, EPA) regard% 

wing coal 8s the primary &el B{ B4a;;dm station or switch to natural gas 

November 17. 1996. 

(v). Schcduk -Coal w Primary FueL Should he owers of Haydcn elect to continus 10 hurn coal, the schedule for 

constructing contxol equipment and meeting the emission limitation deadlincs is VL? rapid for a power plant retrofit. 

me Consent Dare contains forw majcure provisions. If a force majeure event is dcIctmind to wcul under t~.m\s of 

the Decree, this could afTect the schcdule and compliance dates. 

Schedulejor Unit I: 

-Commencement of physical, on-site conshction of control equipment by 6/30/97 

-Commence start-up testing of FFDC and SO! control equipment by 12i3 1/98. 

Schedule for Unit 2: 

LTS Rmnr & Rrvuim Anpr 13~ 1996 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 42
-Commencement of physical, on-site construction of control equipment by 6/30/98. 

-Commence start-up testing of FFDC and SO, control equipment by 1213 1/99. 

Emission Limilalion Conipliairce Dares /or SO,: 

-For Unit 1. within 180 days Aer flue gas is pd through the SO, control equipment, or by July 1, I 999, 

whichever date is earlier. 

-For Unit 2, wilhin I80 days after fluc gas is pd through the SO, control equipment, or by July 1, 2000, 

whichever date is earlier. 

Emission Limitation Complionce Dales for Paniculates: 

-For Unit 1. within 90 days der flue gas is passed through the FFDC control equipment, or by April 1, 1999, 

whichever date is earlier. 

-For Unit 2, within 90 days after flue gas is pd through the FFDC control equipment. or by April 1,2000, 

whichever date is earlier. 

(vi). Schcduk -Natural Cru as Primary FueL Should the owners of Hayden elect to switch to natural ga, the 

following schedule and emission limitation compliance dates apply: 

Skhedule for Unit I & Unit 2: 

-Initiate permitting activities for construction of natural gas pipeline by 10/30196 

-Complete construction of pipcline and Haydcn boiler modifications and commence use of natural gas as 3 primary he1 source by 12/3 I I38 

Emission Limirotion Coniplmttce Date for so, apad 8micdSrPe: 

-February I. 1999 or 30 days an- the owners of Hayden commence w of natural pas as the primary fuel 

s force majcure provisions. A "force majcure cvcnt' is narrowlv 

delay in meeting construction deadlines or emission 11 

SIP. the force majeure provisions of the Con-wnt DLxrW 

ssion limitation compliance deadlines. A determination that 

source. 

(vii). Fom Majcurc. The C 

dcfmed. and can only be the 

compliance deadlines in limited 

to may impact the construction sc 

revisions that incorporate lhe relevant provisions of the Consmt Dccrer demonstrate reasonable prop- to\~~cj the 

national visibility goal is not coinpromiscd. however. by the inclusion of the force majcurc provisions into the SIP. 

Division believes that the parties to die Con.wnt kree do not anticipate nor intend lhal a force majcurc event will hc: 

used to sipiljcantly delay the construction and compliance deadlincs in the Conscnt Dccree nnd In his SIP. 

Consent Decree provides that if a force majeure event may delay compliance by the owners of Haydcn wilh the tms 

of the C0-t Decree for more than sis monk. then the Division, EPA or the Sierra Cluh may seek fkha relief from 

the Coun to fulfill the purposes of the Consrnt Decree. To help ensure hat reasonable progress continues to hc made, 

the Division and the Commission commit to rropcn the SIP as won as possible ~RCS it is determined that a construction 

schedule or an emission limitation schedule has been or Will be, delayed by I2 months as a result of o for= majeurt: 

determination. The SIP will bc recvduatcd at that the to determine whether revisions are necessaq to continue to 

demonstrate reasonable progress, including revisions that adopt new construction or compliance deadlines. In addition, 4 

LTS Rmor & RMI~ AYRYJI IS. 1996 37 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 43
the SIP also contains a clarification that the force majeure provisions referred to in the SIP are not to be construed to a 

authorize or create any preemption or waiver of the requirements of State or federal. air quality laws, or of the 

requirements contained in the SIP or the Consent Decree. 

c Regulatory Tools. Federal and state law provide the au qualify regulator with specific tools for addressing an 

existing stationary facility's emissions in the contest of a specific mification of visihility impairment ofa Class I area. 

The Division may reasonably attribute (RA) visibility impairment to the Hayden andor Craig power stations if there is 

evidence that either one contributes to any visibility impairment in the MI. Zirkel Wilderness. If impairment is attributed 

to an xis sting stationary facility the Division must analyze for BART and determine what, if any, are appropriate 

emission reductions. The facility(s) must then reduce heir emissions accordingly. The State has worked coilabratively 

with stakeholders in the Mt. Zirkcl Visibility Study to assemble additional information that could be used for replatory 

decision-making and laid out a time-table for the decisions. Howeva. the Hayden settlement has changed the State's 

approach (RA/BART approach) toward resolving the USFS certification 8s it affects Haydcn station. 

The owners of Hayden station have voluntarily aped, through a enforceable Consmt Dccrcy, to reduce emissions 

to such a degree that, in the Division's tcxhnical judgment. any possihle contrihutions to visihility impaimmt in WWA 

by Hayden will be reduced to hclow humanly perceptible levels. The State believes this level of improvement reprmb 

the ovaarching requirement of rcasonahle progress toward the national visihility goal as it relatcs to Hayden and 

mWA Continuation of the regulatory proccss to make a reasonable attrihution dccision and to conduct BART analyses 

has therefore become moot and would result in an inefficient w of slate. federal. and private rcxourcxs. In &is 

circumstance, the necd to usc the WNIT approach no longer exists. Howvcvcr. it is appropriate and na-ssq 10 

adopt the relevant rcquiremcnts of thc Consnt Dcrcrcc into the LTS portion of the Visibility SIP. 

3 -- 

d. Reasonable Progress and the Haylrn Requ 169(A) of the fcvioral Clem Air Act estahlishB a 

national visibility goal, not an air quality standard or specific emission standud. While the objectivec. OVW time, is to 

achieve the goal. the mandate is to niakc rcasonahle pro np rcasonahle props. the State 

onsider I) the costs of compliance; 2) the time nccrssar2; CC. 3) the enmg and non-air quality 

nvironmental impacts of compliance: and 4) the rrmainr c SOWCC. The State also &licvCs that 

inherent in the concept of rensonahlc propcss is a dm 

benefits. Each of the reasonable propcs.. considmations and visihili? benefits from the f laydcn rcquirLmcmts. as 

embodied in this SIP revision. arc briefly discussed helow 

(0. Cost of Compliancc By signing the Consent Decree. the Haydm O~TI~~S haw demonstrated thcir willinpcss to 

bear the cost to retrofit thc power station or convcxt it to natural gas. The Division concludes that the cost of the 

cquipmcnt or convmion will increase the cost of production of kilowatts at Hayden generating station and apvus to 

be within the range of costs compared to retrofits at other facilities. Howev~r, the Division had dificulty finding studies 

that contained information that \vas completely comparable to the Haydcn situation. It is also impnant to rmopizc 

that neither the Consent Decree, nor the State through this SIP revision, dictates that the source continue to coal 

or switch to natural pas. The Haydcn o\nms retain the discretion to make this choice and prcsumnbly will evaluate cost 

as one factor in making their choice. Instead of dictating fuel choice. the Conmt Dmrw and this SIP revision establish 

emission limits which are expect& to rcmlve Ifayden's likely contribution to visihility impairment in the WWA. For w 

38 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 44
the coal option, lime spray dryer technology was selected to address SO, emissions because it cdd achieve the emission 

limits, is compatible with baghouses. and has reasonable costs. Thus, the State believes that the selection of this specific 

technology is appropriate to ensure emission limitations will be met if' coal continues to be burned at Hayden station. 

The Division presents the following additional points and information regarding cost: 

Hoyden is willing 10 pq. 

Through voluntarily signing the Consent Decree, the owners of the Hayden station have demonstrated that they 

are willing to bear the cost to retrofit the power plant or convert it to natural gas. The relrofit or conversion is 

not contingent on Public Utility Commission approval of Hayden being able to pass the MS~ into its rate base, 

therefore, whether or not the owners of Hayden are able to get approvals from the Public Utility Commission 

to pass the costs along to the owners' customas, the retrofit or conversion will proceed. 

