DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION

BART Application Analysis

AP

- 604 2

May 2 8 , 2009

NAME OF FIRM: PacifiCorp

NAME OF FACILITY: Naughton Power Plant

FACILITY LOCATION: Section s 3 2 and 33 , T2 1 N, R11 6 W

UTM Zone: 12 Easting : 533,450 m, Northing: 4,622,7 00 m Lincoln County, Wyoming

TYPE OF OPERATION: Coal

- Fired Electric Generating Plant

RESPONSIBLE OFFICIAL: Angie Skinner

, Plant Managing Director

MAILING ADDRESS: P.O. Box 191

Kemmerer , WY 83101

TELEPHONE NUMBER: (307 ) 828

- 4211

REVIEWER S : Cole Anderson , Air Quality Engineer

James ( Josh ) Nall, Air Quality Modeler

PURPOSE OF APPLICATION:

Sections 169A and 169B of the 1990 Clean Air Act Amendments require states to improve visibility at Class I areas. On July 1, 19 99, EPA first published the Regional Haze Rule, which provided specific details regarding the overall program requirements to improve visibility. The goal of the regional haze program is to achieve natural conditions by 2064.

Section 308 of the Regional Haze Rule (40 CFR part 51) includes discussion on control strategies for improving visibility impairment. One of these strategies is the requirement under 40 CFR 51.308(e) for certain stationary sources to install Best Available Retrofit Technology (BART) to reduce emissions of three (3) visibility impairing pollutants, nitrogen oxides (NO

x ), particulate matter (PM), and sulfur dioxide (SO 2 ). EPA published Appendix Y to part 51

- Guidelines for BART Determinations Under the Regional Haze Rule in the July 6, 2005 Federal Register to provide guidance to regulatory authorities for making BART determinations. Chapter 6, Section 9, Best Available Retrofit Technology was adopted into the Wyoming Air Quality Standards and Regulations (WAQSR) and became effective on December 5, 2006. The Wyoming Department of Environmental Quality, Air Quality Division (Division) will

determine BART for NO

x and PM 10 for each source subject to BART and include each determination in the §308 Wyoming Regional Haze State Implementati on Plan (SIP).PacifiCorp Naughton Plant

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Section 309 of the Regional Haze Rule (40 CFR part 51), Requirements related to the Grand Canyon Visibility Transport Commission , provides states that are included within the Transport Region addressed by the Grand Canyon Visibility Trans port Commission (i.e., Arizona, California, Colorado, Idaho, Nevada, New Mexico, Oregon, Utah, and Wyoming) an alternative to the requirements established in 40 CFR 51.308. This alternative control strategy for improving visibility contains special provis ions for addressing SO 2 emissions, which include a market trading program and a provision for a series of SO 2 milestones. Wyoming submitted a §309 Regional Haze SIP to EPA on December 29, 2003. As of the date of this analysis, EPA has not taken action on the SIP. National litigation issues related to the Regional Haze Rule, including BART, required states to submit revisions. On November 21, 2008, the State of Wyoming submitted revisions to the 2003 §309 Regional Haze SIP submittal. Sources that are

su bject to BART are required to address SO 2 emissions as part of the BART analysis even though the control strategy has been identified in the Wyoming §309 Regional Haze SIP.

On February 12 , 2007, in accordance with the requirements of WAQSR Chapter 6 Secti on 9(e)(i), PacifiCorp submitted three ( 3 ) BART applications, one for each existing coal

- fired boiler at the Naughton Power Plant. A map showing the location of PacifiCorp‟s Naughton Power Plant is attached as Appendix

A.

October 16, 2007, PacifiCorp sub mitted updated applications for each of the three ( 3 ) Naughton units subject to BART. Additional modeling performed after the February 12 , 2007 submittal and revised visibility control effectiveness calculations were included.

December 5, 2007, PacifiCor p submitted revised applications incorporating changes to the post

processing of the visibility model runs for each of the three ( 3 ) Naughton units.

March 31, 2008, PacifiCorp submitted addendums to each of the BART applications for Naughton Units

1

- 3 . R evised cost estimates and updated visibility modeling for two (2) NO

x control scenarios were

included in the addendums.