The operators of Haydcn station (Puhlic Service Company of Colorado) have indicated in a letter to the 

Division dated June 14. 1996' that the estimated capital cost in 19% dollars of installing baghouses to control 

particulate and lime spray eers to control SO2 would be approximately s 12 1 million. (This does not include 

the NOS equipment hecause NOx emissions are not believed to influence visihility in the UWA. N0.u 

controls are designrd to reduce acid deposition m the area). Total levelized annual cost of a retrofit. in 1996 

dollars, would be approsimately 522.8 million (includes the cost of capital. operating, maintenance, PW, 

personnel, encrgy use. water, and waste disposal). Capital cost for the LSDs (both units) is estimated at 54 I .4 

million. Thc capital cost of the FFDCs (both units) is estimated to he 579.5 million. Division stdT have 

revicwed thcsc cost cstimatrs and have not found any reason to question their validity. 

The cost of switching thr plant to natural pas is not houn at prmt and is the subject of study by the o\vmxs 

of Hayden who must drtmnine, within I80 days of signing the Consent Decree. whether to continue with coal 

or switch to natural gas. The Division does not currently have information about the cost of a natural gas 

conversion and opcration of the plant on this fuel. However. in terms of evaluating the agreement's cost, the 

Division feels comfortahlr using availahle information for a coal retrofit. The rationale is that if nalurnl gas 

krly that the Haydm o\\ncrs will nvitch fuels. in which casc the use of rctrofit data 

tr. If natural gas is less es 

st of the rtquircments. Hayd 

*Cost of o rein# eslimoled by Puhlic Service Company ofColorado. 

eCosr of0 coriversiori 10 riolrirol pas urrknowri 01 rliis time - relrojjt COSIS willsente os upper bourtdoty of cost. 

*Divisiotr esliniale of COSI 10 tlre average cirstonier of PXo IS less hrt Ilia1 resrr~firrgfi~trr a rcccttf visihiliry 

prorection sertlemertt. 

If Public mice Company were allowed by the Public Utilities Commission lo pass the cost of this investment 

into ~ts rate b=. Ihr DiLision cstimatts that an mvahnent by Puhllc SC~VICS Cornpiinn)' of Colorado in pollution 

control equipment of S I20 million would result in a rate increase of approsimalrly I .42% or an increase to the 

average household rlcxtnc hill of SO 5Wmonth'. As a companson. the EPA rstimatrd that thc cost of SO, 

' Letter from Steve Dayncy. Public Scrvk Company of Colorado, lo Dan Ely. Colorado Dcpallmenl of Public Hcalth and 

Environment, Air Pollution Control Division, June 14, 19%. 

'Mcmorandum from Sbcic Nutt. Colorado Air Pollution Control Division. Lo Dan Ely. Air Pollution Control Division, 

June 6. 1996. 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 45
J 

control for visibility protection purposes at the Nasajo Generating Station (so2 ody ) would increase by 

$1.72/month the electric bill of the average Salt hver Power customer in 1992 dollars’. Thus, the potential 

rate-based cost to customers of PSCo for the Hayden station retrofit, which includes both SO, and pmiculale 

controls, is expected to be far less per customer than that of the Navajo Generating Station retrofit. 

Cost of a rerrofit in Sk, $/ton, and $44Wh (niegmott-hour) as esriniafed by Public Service Coniparty of Colo,-odo. 

Public Service Company CpSCo) has indicated (in a letter previously cited) that the retrofit cost in $/year, $/ton, 

and S/MWh are as follows: 

Sryr Stton SMWh 

unit 1 FFDC S5,130.022 SlO2 S3.96 

Unit 2 FFDC 56,720,779 $99 S3.76 

unit 1 so1 S 10.1 37.2 I6 S2083 S7.82 

unit 2 so, S 12.723.188 S 1930 37.12 

PSCo notes that the SO, removal costs include hoth the FFDC and the LSD as both are required to obtain SO I 

control. The Division believes it is valid to look at the baghouse and lime spray dyer together for the purpo~ 

of an integrated pollution control system that reduces particulate and SO,. However, fully adding in the cost 

of the FFDC to the cost of the lime spray dryer to estimate SO2 rcmoval costs appars Lo the Division to douhlecount the cost of the FFDC. The FFDC is necessq to met particulate and opacity limits ad the Division 

does not believe its full cost should he included in the cost of SO2 control at Hayden hut ackno\vledgcs 

thac are varying approaches to analyze costs. 

The Division believes a levclued annual cost of SI 1.255 millioniyrar for So, removal for flayden is 

reasonable, recognizing that there is no one method for factonnp in the role of the particulate removal s).st~m 

as it relates to costs of SO, ranoval. Thl! Division’s estimate includes the levclimcd annual cost of the LSDs 

(f 10.07 million’) plus 10% ofthe cost of the FFDC (S I. 185 million). The Division helievcs this 10% reprewnts 

a reasonable apportionment to SO, reductions from the FFDC. Under this assumption, the cost ~LT ton of so2 

removed is approximat 

tpy) = S799ttoniyear). 

will be able to recoup h 

trading program under t 

A 1991 EPA modcling study’ cslimatcd the retrofit costs for SO: control at 200 coal-fired rlwtnc utilittcs (630 

hoilas) and specifically evaluated the cost of lime spray drying The 50th pcrcmtilc capital cost was estimatrd 

(in 1988 dollars) to hr: $150kW Adjusted for a plant of Hayden’s six. this translates into $67. j million 

capital cost (S 150 s 440.000 kW) in I988 dollars PSCO has cstirnatcd thc capital cost 01’ SO, equipment fc,r 

-Division i estimate of cost per tori rerrroval of .W, at Havderi. 3 

n 19% dollars (S I I .255 million/( 1G.OOO rpy s 88% removal = 

IS the portion of the control costs that the owners of 

\vmccss of SO: which it will rceeive as part of thc a1 

-€PA study of m, retrv)~ costs (hotk capital arid Ston) arid conipansoru to Hqdert 

3’Approval and Promulgation of Implcmcrilation Plans: Rcvision of thc Visibility FIP for Arizona.” October 3. 1991. 56 

Fdcral Re 50178. 

‘E-mail from SIC= Dqncy, Public Scrvice Company of Colorado. to Dan Ely. Colorado Dcpartmcnt 01’ Public Htaltll 

and Environment. Air Pollution Conlrot Division. “Hayden SO2 Corn LSD only.” June 24. 1996. 

5’Project Summary: Retrofit Costs for SO, and NOs Control Options at 200 Coal-Fired Plants,“ EI’h’600/~7-904’, 1. 

March 1991. 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 46
Hayden will be $4 1.4 million in 1996 dollars. The EPA study also estimated the $/ton removed of SO,. The 

50th percentile cost (in 1988 dollars) was approximately b700hon. The estimate included the cost of capital, 

operating, maintenance, personnel, land, waste disposal. and energy. The Division's estimate for Hayden is 

$799h UI 19% dollars. Assuming a 3% inflation rate applicd to the EPA number to make it more comparable 

to 1996 costs. yields a value of $887/ton - more than the estimate for Hayden. However, the Division believes 

the EPA estimate to be high because EPA evidently included all or part ofthe Cost of FFDC units on particular 

boilers for estimating the cost of SO, control with lime spray dryers if reuse of ESPs was not consid& 

feasible (168 out of 630 boilers). Therefore. 50th percentile costs from the EPA study presented above includt: 

some particulate deviw control cost as well. 

EPA's draft BART analysis for the Navajo Generating Station', in Table 4 of the analysis. provides estimates 

of the $/ton removal of SO, from various control options (e.g.. wet scrubbing. lime spray dryer, dry sorbat 

injection). The S/ton range irom S 1626 to 536 1 1 hodyear depending on the assumptions, level of removal, ad 

type of control system. This is much higher than the Division's estimates of b799/tpy for Hayden, al&ough 

similar to PSCo's estimates of SO, removal (approximately s2~/tpy) that include the full cost of the FmC. 

EPA's analysis does include FFDCs in costing he LSD option for Navajo Grmerating Station hwaw the 

station would need to build haghouses to utilize a LSD. EPA's cost estimate is hetiwen $24OUtpy ad 

S361 l/tpy for a LSDEFDC combination. 