February 2, 2009, PacifiCorp submitted addition al information addressing presumptive BART emission

rates for the three ( 3 ) coal

- fired b oilers at the Naughton Power Plant. The information addresses the type

of coal fired in the three boilers and its impact on NO

x emissions

.

BART ELIGIBILITY DETERMINATION:

In August of 2005 the Wyoming Air Quality Division began an internal review of sou rces that could be subject to BART. This initial effort followed the methods prescribed in 40 CFR part 51, Appendix Y: Guidelines for BART Determinations Under the Regional Haze Rule to identify sources and facilities. The rule requires that States ident ify and list BART

- eligible sources, which are sources that fall within the 26 source categories, have emission units which were in existence on August 7, 1977 but not in operation before August 7, 1962 and have the potential to emit more than 250 tons per year (tpy) of any visibility impairing pollutant when emissions are aggregated from all eligible emission units at a stationary source. Fifty

- one (51) sources at fourteen (14) facilities were identified that could be subject to BART in Wyoming.PacifiCorp Naughton Plant

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The ne xt step for the Division was to identify BART

- eligible sources that may emit any air pollutant which may reasonably be anticipated to cause or contribute to impairment of Class I area visibility. Three pollutants are identified by 40 CFR part 51, Appendix Y as visibility impairing pollutants. They are sulfur dioxide (SO 2 )

, nitrogen oxides (NO

x ), and particulate matter (PM). Particulate matter with an aerodynamic diameter of 10 microns or less (PM 10 ) was used as an indicator of PM. In order to determine visibility impairment of each source, a screening analysis was performed using CALPUFF. Sources that

emitted over 40 tons of SO 2 or NO

x or 15 tons of PM 10 were included in the screening analysis. Using three years of meteorological data, the screening an alysis calculated visibility impacts from sources at nearby Class I areas. Sources whose modeled 98 th percentile 24

- hour impact or 8 th highest modeled impact, by year, was equal to or greater than 0.5 deciviews (dv) above natural background conditions (Δd v) were determined to be subject to BART. For additional information on the Division‟s screening analysis see the Visibility Improvement Determination: Screening Modeling section of this analysis. The

three existing coal

- fired boilers at PacifiCorp‟s Nau ghton Power Plant were determined to be subject to BART. PacifiCorp was notified in a letter dated June 14, 2006 of the Division‟s finding.

DESCRIP TION OF BART ELIGIBLE SOURCES:

PacifiCorp‟s Naughton Power Plant is comprised of three ( 3 ) pulverized coal

- fired units with a total net generating capacity of 7 0 0 m ega w atts (MW). Naughton Unit 1 generates a nominal 160 MW and commenced operation in 1963. The boiler on U nit 1 is tangential fired and was manufactured by Combustion Engineering (now ALSTOM ). Th e unit uses good combustion practices (GCP) to control

NO

x emissions. It was originally constructed with a Research Cottrell mechanical dust collector to control particulate matter emissions , and in 1974 a Lodge Cottrell electrostatic precipitator (ESP) w as added to further reduce particulate emissions

. SO 2 emissions are controlled using lo w sulfur coal to

maintain emissions below 1.2 lb per million British thermal units (MMBtu)

. Naughton Unit 2 generates a nominal 210 MW and commenced operation in 196 8

. The boiler on Unit 2 is also tangential fired and

was manufactured by ALSTOM

. The unit uses GCP to control NO

x emissions. It was originally

constructed with a United Conveyor mechanical dust collector to control particulate matter emissions and

in 197 6 a Lodge Cottrell ESP was added to further reduce particulate emissions

. SO 2 emissions are controlled using lo w sulfur coal to maintain emissions below 1.2 lb/MMBtu . Naughton Unit 3 generates
a nominal 330 MW and commenced operation in 1971 . The boiler on Unit 3 is tangential fired and was

manufactured by ALSTOM

. The unit was retro fitted with ALSTOM LCCFS II low NO

x burners (LNB) in 1999. Particulate emissions are controlled using a Buell weighted wire ESP and flue gas conditioning (FGC)