*EPA 5 dmJ BART onolysis of rhe cost of Nmjo Gmcroting Sotion's So, control. 

*PXo's estimore o$cosI per ton renrovol ofponiculore 01 Hoyden srotion. 

In evaluating the cost clement. it is important to reco- that baghouses. in addition to addressing Haydm 

station's contrihution of pmiculates to visibility impairment in the EWA. also \\*ill rectify Hayden's difliculv 

mplying with State and Fedcral opacity limits. Jn the Sierra Club's lawsuit against Hayden station for opacity 

violations. the Sierra Cluh was swking an injunction to require the Hasden owms to install haeh0u-X. One 

could argue that if baghouses were already nrxesary to crddrcss QprtCiQ' isSUsS; the c~st of the srrtt1cml-m~ for 

visibility purposes should only consider the cost of the LSDS. Ho~cv~~. the Division believes it is appropriate 

to consider the cost of hnghouses in the conteht of making reasonable P~O~LSS hccaw of the nem certainty 

3 

liminating particulate plumes from Hayden station that m 

each unit, is expected by PSCo to remove pe 

cr citd culicr) per ton of particulate removed at 

oies oTFFDC COSI ttsrrig EPA spreadrliecu. 

EPA has developed a sct of sprsadshects (COST-AIR) for estimating the cost of ~anous air pollution control 

options. The Division attained the spreadsheet for fahric filters and estimated the cost of FFDCs at Hayj'm. 

The Division's cstimatc of capital costs of 529.6 million for Unit 1 and 542.9 million for Unit 2 are \vithin about 

10% of' PSCo's estimata ahow' The spreadsheet also outputs the cost p~ ton rrmovd Thc Division's 

estimates for Haydcn Unit I are %32/tpy (cornparcd to PSCO'S estimate of SIOZ/tpy) and %8l/tpy [or Unit 2 

(PSCo's estimate is S99Itpy). 

*'Ekit Available Rctrofit (BART) Analysis for the Navajo Gcncrahg Station in Page. Anmna." EPA Contract No. 68-07- 

4400. William R. Barnard. E.H. Pahan and Associates. Inc., prepsnd for the U.S. EPA, Januar). 3 1. 1990. 

Memorandum from Gary Kcnniston. Colorado Air Pollution Control Division. 10 Dan Ely. Air Pollution Control 3 Division, Cost estimates for FFDC and spray dpcr insbllation at Haydcn SEGS, July 12. 1996. 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 47
The Division's and PSCo's estimated cost of SO, and particulate emission reductions appear to be lower or similar to 

estimates for other projects or for this project using alternative methods. The State concludes, therefore, that the cost 

of SO, and particulate emission reductions is reasonable. 

Q. Time Nmrsary for Compliance. If the owners of Hayden elect to continue using coal as their primary &el, startup testing of the FFDC and SO, control equipment would occur by 12I3 1/98 for Unit I and by 1 u3 1/99 for Unit 2. If 

the owners elect to bum natural gas as their primary fiiel, they will begin doing so by I213 1/98. Under the terms of the 

consent Decret, approximately 2% to 3% years would elapse between the filing of the Darts and conversion to aatwal 

gas or operation of the control equipment, respectively. In comparison, assuming the Division went through a complete 

RA/BmT proccrs with the Hayden facility, which would take at least an additional 6 months, and fiyther assuming 

there are no challenges to the decision, BART regulations (AQCC Regulation #3. PM 9. XI.D.2) require that a facility 

that has received a BART permit from the Division "shall install and operate BART as cspAit 

2 &llli 

installation of control equipment could bc up to 5% years -- longer if there wcre administrative and/or corn appeals of 

agency decision-making. The State hclie\w that the Hayden settlement offers particulate and SO2 rductions on a mom 

rapid timetable than would likely hs achievable through a possibly controversial MART process. The terms of the 

Hayden settlement, as emhodid in this SIP revision, will also result in emission rductions much more rapidly than in 

tk Navajo Generating Station visihilit). settlement and Visibility Protection Propam Federal lmplcmcntation Plan (FIP). 

The FIP, which was promulgated on Octohc7 3.1991, allowed until November 1997. November 1398. and August I999 

for installation of SO, controls on the tluctl Navajo units. 

in no case later than 5 years after permit issuance." Under this scenario the Division estimates thai 

(iu). Energy and Non-Air Qualit? Environmental impacts. 

" .' 

If natural gas is choscn hy the owws of Hayden as the primary fuel, the OWILTS will have to initiate Vmitting, 

design, and construction activities for a natural gas pipeline. It is unkno\\n at this time what the xalc (1.c.. 

number of miles. ncxd for drveloprncnt of new gas fields) of thi 

iways cause disturhanccs. Thcse d 

Thc Division is aware of con& 

I wuth\vcstLm Wyoming and pan ste~i Colorado ("S 

and is uncertain as IO w1wthc.r and how ongoing dcItvL? of natural gas to I Inydcn souid bc allcxtcd hy this 

controversy. The Division also ha% no dcfinitive information that \\.auld indicate that there are impacts to the 

nation's or region's map supply associated with the lllie of natural gas at Haydrn station. Compared to coal, 

there are fewer non-air qualip impacts from the burning of natural gas as a fuel. For s~mplc. there 1s no ash 

or other solid waste for dtsposal 

*Coal. 

Assuming coal is continud as the pnmq hcl. the impacts include: 

*Enmay. PSCo estimates th31 the w' of baghouses and lime spray dyers. due lo energy nLd to ~ull thr.~ 

systems. will decreasc: thc plant output hy I. 1%. In the Division's judgment this is a rea.sonahlc rstimatc and 

similar to those found in EPA's BART analysis for the Navajo Gcvrrating Station (cited exlicr). 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 48
c) -Water. A lime spray dryer system requires water UI order 10 operate. EPA's BART Guidelines' indicate the 

requirements for a lime spray dryer to be approsimately .8 gallons per minute per megawatt. Assuming the 

Hayden facility was running at full capacity year-round, an additional 185 million gallondyear would be 

required. similarly, PSCo estimates that at 80% capacity, the water use would be 544 acre feet to run the lime 

spray dryer (177 million galloneear). Of that amount, 477 acre feet will come from reusing water in 

eveporatim ponds. The Division understands that the additional water (67 acre feet) will be from existing \vats 

rights currently owned by Hayden. This additional water use would represent a commitment of water rights 

from the Y ampa River. 

*Ash and Sludge. Ln a spraydying system, a fine spray of alkaline solution is injected into the flue gas stream 

as it passes lhrough a contact chamber, where the reaction with the so, OCCUTS. The heat from the flue gas 

evaporates the liquid from the absorbent solution. leaving a dry powder. which is then colltcted by the 

paniculate control device (haghouse). In addition to coal ash in the haghouse. the lime spray dryer will odd 

spent reagent plus unreacted ahsorhcnt. Typically thr~e have a low soluhility and arc not considered an 

environmental disposal prohiem'. Two additional studies indicate that the residuals from lime spray dryers 

considered to be safe and that the tosicity of the residues are well below the Estraction Procedure (Ep) toxicity 

limits" 'I. EP limits arc estahlished under the currcnt Resource Conservation and Recovcry Act regulations 

(40 CFR 261.24). Finally. Public Service Company (in a previously cited letter of June 14. 1996) states, 

Haydm is a zero discharge unit and thus dws not have a river water discharge. The LSD will 

dect the zero discharge and will not have off-site disposal of a new liquid waste. 

A ESD changes the solid \vastc stream that will he collcctd from he FFEC. The SOz in the 

flue gas reacts with the hydrated lime to form calcium/sulfi~r compounds. Thc calcium/sulfi 

compounds. unreactrd reagmt, and flyash will tx collected from the FFDC and disposed of 

in the current landfill locatd near the plant. It is not y major changes to the 

current solid wastc disposal practices will h! rrquir changes to the disposal 

method are plannid. the quantities of waste genera! 

operation approximately I I8,ooO tons pcr year of mild waste IS gcnerated from both units 

Ma the LSD installation is in opcration, it is estimatd that 160.500 tons of solid waste wlil 

be generated resulting in a 36% 1ncrea.w in solids requinnp disposal. 