. SO 2 emission s are controlled using low sulfur coal and a UOP LLC two

- tower sodium based wet flue gas desulfurization ( W FGD) system that was installed in 1997

.PacifiCorp Naughton Plant

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Table 1: Naughton Units 1

- 3 Pre

- 2005 Emission Limits (a)

Source Firing Rate

(MMBtu/hour) Existi ng

Controls NO

x

(lb/MMBtu) SO 2

(lb/MMBtu) PM/PM 10

(lb/MMBtu) (c) (d)

Unit 1 1

, 850 GCP, ESP 0. 7 5 (3

- hour block)
0. 58 (annual) (b) 1.2 (2

- hour block ) 0.24

Unit 2 2

, 400 GCP , ESP 0. 75 (3

- hour block)
0. 54 (annual) (b) 1.2 (2

- hour block ) 0. 23

Unit 3 3

, 7 00 LNB , ESP,
FGC, WFGD 0. 75 (3

- hour block)

0.4 9 ( annual) (b) 0.5 (2

- hour block ) 0. 21

( a) Emissions taken from Operating Permit 31

- 12 1

. ( b ) Limit established through the 40 CFR part 7 6 (Acid Rain Program).

( c ) Based on the equation: 0.8963/I 0.1743 lb/MMBtu of he at input where I=boiler heat input in MMBtu/hr.

(d) Averaging period is 1 hour as determined by the appropriate test method

.

PacifiCorp recently received an Air Quality permit to modify the three Naughton units. Units 1 and 2 will be equipped with new st ate

- of

- the

- art low NO

x systems with advanced overfire air (OFA) and flue gas conditioning systems to help improve the particulate removal efficiency of the existing ESPs on each of the units. New wet flue gas desulfurization systems will be installed on N aughton Units 1 and 2. The existing ESP on Naughton Unit 3 will be replaced with a new full

- scale fabric filter (FF) at which time the existing FGC system will be removed. Table 2 lists the new emission limits for the Naughton units

. They become effecti ve after the corresponding controls are installed and the applicable initial performance test s are completed

.

Table 2: Naughton Units 1

- 3 Proposed Emission Limits (a)

Source Permitted

Controls NO

x SO 2 PM/PM 10

Unit 1 New LNB with

advanced OFA

, FGC

, ESP,

WFGD 0.75 lb/MMBtu

(3

- hr rolling)
0. 26 lb /MMBtu

(12

- month rolling) 481 lb/hr

(12

- month rolling) 0. 15 lb/MMBtu

( 1 2

- month rolling ) 1.2 lb/MMBtu

(2

- hr rolling)
833 lb/hr

( 3

- hr block ) 0.042 lb/MMBtu (b)

78 lb/hr (b)

340 tpy (b)

Unit 2 New LNB with

advanc ed OFA,
FGC, ESP,

WFGD 0.75 lb/MMBtu

(3

- hr rolling)
0. 26 lb/MMBtu

(12

- month rolling) 624 lb/hr

(12

- month rolling) 0. 15 lb/MMBtu

(12

- month rolling) 1.2 lb/MMBtu

(2

- hr rolling) 1,080 lb/hr

(3

- hr block) 0.054 lb/MMBtu (b)

130 lb/hr (b)

568 tpy (b)

Unit 3 Existing LNB

with OFA, FF

, WFGD 0. 7 5 lb/MMBtu

(3

- hr rolling)
0. 4 5 lb/MMBtu

(12

- month rolling) 1,665 lb/hr

(12

- month rolling) 0. 5 lb/MMBtu

(2

- hour rolling ) 1, 850 lb/hr

( 3

- hr block ) 0.015 lb/MMBtu

(24

- hour block) 56 lb/hr

(24

- hour block) 243 tpy

(a) Emissio ns limits taken from recent New Source Review construction permit for Naughton Units 1

- 3

. (b) Averaging period is 1 hour as determined by 40 CFR 60.46 and EPA Reference Test Methods 1

- 4 and 5

.PacifiCorp Naughton Plant

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A construction sc hedule for installing new LNB with advance d OFA , FGC, and WFGD on Naughton Units 1 and 2, and a full

- scale FF on Unit 3 was submitted in the permit application. The installation of FGC on Units 1 and 2 was originally proposed to occur in 2008, however since the authorization to install

the contro ls is dependent on the issuance of the pending Air Quality permit, installation will be delayed until permit issuance. A construction summary is provided in Table 3.

Table 3: Upgrades to Naughton Units 1

- 3

Source NO

x

Control Equipment

, Installation yea r SO 2 Control Equipment

, Installation year PM/ PM 10 Control Equipment

, Installation year

Unit 1 New LNB with OFA, 201 2 WFGD , 201 2 FGC, 2009 (a)

Unit 2 New LNB with OFA, 201 1 WFGD , 20 11 FGC, 20 0 9 (a)

Unit 3 LNB with OFA, Existing WFGD, Existing FF, 2014

(a) PacifiCorp originally proposed installing FGC on Units 1 and 2 in 2008, however the inst allation date has been moved to the date of permit issuance.

CHAPTER 6, SECTION 9

– BEST AVAILABLE RETROFIT TECHNOLOGY (BART)

A BART determination is an emission limit based on the application of a continuous emission reduction technology for each visibility impairing pollutant emitted by a source. It is “...established, on a case

- by

case basis, taking into consideration (1) the costs of compliance, (2) the energy and non

- air quality environmental impacts of compliance, (3) any pollution equipment in use or in existence at the source, (4) the remaining useful life of the source, and (5) the degree of improvement in visibility which may reasonably be anticipated to r esult from the use of such technology.” 1 A BART analysis is a comprehensive evaluation of potential retrofit technologies with respect to the five criteria above. At the conclusion of the BART analysis, a technology and corresponding emission limit is ch osen for each pollutant for each unit subject to BART.

Visibility control options presented in the application for each source were reviewed using the methodology prescribed in 40 CFR 51 Appendix Y, as required in WAQSR Chapter 6 Section 9(c)(i).

This me thodology is comprised of five basic steps:

Step 1: Identify all 2 available retrofit control technologies Step 2: Eliminate technically infeasible options Step 3: Evaluate control effectiveness of remaining control technologies Step 4: Evaluate impact s and document the results Step 5: Evaluate visibility impacts

1 40 CFR Part 51 Appendix Y: Guidelines for BART Determinations under the Regional Haze Rule (70 Federal Register 39163).

2 Footnote 12 of 40 CFR 51 Appendix Y defines the intended use of „all‟ by stating “...you must identify the most stringent option and a reasonable set of options for analysis that reflects a comprehensive list of available technologies.”PacifiCorp Naughton Plant

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The Division acknowledges that BART is intended to identify retrofit technology for existing sources and is not the same as a top down analysis required for new sources under the Prevent ion of Significant Deterioration (PSD) rules known as Best Available Control Technology (BACT). Although BART is not the same as BACT, it is possible that BART may be equivalent to BACT on a case

- by

- case basis. The Division applied all five steps to each visibility impairing pollutant emitted from each coal

- fired boiler (Units 1

- 3) at the Naughton Power Plant thereby conducting a comprehensive BART analysis for NO

x , SO 2 and PM/PM 10

.

PRESUMPTIVE LIMITS FOR SO 2 AND NO X FROM UTILITY BOILERS

EPA conducted detailed analyses of available retrofit technology to control NO

x and SO 2 emissions from

coal

- fired power plants. These analyses considered unit size, fuel type, cost effectiveness, and existing

controls to determine reasonable control levels based on the application of an emissions reduction technology.

EPA‟s presumptive BART SO 2 limits analysis considered coal

- fired units with existing SO 2 controls and units without existing control. Four key elements of the analysis were: “...(1) identification of all

p otentially BART

- eligible EGUs [electric generating units], and (2) technical analyses and industry research to determine applicable and appropriate SO 2 control options, (3) economic analysis to determine cost effectiveness for each potentially BART

- eligibl e EGU, and (4) evaluation of historical emissions and forecast emission reduction for each potentially BART

- eligible EGU.” 3 491 BART

- eligible coal

- fired units were identified and included in the presumptive BART analysis for SO 2 . Based on removal

efficie ncies of 90% for spray dry lime dry flue gas desulfurization systems and 95% for limestone forced oxidation wet flue gas desulfurization systems, EPA calculated projected SO 2 emission reductions and

cost effectiveness for each unit. Based on the results o f this analysis, EPA concluded that the majority of

identified BART

- eligible units greater than 200 MW without existing SO 2 control can meet the presumptive limits at a cost of $400 to $2,000 per ton of SO 2 removed.