8*Guidelincs for Dctcnniiring Best Availahlc Retrofit Technology for Coal-Fircd Powcr Plants and Other E+,tiilg 

Stationary Sourccs.~ United Stata Environmcntal Protation Apcy. ofice Of Air Quality Planning and Standards. Research 

Triangle Park, NC 2771 1, EPA450/3-80409b. Novcmhcr 1980. 

'Report to Congress: Wssta from the Combustion of Coal by Elccinc Utility Power Plants. EPAIS30-SW-88-02M. Fcb.. 

1988. 

lo "Evaluation of a 2.5-MW Spray Drycrffabric Filtcr SO2 Rcmoval S)'stm." EPRY65-7449. Project 1870-3. August 

1991. p. 9-61. 

" "PhysicalChcmical Charactcrislics olUtili5 Solid Wastes." Tctm Tmh Inc.. EPRI EA-3236, Scpkmbcr 1983. 

LTS Rmcw & Rmr~cn. Aug~l IS. 1996 43 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 49
Overall, it is the Division's judgment that either natural gas or coal and associated control systems will produce Some 

non-air quality environmental impacts yet either choice would result in an overall acceptable level of environmental 

quality. Also, the USFS believes that hecause the Hayden settlement will lead to reductions of hoth S02.and Nox: 

emissions, positive environmental impacts to the aquatic ecosystems in the MZWA will result". 

(b). Remaining Useful Life of the Sourcc An official with PSCo stated". "The remaining usefd life of Hayden IS 

contingent on its continued economic competitiveness in a deregulated mariie!phcz in addition to technical 40 

operational considerations. Given that the investments are made in pollution controls 01 :.~ia! g; L- zJion and fie 

plant remains competitive in the market place, Public Service Company anticipates a usehl life of Hayden station on 

the order of 20 years." It is the Division's technical judgment that given the overall competitive position of Public 

Service Company in the region', the typical current projected life Of electric generating stations", and past 

representations of the remaining life of Hayden station made by PSCo", an estimate of at least 20 years remaining useful 

life of the Hayden station is reasonahle regardless of the fuel chosen. Given the expected remaining uxful life of the 

station. a retrofit or conversion of this magnitude is reasonable. 

(v). Visibility Benefitr and Level of Emission Reduction. 

*Visibility Benefits. Any contributions to visibility impairment in the MI. Zirkel Wilderness cauwd by or 

contributed to by the Hayden po\vm station would come from 1) primary particulate plumes; andlor 2) a locally 

generated date haze. Based on Ihe Division's technical judgment. experience with information €merated 

regarding the operation of Haydcn station, and findings of the Mt. Zirkel Visibility Stud$* (e.~.. pages j- j7. j-61, 

5-62 and Table 5.5.1) there is close corrcspndrnce ktwm~ occasions when particulate plumL% are clearly visible 

6om the Hayden station and malfunctions with its existing Electro-Static Precipitators. The conversion ol'thr station 

to natural gas or use of bagl~ousc.s will virtually eli te particulate plumes coming from Haydcn that ma]; entm 

the MI. Zirkel Wilderness. With regard to locally generated sulfate hazes. the Division's technical judgment is that 

removing at least 82% of the 1995 inventory of 16.000 tonsiyear of SO, will etl'ctively address visibility prohlcms 

3 

and will lower the threshold of SO2 emissi 

Thcrc IS also evidence in the Mt. Zirkel Visihilit 

ent, as embodied in this SIP revision. nearly 

lZ Lertm from Elizabeth Estill. Rcgional Forester. Rocky Mountain Rcgion. U.S.DA. Forest Scrvicc. to Marpc t'crkins. 

Dimtor. Colorado Air Pollution Control Division. July 10. 1996 

l3 Pcrsonal mmmunicalion hcwccn Stcvc Dayncy. Public Scrvicc Company of Colorado. and Dan Ely. Colorado 

Dcpartmcnt ofPublic Hcalth and Enviroiiincnt. July 17. 19%. 

lC Pcnocul communication with Jim Gcicr. Colorado Air Pollulion Control Division. and Dan Ely. Colorado Air Pollution 

Control Division. July 18. 1996. 

l5 Scc PuMic SmioC Company of Colorado. 1991 Annual Rcpur:. regarding thc Havdcn pwcr plant thc Comwny 

indicstcs (hat Unit 1 has a maining lifc of 70 ycan and Unit2 has a maining life of 3 1 yean 

l6 Watson, John G.. Blumenthal, Donald L.. et. al.. Aft. Zihl Wilderness Area Rcasotrnhlc AII~I~II~IOII ,St~ch, 

0 f Visibility Imparrment, i'olirttre 11: Resrriis o/ Data Analysis atrd Afodelrtig. Final Report. prrparcd for T~blcal 

Steering Committee, do Colorado Dcpartmcnt of Public Health and Environment, Atr Pollution Control Division, 

Denver, CO, July I, 19%. 

L/ 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 50
in a change in visibility in the MZWA that would he perceptihle (e.g.. pages 6-74.6- 106.6- 147,6- 148.6- 167.6- 168, 

6- I7 I, 7-4, 7-9, 7-10, 7- 15, 7- 16, 7- 17). The Division recopkes that regional haze from outside Colorado and 

emissions from other sources within Colorado may also be contributing to v1slhilrv impairment at MZWA. . . .. 

*Level of Emission Reductions. The Division believes the level of particulate reduction at Hayden is appropriate 

and bases this conclusion in part on an esamination of levels of conLro1 requircd of the most recently permitted coalfired utilities in Colorado. For esamplc, unit #3 of the Craig station (Craig. CO) and the Rawhide station (Fort 

Collins, CO) undenvent PSD permit revicws and BACT determinations for particulate. The emission limit for each 

station is 0.03 Ibs per million Btu hcat input - the same as requud for the Hayden reuofiUconversion. The 

Division believes the SO2 emission limits for unit #3 of Craig and Rawhide also show that Haydcn's emission limits 

are what is generally required for new sources. Craig's requhmt is a 70% rduction. while Rawhide's is 8Wh. 

Hayden's emission limits were estahlished by reducing by 85% the sulfur content in its coal. 

(vi). Remooable Progress. The State hclicvcs that the terms of this SIP revision represent reasonahle propcss toward 

the national visibility goal with respect to Haydm station. The requirements will produe significant emission reductions 

that are expected to cfl'cct1vely eliminate the visibility impairment in the MZWA that could he associatrd with the 

station. The associated costs. non-air quality environmental impacts. and enera impacts appear to he reasonable 

given the remaining usehl life on the facility. The SIP will produce reductions of visihility impairing poiiutants at 

Hayden Station at a reasonable cost. years Wore similar reductions would likely mur bough reasonable attribution 

and BART determinations. The emission limitations for Haydnr for So, and particulate. reached through a negotiation 

process involving a numhc7 of parties. are similar to or mocc slringmt than those imposed on units suhjcxlt to PSD 

regulations (e.g.. Craig Unit 3 and Rawhide Energy Station). The State hclicves that the Hayden settlement, 

emmid in this SIP revision, hy remedying Hayden's conhhution to visihility Impairment in the MWA expeditiously, 

at a reasonable co~l. md without usidur non-air Lmvirommtal or energ impacts. hhn@ more "sranahlc p~jg~~i~" 

to thc Mt. Zirkel Wildcmess than could he achie\*ed hugh other means. The Division recognizes that regional h3Zt: 

from outside Colorado, rmissions from sources outside Colorado, and emissions from other Colorado sources could a1.w 

contributing to visibility impairnicnt in the MWA. 

The State believes the Hayden ss-csjl and rcsolws the ccrtilicatron of impairment hrau - by the USFS in relation to Hayden station The State is joined in his concluwm by the USFS -- the manager of the Mt. 

Zirkel Wilderness. The Division on June 24. I996 rtxeived a letter from the USFS Regional Forester. Eli7~hth Estiil. 

The USFS formally certified \4sihility impa1nnent at MZWA in 1993 and now concludes. 