A presumptive BART NO

x limits analysis was performed using the same 491 BART

- eligible coal

- fired

units identified in the SO 2 presumptive BART analysis. EPA considered the same four key elements and established presumptive NO

x limits for EGUs based coal type and boiler configuration. For all b oiler types, except cyclone, presumptive limits were based on combustion control technology (e.g., low NO

x burners and overfire air). Presumptive NO

x limits for cyclone boilers are based on the installation of SCR, a post combustion add

- on control. EPA a cknowledged that approximately 25% of the reviewed units could not meet the proposed limits based on current combustion control technology, but that nearly all the units could meet the presumptive limits using advanced combustion control technology, such a s rotating opposed f

ire air. National average cost effectiveness values for presumptive NO

x limits ranged from $281 to $1,296 per ton removed.

Based on the results of the analyses for presumptive NO

x and SO 2 limits, EPA established presumptive

limits for EGUs greater than 200 MW operating without NO

x post combustion controls or existing SO 2 controls located at facilities with a generating capacity greater than 750 MW. 40 CFR part 51 Appendix Y states that the presumptive SO 2 level for an uncontrolled uni t is either 95% control or 0.15 lb/MMBtu. Presumptive NO

x levels for uncontrolled units are listed in Table 1 of Appendix Y and classified by the boiler burner configuration (unit type) and coal type. NO

x emission values range from 0.62 lb/MMBtu

down to 0.15 lb/MMBtu. While Appendix Y establishes presumptive SO 2 limits and says that states

3 40 CFR Part 51 A ppendix Y: Guidelines for BART Determinations under the Regional Haze Rule (70 Federal Register 39133).PacifiCorp Naughton Plant

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should require presumptive NO

x , it also clearly gives states discretion to “...determine that an alternative [BART] control level is justified based on a careful conside ration of the statutory factors.” 4 The Division‟s following BART analysis for NO

x , SO 2 , and PM/PM 10 takes into account each of the five statutory factors.

PacifiCorp‟s Naughton Power Plant consists of three units with a total generating capacity of 700 M W. Naughton Unit 1, generating nominal 160 MW, Unit 2, generating a nominal 2 1 0 MW, and Unit 3, generating a nominal 330 MW, are tangentially fired pulverized coal boilers. SO 2 emissions from Units 1 and 2 are controlled by burning low sulfur coal withou t the use of add

- on controls. Unit 3 SO 2 emissions are control using an existing UOP LLC two

- tower sodium based WFGD system that was installed in

1997 . NO

x emissions from Units 1 and 2 are not controlled using either NO

x combustion controls (LNB)

or add

- on controls. ALSTOM LCCFS II LNB were installed on Unit 3 in 1999. Presumptive SO 2 limits of 95% reduction or 0.15 lb/MMBtu and presumptive NO

x limits based on unit type and coal type, do not apply to the three Naughton units because the total generating capacity of the facility is below 750 MW

. However, the Division required additional analysis of potential retrofit controls for NO

x , SO 2 , and

PM/PM 10 , taking into consideration all five statutory factors, before making a BART determination.

NO

x emission s from coal combustion are affected by the chemical and physical properties of the feed coal. Heat content, carbon content, fuel

- bound nitrogen and oxygen, volatile matter content, volatility, and agglomeration of the feed coal significantly affect the de sign and operation of combustion controls such as LNB and OFA systems. This is evidenced by EPA‟s decision to classify presumptive NO

x emission levels based on specific controls as applied to different boiler types firing various types of coal.

In EPA‟s analysis for establishing presumptive NO

x limits, three primary coal types were identified: bituminous, sub

- bituminous, and lignite. These coal classifications were based on EPA's Mercury Information Collection Request (ICR) for the Electric Utility Steam Generating Unit Mercury Emissions Information Collection Effort, OMB Control Number 2060

- 0396. In responding to the ICR PacifiCorp reported that Naughton Units 1

- 3 burned sub

- bituminous coal. Subsequent to the ICR PacifiCorp further

evaluated the coal c lassification using ASTM method D 388

- 05 Standard Classification of Coals by

Rank , an industrial standard for classifying coal. After reviewing method D 388 coal classifications, PacifiCorp noted that high volatile C bituminous coal and sub

- bituminous A coals have similar heating values, but different agglomeration characteristics. Table 3 from ASTM method D 388

- 05 Standard Classification of Coals by Rank is shown as Figure 1.

4 Ibid. (70 Federal Register 39171).PacifiCorp Naughton Plant

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Figure 1

PacifiCorp contracted with CH2M Hill and ALSTOM, a boiler manufacturer, to further research the impact of coal characteristics on NO

x emissions. Laboratory tests, including tests using a bench

- scale drop tube furnace run by ALSTOM, showed the influence of both fuel type and stoichiometry on NO

x emission s. Additional testing examined the impact of coal volatility on NO

x emissions. Based on the results of the research, PacifiCorp concluded that “[t]he coals used at Bridger and Naughton tend to be higher rank than typical PRB coals. As such, they will ha ve less fuel nitrogen released during the devolatilization phase of combustion, and thus will produce have [ sic ] somewhat higher NO

x than will

true PRB coals when fired under low

- NO

x staged conditions.”PacifiCorp Naughton Plant

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PacifiCorp also examined how fuel

- bound NO

x evolves from solid coal char after the volatile component of the coal is combusted. After reviewing laboratory test data on NO

x conversion from fuel

- bound nitrogen during volatilization and during char combustion, PacifiCorp concluded: “Typically, lower r ank (more reactive) fuels have more fuel NO

x associated with the volatiles than the char, so low

- rank coals

overall have the lowest NO

x potential. The performance of the Bridger and Naughton coals tends to fall

between the PRB coals and eastern bituminous coals shown [Figure 3, CH2M Hill‟s Technical Memorandum: Coal Quality and Nitrogen Oxide Formation submitted by PacifiCorp on February 2, 2009]. This would support the conclusion that the Bridger and Naughton coals have a NO

x reduction potential below ea stern bituminous coals, but not as low as true PRB coals.”

Coal characteristics affect the design and efficiency of pollution control equipment, as well as boiler design. Based on the information presented by PacifiCorp, it is likely that the Naughton un its will not be

able to meet presumptive NO

x levels of 0.15 lb/MMBtu for tangential boilers firing sub

- bituminous coal. Air Quality Permit MD

- 1552 authorized the installation of new ALSTOM TFS 2000 TM LNB with separated OFA systems on all four u nit s at Pac ifiCorp‟s Jim Bridger Power Plant. Units 2

- 4 are currently equipped with this combustion control system. Recent monitoring data supplied by the continuous emissions monitoring systems on the three units indicate that a NO

x emission rate of 0.15 lb/MMBtu is not achievable on a continuous basis. Fuel characteristics of the coal burned at the Naughton Power Plant are similar to the coal fed to the Jim Bridger un i t s, which are also tangentially

- fired boilers. In the

absence of site

- specific operational data , it is reasonable to anticipate NO

x reductions from the application

of new state

- of

- the

- art LNB on the Naughton units will be comparable to the Jim Bridger units.

Naughton was included in EPA‟s presumptive limits analyses for NO

x and SO 2 . As a result of the final publication of 40 CFR part 51, Appendix Y establishing BART presumptive limits for facilities with a generating capacity greater than 750 MW

, Naughton is not subject to presumptive limits. T he Division required additional analysis of potential retrofit controls for NO

x , which included add

- on controls in addition to combustion control, taking into consideration all five statutory factors, before making a BART

determination. And while PacifiCorp addressed applicability of presumptive NO

x l imit s f or the Naughton

units in the ir BART application s
, the effectiveness of the proposed combustion control for removing NO

x was evaluated in this analysis under Step 2: Eliminate technically infeasible options, Step 3: Evaluate

control effectiveness of remaini ng control technologies, and Step 4: Evaluate impacts and document the results of the BART process.