The Consent Decree recently dcvelopd by the State. EPA. Sicma Cluh, and Puhlic Semice conipany 

(sic) will rcsult in significant cinisions rcductions at the Hayden Station. It is our opinion that the 

magnitude of the emission rductions for particulates and sulfur dioxide contained in the Consent 

Decree should cffcctively addrew the concerns of visihility impairment WL' had with this facility. The 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 51
emission reductions should eliminate Hayden's contribution to visibility impairment to helow a 

perceptible threshold". 

e. The Sis Factors. EPA regulations (C.F.R. 51.302(~)(2)) require the State to consider, at a minimum, sis factors 

when developing a LTS. Because part I of this LTS SIP revision process is fwused entirely on the Hayden requirements 

that resulted !?om the negotiated settlement. some of the six factors are not applicahle. Each factor is discussed 

individually below: 

(0. Ongoing Air Pollution Programr This factor is not applicable in the contest of requtrcwnts 1~- I :--'* :z station. 

It will be considered in part 11 of the LTS review/rcvision process. 

(ii). Smoke Management Practices. This factor is not applicable in the contest of requirements for Hayden station. 

It will be considered in part I1 of the LTS reviedrevision process. 

(ill). Additional Emission Limitations and Schedules for Compliance The Division was on-track to determine 

muonable attrihution and perhaps BART for the Hayden station. Because a settlenicnt. ernhodied in a Consent Decrw, 

was reached that established limits that arc expected to eliminate Hayden station's contrihution to visihiliv impairment 

in MZWA. the need to proceed with a MART approach is ohviatrd. In ordcr to insure that reasonahle progress is 

demonstrated in the SIP contest. the State has determined it is nemsary and appropriatc to include certain requirements 

hm the Consent Decree in this SIP. The specific emission limitations and specific controls (if Hayden continues to burn 

coal as its primary fuel) to achieve the limitations are contained in the language included from the Consent Drcrrc: 

(Consent Decrcc section V. Emission Controls and Limitations). The consmction schedule and schedule for compliance 

with emission limitations for I-laydem station are also in the esccrpted Conscnt Dcxrcv in sections VII. Construction 

d Compliance Deadlines. rrspczctivcly. The schedules are suhject to force 

majeure determinations pursuant to the Consrnt Decree. 

3 

Retirement and Rcplnrement Schedules. This factor he contest of requirements for 

ion as the sourcc is neither king retired nor replaced. 

(v). Measures to Mitigate the Imparts of Construction Activities. In the tllrhnical judgmcm of the Division. it is not 

believed that construction activities at Haydm station or in the consvuction of a natural pas pipeline will conmhute 10 

impainnent to the Mt. Zirkel Wilderness or othcr Class I arcas. Thc distance hctwcem the construction and the CIL,S 1 

area is at least 20 miles and it is ven unlikely that fugitive emissions from he site nould influence visihilic The size 

of particles that exapc a COnStruClion site are also usually relatively large (e.p.. fugitive dus!) and \vould raprdly dcposit 

out. The marginal increase in cmiissions from the= Hayden-specific activities would not he mrasurahlc against the 

background of current existing area emissions. Thus, no mitipation measures are ncxxssaq in this contest 

" Lcncr from EliLsbcth Estill. Regional Forcstcr. Rocky Mountain Region of thc U.S.D.A. Forest Scrvicc. to Margic 

Pcrkins, Dircctor, Air Pollution Control Division. Colorado Dcpaflmcni of Public Hcalth and Eiivirotiincni. Juiic 24. 19%. 

L15Rn7rw & RNUIOZ AupuI IS. 1996 46 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 52
(vi). Enforceability of Emission Limitations. By adopting the emission limitations for Hayden into Colorado’s SIP, 

such limitations become enforceable hy the State, and when approved by EPA, the limits are also federally enforceable 

by EPA. The Consent Decree’s emission limitations, during the term of its existence. are enforceable lhrough a petition 

by any ofthe parties to the Consent Decree to the United States District Court for the District of Colorado. A provision 

of the Consent Decree states that it cannot be terminated until certain requirements including emission limitations have 

been incorporated into the State’s Title V permit for Hayden station. Once in the Title V permit, the requirements would 

be enforceable by the State andor EPA. A provision of the Decree also stipulates monetary penalties to he paid hy the 

owners of Hayden should the station fail to meet emission limits. Enforceability of emission limitations is also related 

to how one determines compliance. the reliability and validity of measurements to detmine compliance, and reponing 

of data. For these reascms, Consent Decree sections VI. Continuous Emission Monitors (for SO, and opacity) and IX. 

Reporting are included fkom the Hayden Consent Decree in this SIP amendment. 

C. ENFORCEABLE PARTS OF THE SIP REVISION: HAYDEN STATION REQUIREMENTS. 

The following provisions, which are taken from the Hayden Consent Decree. are heing adopted as pan of this 

revision to the Long-Term Strategy portion of the Colorado Visibility SIP, shall be me1 hy the Hayden owners. and are 

intended to be enforceable. The Consent Decree numhering scheme has heen retained to avoid confusion hetwtxm the 

Consent Decree and the SIP. hut only thosc sections pertinent to visibility. newssary td ensure the enforceahility of the 

requirements related to visibilit).. and to demonstrate reasonahle progress are being adopted in this SIP revision. Also, 

Some changes have been made to the Consent Decrce language to conform the Consent Decree requirements to the SIP 

regulatory framework. Changes have heen made to language which ref- to the forcc majeure provisions ofthe Consent 

D&nx to ensure that a demonstration of rcasonahle progress can be made at this time. Changes are highlighted in bold, 

‘CI) 11. DEFINITIONS 

prcssly providd herein, t~m used in this SIP component [Defined below. “SIP 

mmponent” replacer Dccm wherever it appears] that are defined in the Clean Air Act, 42 U.S.C. § 740 I g a., or 

replations implementing the Clean Air Act. shall have the meaning set fodl in the Act or regulations. 

,* 

2. Whenever the terms set forth helow are u.4 in this SIP component. the following definitions shall apply: 

a. ‘Act” shall mean the CI 2 U.S.C. $7401, 

b. ‘Boiler operating day’ any calendar h coal is comhustd in the hoiler 

unit for more than 12 hours. If CO3 r more than 12 24 hours during a calendar day, 

calculation of that day’s SO, emissions for the un~t shall he had solely upon the average of hourly CEMS data collected 

during hours in which coal was comhuqtcd in the unit, and shall not include my time in which coal was not combust&. 

‘Boiler operating day” for natural gas shall mean any calendar day in which natural gas was comhusled in a hoilw of 

a unit for 24 hours. 

c. “Business day’ shall nitan all work day of the \re& csccpt Saturday, Sunday and all Colorado and federal 

holidays. 

d. ’Calendar day” shall mean any 24 hour pod between 12:OO midnight and the following midnight in 

Colorado. 

’CEMS’ shall mean continuous emissions monitoring system, which consists of all equipment used to 

sample, analp, and record on a continuous basis, opacity, SO,, NO,. or any other emissions-related parameters that 

e. 

may he required. id 

47 LTS Rmnr & Rmrm Au~I 15. I956 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 53
f. "Coal" shall mean all solid fuels classified as anthracite, bituminous, subhituminous, or lignite by the 

American Society of Testing and Materials, Designation 

D388-77. 

g. "Co-fire" shall mean when a unit at the Hayden Station is cornbusting coal and natural gas simultaneously, 

h. 'Colorado" shall mean the State of Colorado and the Colorado Depanment of Public Health and 

other than during periods of startup. 

Environment, Air Pollution Control Division; 

i. 'Day' shall mean a calendar day. In computing any period of time under this SIP component, except in 

computing compliance with emission limitations. where the last day would fall on a Saturday. Sunday or federal or 

Colorado holiday, the period shall tun until the close of the next business day. 

j. "SIPamponent" shall mean the language from the Hayden Consent Deerre (Civil Action 93-B-17.19, 

United Stater District Court for the District of Colorado), u modUid bewin, included in paragraph .if the 

August 8,1996 revision of the Long-Term Strategy portion of Colorado's Class I Visibility Protectio.. -,:am 

State Impkmentation Plan. 

k. 'Hayden Owners"[ replace uDefendants" throughout] shall mean Public Service Company of Colorado, 

Inc., Salt River Project Agricultural Irnprovcmenl and Power District. and PacifiCorp. and successor ownrrs of Hayden 

Station. 

1. "Division" shall mean the Colorado Air Pollution Control Division. 

m. 'EPA" shall mean the United States Environmental Protection Agency. 

n. 'Excess opacity rcading" shall mcm each six-minute period of time during which the opacity ot'txnissions 

from Unit I or Unit 2 at Hayden Station csccrds 20.004 as determined by the opacity CEMS. 