NO

x : IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

PacifiCorp identified four control technologies to control NO

x emissions: (1) low NO

x burners with

a dvanced OFA, (2) rotating opposed fire air (ROFA), (3) selective non

- catalytic reduction (SNCR), and (4) selective catalytic reduction (SCR). LNB with advanced OFA and ROFA are two combustion control technologies that reduce NO

x emissions by controlling t he combustion process within the boiler. These two technologies have been demonstrated to effectively control NO

x emissions by reducing the amount of oxygen directly accessible to the fuel during combustion creating a fuel

- rich environment and by

enhancin g control of air

- fuel mixing throughout the boiler‟s combustion zone. SNCR and SCR are add

on controls that provide a chemical conversion mechanism for NO

x to form molecular nitrogen (N 2 ) in the flue gas after combustion occurs. These four technologies a re proven emissions controls commonly used

on coal

- fired electric generating units.PacifiCorp Naughton Plant

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1. Low NO

x Burners with Advanced Overfire Air

– LNB technologies can rely on a combination of fuel staging and combustion air control to suppress the formation of thermal N O

x . Fuel staging occurs in the very beginning of combustion, where the pulverized coal is injected through the

burner into the furnace. Careful control of the fuel

- air mixture leaving the burner can limit the amount of oxygen available to the fuel during combustion creating a fuel rich zone that reduces the nitrogen to molecular nitrogen (N 2 ) rather than using oxygen in the combustion air to oxidize the nitrogen to NO

x . The addition of advanced overfire air provides additional NO

x control by injecting ai r into the lower temperature combustion zone when NO

x is less likely to form. This allows complete combustion of the fuel while reducing both thermal and chemical NO

x formation.

2. Rotating Opposed Fire Air

– ROFA can be used with LNB technology to control the combustion process inside the boiler. Similar to the advanced overfire air technology discussed above, ROFA manipulates the flow of combustion air to enhance fuel

- mixing and air

- flow characteristics within the boiler. By inducing rotation of the comb ustion air within the boiler, ROFA can reduce the number of high temperature combustion zones in the boiler and increase the effective heat absorption. Both of which effectively reduce the formation of NO

x caused by fuel combustion

within the boiler.

3. Sel ective Non

- Catalytic Reduction

– SNCR is similar to SCR in that it involves the injection of a reducing agent such as ammonia or urea into the flue gas stream. The reduction chemistry, however, takes place without the aid of a catalyst. SNCR systems rely on appropriate injection temperatures, proper mixing of the reagent and flue gas, and prolonged retention time in place of the catalyst. SNCR operates at higher temperatures than SCR. The effective temperature range
for SNCR is 1,600 to 2,100 F. SNCR s ystems are very sensitive to temperature changes and typically have lower NO

x emissions reduction (up to fifty or sixty percent) and may emit ammonia out of the exhaust stack when too much ammonia is added to the system.

4. Selective Catalytic Reduction

– SC R is a post combustion control technique in which vaporized ammonia or urea is injected into the flue gas upstream of a catalyst. NO

x entrained in the flue gas is reduced to molecular nitrogen (N 2 ) and water. The use of a catalyst facilitates the reactio n at an exhaust temperature range of 300 to 1,100 F, depending on the application and type of catalyst

used. When catalyst temperatures are not in the optimal range for the reduction reaction or when too much ammonia is injected into the process, unreacte d ammonia can be released to the atmosphere through the stack. This release is commonly referred to as ammonia slip . A well controlled SCR system typically emits less ammonia than a comparable SNCR control system.

In addition to applying these control t echnologies separately, they can be combined to increase overall

NO

x reduction. PacifiCorp evaluated the application of LNB with advanced OFA in combination with

both SNCR and SCR add

- on controls.

NO

x : ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

None of th e four control technologies proposed to control NO

x emissions were deemed technically infeasible by PacifiCorp.PacifiCorp Naughton Plant

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NO

x : EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

The Division considers the control effectiveness of a proposed control technol ogy to be equivalent to the

BART

- determined permit limit. The limit is based on continuous compliance when the control equipment is well maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions. In order to demonstrate continuous compliance with the permit limit it is important to consider that even well maintained and operated equipment will have some emissions variability. Complex emission control equipment, such as LNB with advanced OFA, general ly have inherent variability that must be considered when establishing the limit. Otherwise, the source will be out of compliance even though the equipment is operated and maintained as well as possible.