0. 'FFDC' shall mean Fahric Filtcr Dust Collector. 

p. 'Fossil-fuel' shall mean natural pas. petroleum. coal. and any form of solid. liquid. or gascc'ous fuel dcnvcd 

q. 'Heyden Station' shall mcm thc fossil-he1 fired steam generating plant located near the lawn of Hayden, 

Colorado, consisting of two boilers and rclatcd elcclric generators and all ancillary process and air pollution emission 

control equipment known Bs Unit I and Unit 2: 

s for the 'mse or crea ful heat. 

r. 'NO,' shall mean nitrogc 

s. 'Paragraph" shall mean a 

t. mot applicabk to this SIP component.] 

u. [Not applicabk to this SIP component] 

V. 'QNQC' shall mean the quality assurance and quality control measures to ensure the accuracy of CEMS 

ed by an arabic numeral. 

required by this SIP component. 

w. "Quarter" shall mean a calendar quarter consis!ing of three full months, beginning on the lirst day ofcitlier 

Januq. April. July or October. 

s. 'Rolling average basis' shall mean an average over a pod of time consisting of the bl 30 or 90 boiler 

operating days, with a new daily avtroge generated each successive boiler operating day, based on the sum of the daily 

averages for the last 30 or 90 boiler operating days. 

y. "Section" shall mean a ponion of this SIP component identified by a capital roman numeral. 

2. 'Shutdown" shall mean the cessation of operation of Unit 1 or Unit 2 at Hayden Station for any purpox or 

reason. 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 54
aa. [Not applicable to this SIP component.] 

bb. "Startup" shall mean the setting in operation of Unit 1 or Unit 2 at Hayden Station for any purpose or 

reason. 

cc. "SO," shall mean sulfur dioxide. 

dd. "Title V" shall mean Title V of the Clean Air Act. 42 U.S.C. $766 I ~OU@ $ 766 1 f. 

ee. "Unit 1 " shall mean the 180 megawatt steam generating unit and related electric generating and air pollution 

emission control equipment for which construction was completed at the Haydcn Station in 1965. including all changes 

made, and to be made, to such equipment thereafter. 

0. "Unit 2" shall mean the 260 megawatt steam generating unit and related elccbk generating and air pollution 

mission control equipment for which construction was completed at the Hayden Station in 1976. including all changes 

made, and to be made, to such equipment thereafter. 

gg. "Consent Decree" or "Hayden Consent Decree" shall mean the Consent Deem entered in Sierra 

Club v. Public Service Comrtanv of Colorado. Inc. et aL, CivU Action Ncr. 93-B-1749. 

V. EMISSION CONTROLS AND LIMITATIONS 

7. Haydcn Owners shall. at all times, maintain and optimally operale the boilers and all pollution control equipment 

icstalled at the Hayden Station consistent with good air pollution control practices for minimizing cmissions. Wi~out 

limitation, his shall include returning the control equipment to optimum efficiency as soon as practicable during hila 

startup or following control equipment outage or impairment. and maintaining the control equipment at optimum 

efficiency as long as possihle while shutting down the boiler. 

8. Haiden Owners shall install the following control equipment, and shall achieve the following emission limitations 

for each Unit at the Hayden Station. in accordance with the deadlines wt forth in Scctions VII and VIII: 

a. Sulfur Diosido CSO,) 

i. Unlcss Haydcn Ouners elect 10 switch to natural gas pursuanl lo paragraph 24. Hayden Owners shall 

instali and operate lime spray dqcr tcchnolog on Unit I and Unit 2 at the Hayden Station. Hayden Owners shall design 

and construct such lime spray dqcr ttxhnolog to meet the emission limilations. including the percentage reduction 

requirement, set forth helo\\*. 

3 

n limitations for each unit at the Hayden Station shall hc as 

Biu heat input on a 30 boiler opcrating day rolling av 

Btu heat input on a 90 hoiler operating day rolling av 

iii. Compliance wih the SO, mass emission limitations UI subparagraphs (a)(ii)(l) and (2) herein shall be 

detmincd using data from thrt SO: CEMS that Hayden Ouners are required to maintain. calihrate and operate pursuant 

to Section VI. 

iv. Sulfur dioside controls on cach unit at the Haydcn Station shall achieve at least an 82% reduction of 

mlfuF dlostde on a 30 hoilcr operating day roiling average basis. 

v. Compliance with the SO, percentage reduction requirement in suhparapaph (a)(iv) ahove shall he 

dethed using data from the SO, CEMS that Hayden Owners are required to maintain, calibrate and opuate pursuant 

10 Section W. Continuous emission monitor data taken from the inlet flue gas stream to the lime spray dryer shall he 

compared to continuous emission monitor data taken from the outlet flue gas stream at the stack to determine the 

percentage reduction in sulfur dioside concentrations (based on pounds per million Btu at the inlet continuous emission 

monitor versus pounds per million Btu at the outlet continuous emission monitor). If the Hayden Owners elect to switch *d 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 55
to or co-fire with natural gas, an adjustment shall be made in the calculation of this percentage reduction requirement 

to provide Hayden Owners credit for the decrease in the So, concentrations in the inlet stream resultutg from the 

introduction of the natural gas component of the fuel, provided that Hayden Owners first submit, and obtain State and 

EPA approval of, a detailed protocol setting forth the method by which such adjustments will be made. Upon approval 

by the State and EPA, such protocol shall become an enforceable part of this SIP component. 

vi. The first two hours after the first coal feeder on a unit has started during startup shall be excluded from 

the calculation of that day's SO, emissions for such Unit. 

vii. Regardless of Hayden Owners' compliance with (and without relieving Hayden Ownm of the 

obligation to comply with) the emission limitations and other requirements set forth in this Section. in no e\'er,: stail 

Hayden Owners operate any boiler for more than 72 consecutive hours at a unit without an SO, control system achieving 

some reduction of SO2 emissions at that Unit. Following shutdown pursuant to this subparagraph, Hayden Owners shall 

only restart the boiler on a unit when any malfunctioning control equipment has been repaired. 

viii. During any boiler operating day, as defuted in this SIP component. all emissions of SO2 from the stack 

of any unit shall be included in the determination of Hayden Owners' compliance with the SO, emission limitations set 

forth in this paragraph, unless excluded as the first two hours during startup. excluded pursuant to paragraph 29 during 

the first six months after the compliance date established in Section VIII. or as a result of a 'catastrophic failwe" as 

defined below. 

ix. Catastronhic Failure. 

(1) A "catastrophic failure," for purposes of this paragraph. shall mean a complete failure ofthe SO, 

emission control equipment at a Hayden Station unit that is directly caused by a force that Hayden Ownm could nei&m 

have controlled nor reasonably anticipated, and that could not have been prevented through the exercise of good air 

pollution control practices for minimizing emissions. 

(2) Without limitation, a catastrophic failure shall not include SO2 emissions that are related to wit 

stmup or shutdown; load fluctuations; operator failure; upsets; design, cornsthplction. or equipment defects &at Wiyden 

Owners could have controlled or reasonably anticipated; or the failure of any SO2 emission control equipment 

components due to ordinary wear and tear. irrespective of Hayden Owners' efforts to maintain andor replace 

components. 

(3) For purposes of det SO, emission limitations set 

catastrophic failure". 

(4) For any boiler operating day fw which data is escludcd due to a catastrophic failure, the 

calculation of that day's average SO, emissions for the unit shall be based solely upon how of nonexcluded CEMS data 

that would otherwise be counted under this SIP component. Days in which all such hours are excluded as a result of a 

catastrophic failure pursuant to this paragraph shall not he counted in calculating compliance with the SO, emission 

limitations. 

(5) If Hayden Owners wish to invoke the catastrophic failure exception, they first must notif) the 

Division by phone immediately. but no later than two hours after the start of the next business day following such failwe. 

Second, within 30 days of such failure, Hayden Owners must provide a written report to the Division that contains: (a) 

all hourly SO, CEMS data Hayden Owners wish to have excluded. (b) evidence of Hayden Owners' notification to the 

Division, and (c) all evidence that demonstrates the failure is a "catastrophic failure" as defined above. [bnguage 

deleted]. If Hayden Owners fail to follow the notice andor reporting requirements of this paragraph, the catastrophic 

failure exception shall not apply 

aragraph, no more than 24 hours hall be escluded fo 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 56
c. Particulates 

i. Unless Hayden Owners elect to switch to natural gas pursuant to paragraph 24, Hayden Owners shall 

install and operate Fabric Filter Dust Collectors (also known as FFDCs or baghouses) on Unit 1 and Unit 2 at the Hayden 

station. Hayden Owners shall design and construct such FFDCs to meet the emission limitations set forth below. 

ii. The particulate matter limitations for each unit at the Hayden Station shall be as follows: 

(1) 0.03 poundsof prim- particulate matter per million Btu heat input. as averaged over six (6) hows 

of EPAs reference method for particulate testing, and 

(2) opacity of 20.0 percent. as averaged over each separate 6-minute perid within an hour, beginning 

each hour on the hour. Notwithstanding the foregoing, during periods of building a new fire. cleaning of fire box=, 

startup, Soot blowing, any process modification or adjustment or occasional cleaning Of control equipment, Hayden 

Owners shall not caw or allow the emission of air pollutants in excess of 30 percent opacity for a period or periods 

aggregating more than 6 minutes in any 60 consecutive minutes. 

iii. Any opacity reading in excess of the limitations set forth in subparagraph (ii)(2) above may he escuxd 

if [deletion] Hayden Owners have demonstrated such reading was the result of an unpredictable failure of air pollution 

control or prows equipment that was not due to poor maintenance. improper or CareleSS operations. or othenvise could 

not have been prevented through *e escrcix of reasonable care. If Hayden Owners seek to excuse any such exopacity reading, they must noti@ the Division as swn as possible by telephone. but no later than two hours after the stm 

of the next business day. In addition. for purposes of lhis SIP component, any claim of eScuSe must he made in \b+ting 

in Hayden Owners' nex% quarterly report following such condition. and must describe: (a) the date and time telephone 

notification was given to the Division. and the person to whom notiftation WBS given, (b) the cause of thc condition, 

(c) all actions Haydtn Owners took to mrresi the condition. and (d) all actions Hayden Owners will take to prcvcnt the 

condition from recurring. 

iv. Compliance with the primary particulate cmission limitation in subparagraph (c)(ii)( I) herein shall 

U 

determined aceording to EPA Me&& 5.40 C.F.R. Part 60. Appdix A, or in acsordanw with a compliaitllcs asstwac~ 

monitoring pian as may be set fofih in Iiaydtm O\tners' Title V operating pennit. Hayden O~nrr~ shall conduct 

Method 5 test on each unit at the Hayden Slation within 100 days after flue gas is first passed lhrough thc FFDC. and 

Colorado or EPA. and submit all results and a complete descript ts to the Division 

rt following Hayden Owners' receipt of the results. 

cc with the opacity emission limitation in subparagraph (c 

g data from the opacity CEMS that Hayden Owners are r 

.dl he determined 

ntain, calibrate and 

operate pursuant to Section Vl of this SIP component, and may be verified on an intamittmt basis by EPA Method 9, 

40 C.F.R. Patt 60, Appendix A. 

vi. [Not applicable to this SIP component]. 

V1. CONTINUOUS EhllSSlON MONITORS 

9. At all times aRer the Colorado Air Qualit?. Control Cornmush's adoption of lhis SIP component, Hayden 

ouqers shall maintain. calibrate and operate CEMS for each unit of the Hayden Station to measure accurately so, 

emissions from each such unit, as wvll 11s flow and carbon dioxide, in full compliance with the requirements found at 

40 C.F.R. Part 75. Nothing herein shall preclude Hayden Owners fiom installing. certifying and operating integrated 

CEMS equipment to measure SO,, NO, or opacity. or any combination thereof. 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 57
10. At'all times after the Colorado Air Quality Control Commission's adoption of this SIP component, Hayden 3 

Owners shall maintain, calibrate and operate CEMS to measure accurately the opacity Of emissions from each unit at 

the Hayden Station in full compliance with the requirements found at 40 C F.R. Part 60. Appendix B, Specification 1, 

and 5 C.C.R. 1001-3,1V.A and B. 

1 1. [Not applicable to this SIP component] 

12. Prior to initial startup of the SO, control equipment at each unit required by this SIP component, Hayden 

Owners shall, in addition to other CEMS required hy this SIP component: (a) install and thereafter maintain, calibrate 

and operate an accurate CEMS at the inlet flue gas stream to the lime spray dryer on each unit to measure accuratel~~ 5g2 

concentrations in pounds per million Btu heat input. and (b) tie the coal feeders on each unit into the SO, CEMS :,ch 

that the CEMS nccurateiy reflect the date and time when the first coal fetder on each unit has started during each startup. 

13. mot applicabk to this SIP component]. 

14. wot applicabk to this SIP component]. 

15. vot applkabk to this SIP component). 

16. Beginning within 30 hoilm opcrating days from the date flue gas is first pd through the SO2 control 

equipment for each unit, Hayden Ostncrs shall calculate hourly average so, concentrations in pounds per million Btu 

at the inlet and outlet continuous emission nionitors for each unit, in accordance with the requirements of 40 C.F.R. part 

7s. 

a. For each boiler operating day, Haydm Owners shall w the inlet and outlet hourly avcragcs to calcuIate he 

following at each unit: hourly SO, average peratage removal, daily SO, average percentage r~moval had on the 

hourly averages, and 30 day rolling SO, avwage pcrccntage removal based on the daily svnages. 

b. For each boiler operating day, Hayden Owners shall use the outlet hourly avnages to calculate tho following 

at each unit: daily average SO, emissions hascd on he hourly averages. and 30 day and 90 day rolling averages hd 

on the daily averages. 

two hours after the first coal fc.edm has 

starred shall bc excluded from the calculation of that boiler operating day's SO, emissions for the unit. 

beginning within 30 days of the 

Owners shall calculate hourly 

monitor at each unit. in accord 

by paragraph 16(b). 

17. Hayden Owners shall rcporl to the Division on a quarterly hasis each 30 day rolling avrrage and each 30 day 

rolling average during the prior qumlcr that esccxdd or failed to comply with the SO: cmisqion limitations containd 

in this SIP component. Each quarterly rcpon shall include all times the coal kdms have started during startup 

reported through the CEMS. This rcpon shall also include a list of the days and hours cdudcd for any reason from 

determination of Hayden Owners' conipliance N ith the SO, limits. 

c. As provided in graph 8(3)(vi). during startup of the unit. 

d. Notwithstanding thc foregoing, if Hayden Owners elect to switch to natural gas as the pnmiuy fuel 

CTS commcnce use of natural gas as the primnry fuel murc 

rations in pounds per million Btu at the outlet continuo 

.L~LXIIS of 40 C.F.R. Part 75, and shall calculate the avcrag 

18. [Not applicabk to this SIP component] 

19. [Not applicabk to this SIP component) 

20. For any hour that valid, qualq-asswed mntinuous emission monitor data for a unit is unavailable, So, 

[dektioal emissions shall be calculated in accordance with the missing data suhstitution procedures contain4 in 40 

C.F.R. Part 75. 

LTS Rrvrnr C Rnurm August 13.1996 

3 

52 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 58
21. Hayden Owners shall calculate opacity based on CEMS data for each six-minute period of time any boiler is 

22. Hayden Owners shall report to the Division on a quarterly basis all excess opacity readings from each unit. ad 

shall state the cause of each excess opacity reading and Hayden Owners' efforts to minimize such readings. 

23. Hayden Owners shall ensure that the opacity CEMS on Unit 1 and Unit 2 art: properly recording data at least 

98.0% of each unit's operating time each quarter, provided, however, that if final federally-enforceahle regulations are 

promulgated that.impose new CEMS QNQC requirements that have the effect of increasing the proponion of CEMS 

QA/QC activity time in relation to unit operating time, then Hayden Onners may seek a revision to this SIP component 

to amend the 98.0% CEMS availability requirement accordingly. 

operating, in the manner, frequency and interval as prescribed in the applicable replations 

VII. CONSTRUCTION SCHEDULE 

24. No later than [deletion] November 17, 1996. Hayden Ownm shall notify the Division of Hayden Owners' 

decision concerning the primary fuel source for the Hayden Station. If Hayden Owners decide to continue using coal 

as the primary fuel source, thc xhcdule in paragraph 25(a) shall apply. If Hayden Owners decide to switch to natural 

gas as the primary fuel source. the schcxh.de in paragraph 25@) shall apply. 

25. The schedules are as follows. suhjcct to a force majeure determination. pursuant to the Hayden Consent 

km,hciuding a decision by the Court to limit form majeure pursuant to paragraph 59 of the Hayden Consent 

Decm However, if any schedule has been extended or will be extended pursuant to such a force majeum 

determination or determinations by more than 12 months beyond the particular deadline, the Division shaU 

request that the Commission reopen (with public notice and hearin& the lang-Term Strategy element of 

Cobmdo's Class I Visibility Protection Program State Implementation Plan to reevaluate the demonstration of 

mabk progms,md to revise the State lmplemcntrtion Plan as may be necessary to ensure that the emission 

limitations are met. In no event shall these fum majeure provisions be construed to authorize or create any 

P 

Dccm and incorporated into this SIP. 

. 

r wiivef 6f any State or federal air quality law, or of any requirement contained in the Consent $8 

a. Schedule - Coal as Primonv Fucl. If Hayden Owners continue to operate Hayden Station using coal. Hayden 

s shall meet the following dcadlincs for [d UP testing of the emission control 

t required by Section V of this SIP compon 

Dcadlinc 

(i - vii) Not nppiicrl~le to this SIP component 

(viii) 

FFDC and SO, [deletion] control equipment 

Complete construction and mmncnce startup testing of the I 213 I /38 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 59
Activity Deadline 

(I - vii) Not applicable to this SIP component 

(viii) Complete construction and commence startup testing of the 120 1/99 

FFDC and SO, [dektion] control equipment 

b. Schedule - Natural Gas as Primaw Fuel. If Hayden Ouners elect to convert Hayden Station to natwal gas, 

Hayden Owners shall meet the following deadlines for conversion of the Hayden Station to natural gas: 

Activity Deadline _. 

(i - lii) Not applicable to this SIP component _. -

(iv) Complete consmction of pipeline and 

boiler modifications. and commence use of 

natural gas as primary fuel source 

12/31/98 

26. Upon initiation of startup of the Haydm Station using natural pas as thc furl source. Hayden Ownm shall 

lhereaner monitor on a quarterly basis the quality of the natural gas being butncd Results of such monitoring shall he 

sent to tbe Divirioa on a quarterly basis. 

a. ne natural gas burned at the Hayden Station shall be of the following quality: no more than 5 Fains oftotal 

sulfur per 100 cubic feet at 14.73 p.s.i. and 60 degrees F. 

b. The natural gas quality shall be determined by the followbg method: ASTM 0-5504-94, Standard Tat 

paphy and f Sulfur Compounds in Natural Gas and Gascous Fu 

this SLP component]. 

VIII. EMISSION LIMITATION COMPLlANCE DEADLINES 

28. Hayden Owners' obligation to mwl the SO, Idektionj and particulate emission limitations xi fo~ in Setion 

V shall commence on the dates listed below, subject to a force majeure [deletion] determination punuant to the 

Hayden Consent Decm (including a decision by the Court to limit Tom majturc punuant to paragraph 59 of 

the Hayden Consent Deem). However, if any schcduk bas been extended or will be extended pursuant to such 

a force majeum determination or determinations by more than 12 months beyond the particular deadline, the 

Division shall =quest that the Commission reopen (with public notice and hearing) the Long-Tern Strategy 

element of Colorado's Class 1 Visibility Protection Program State Implementation Plan to mvaluate the 

dcmtmtratioa ofrrruonabk progress, and to revise the State Impkmentation Plan as may be nmssaq to ensum 

c, 

that the emusbn limitations are met. In no event shall these fom majeure provisions be construed to authoe 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 60
or create any preemption or waiver of any State or federal air quality law, or of any requirement contained in 

the Consent Decree and incorporated into this SIP. a 

a. So,: 

i. For Unit 1, within I80 days after flue gas is passed thr~~gh the SO: control equipinent. or hy July 1, 

ii. For Unit 2, within 180 days aftcr flue gas is passed through the SO2 control equipment, or by July 1, 

1999, whichever date is earlier; and 

2000, whichever date is earlier. 

b. [deletion] 

i. [deletion] 

ii. [deletion] 

i. For Unit 1, within 90 days aflcr flue gas is passed through the FFDC control equipment, or by April I, 

ii. For Unit 2, within 90 days aftcr flue gas is passed thr~~gh the FFDC control equipment, or hy April 1, 

29. Dung thc first sis months folloning the data list& in paragaphs 28(a)(i) and (ii) ahow. for purposes of 

[deletion] detmming compliance with the SO, emission limitations set fOt3h in &lion v, [deletion] pcnods during 

which the control equipment fails to meet an SO2 emission limitation may be excluded if Hayden Owners are able to 

demonstrate that such failure was due to a design or construction defect beyond Hayden Owners' control. During he 

first four months following the dates listed in paragraphs 28(c)(i) and (ii) above, lor p~rposes of [deletion1 determining 

compliance with the particulate 'mission limitations set fodt in Section V, [dektion] periods during which the controt 

equipment fails to mcct a particulate ciiiission limitation may be excluded if Haydcn Owners arc able to demonstrate 

that such failure was due to a design or construction dcfcct bond Hayden Owr~m' control. 

Owncm nisii to seek an exclPrsion undeqtk'u paragraph, Haydem Ownem ohdl submit a 

written report to the Division that [dcletionl identifir the times proposed for esclusion and providcr the rrmm for 

the failure to meet the limitation, including all evidence that demonstrates the failure W~S caused hy a design or 

ons takcn and to he laen 

c. Particulates: 

1999. whichever date is earlier; and 

2000. whichever date is carlirr. 

defect hcyond 1 faydm Ouners' contr 

ilure, and a schsdulc to complete su 

ot applicable to this SIP compone 

twithstanding the foregoing, if Ilayde talion lo natural gas. Hayden 

Owners' ohligation to mwt the SO: [deletion] and particulate emission limitations xt forth in Soxion V shall 

commence on thc earliar of Fehrue I, I999 or 30 days der the date Hayden Ouners conwicncc USC: of natural gas as 

kprimq fuel sourcc, suhjcct lo a force majeurc. [deletion] determination pursuant to the Hayden Consent Decree 

(including a decision by tlic Court to limit force rnajeurc pursuant to paragraph 59 of the Hayden Consent 

Decree). However, if any schedule has been extended or will be extended pursuant to such a force majeum 

determination or determinations by mart than 12 months beyond the particular deadline, the Division shall 

request that the Commission reopen (with public notice and hearing) the Long-Term Stratev element of 

Cobrado'# Class I Visibility Protection Program State Impkmtntation Plan to reevaluate the demonstration of 

mabk pq-ur, and to revise the State Implementation Plan PI may be necessary to ensure that the emission 

limitations are met. In no event shall these force majeun provisions be construed to authorize or create any 

a 

MI 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 61
preemption 

Decree and incorporated into 

or waiver of any State 

this STP. 

or federal air quality law, or of any requirement contained in the Consent a 

LX. REPORTING 

3 I. Within 30 days after the cnd of each quarter, [deletion]. Hayden Owners shall provide a quarterly report to the 

Division regarding the immediatcly precedq quarter that contains all of the information this SIP component requires 

Hayden Owntrs to report on 6 quarterly basis. 

32. wot applicabk to this SIP component]. 

33. In specific, each quarterly report shall include: 

a. A description of construction deadlines achieved. progress made toward meting future deadlines, and my 

b. All elements of the esccss opacity quarterly report; 

c. Afkr installation of the so: conlrol equipment. the required quarterly reports for so? emissions (including 

d. [deletion] 

e. If Hayden Owners clcct to convert Hayden Station to natural pas, all idbrmation required 10 be included 

actual, expected or reasonably likely delays; 

donation regarding excluded psnods) [deletion} and CEMS qualic assurance reports. 

in the natural gas quartaly reports; and, 

f pot appkabk to this SIP component]. 

34. [Not applicable to this SIP component]. 

35. [Not applicable to this SIP romponcntl. 

52.320(d), EPA-approved source-specific requirements Part 1 of 1, Page 62