Pacif iCorp contracted with Sargent and Lundy (S&L) to conduct a study of applicable NO

x control technologies for the Naughton units and to collect data from boiler vendors. Based on results from the study, PacifiCorp indicates that new LNB with advanced OFA on Naughton U nits 1 and 2 would result in

a NO

x emission rate as low as 0.24 lb/MMBtu. On pages 3

- 9 of the December 2007 submittals for Naughton Units 1 and 2 PacifiCorp states: “ PacifiCorp has indicated that this rate [0.24 lb/MMBtu] corresponds to a vendor guarantee plus an added operating margin, n ot a vendor prediction, and they believe that this emission rate can be sustained as an average between overhauls. ” However, due to unforeseen operational issues associated with retrofitting the boilers, including site specific challenges, PacifiCorp prop oses an additional NO

x increase of 0.02 lb/MMBtu to total 0.26 lb/MMBtu. Naughton Unit 3 is equipped with LNB and has demonstrated compliance with a 0.40 lb/MMBtu NO

x emission rate. PacifiCorp r eviewed the option of tuning the existing LNB to further re duce NO

x emissions and indicates that lowering emissions to 0.35 lb/MMBtu is possible. In the March 26, 2008 Addendum for Unit 3, PacifiCorp proposed a permitted rate of 0.37 lb/MMBtu to account for unforeseen operational issues and site specific challeng es.

PacifiCo rp worked with Mobotec to conduct an analysis of retrofitting the existing boilers at the Naughton Power Plant with Mobotec‟s ROFA. Mobotec analyzed the operation of existing burners and OFA ports. Typically the existing burner system does n ot require modification and the existing OFA ports are not used by a new ROFA system. Instead, computational fluid modeling is performed to determine the location of the new ROFA ports. Mobotec concluded that a NO

x emission rate of 0. 2 4

lb/MMBtu was achi evable on Units 1 and 2 using ROFA technology. Unit 3 may achieve 0.26

lb/MMBtu. PacifiCorp added an additional operating margin to each anticipated emission rate of 0.0 2 lb/MMBtu to account for site specific issues, including the type of coal burned in the boilers , for total proposed emission rate s of 0.26 lb/MMBtu for Units 1 and 2, and 0.28 lb/MMBtu for Unit 3

.

S&L evaluated emission reductions associated with installing SNCR in addition to retrofitting the boilers

with LNB with advanced OFA. Based o n installing LNB with OFA capable of achieving a NO

x emission

rate of 0.2 6 lb/MMBtu on Units 1 and 2 , S&L concluded that SNCR can reduce emissions by 20 % resulting in a projected emission rate of 0. 21 lb/MMBtu. Installing SNCR on Unit 3 can reduce the

ant icipated rate of 0.37 lb/MMBtu by 20% resulting in a NO

x emission rate of 0.30 lb/MMBtu. PacifiCorp noted in the analysis that the economics of SNCR are greatly impacted by reagent utilization. When SNCR is used to achieve high levels of NO

x reduction, l ower reagent utilization can result in significantly higher operating cost.PacifiCorp Naughton Plant

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S&L prepared the design conditions and cost estimates for installing SCR in each of the Naughton units. A high

- dust SCR configuration, where the catalyst is located downstream from the boiler economizer before the air heater and any particulate control equipment, was used in the analysis. The flue gas ducts would be routed to a separate large reactor containing the catalyst to increase the removal rate. Additional catalyst wo uld be added to accommodate the coal feedstock. Based on the S&L design, which included installing both new LNB with advanced OFA and SCR, PacifiCorp concluded the Naughton

u nits could achieve a NO

x emission rate of 0.07 lb/MMBtu.

Table 4 : NO

x Emission R ates Per Boiler

Control Technology Unit 1 Resulting NO

x Emission Rate (lb/MMBtu) Unit 2

Resulting NO

x Emission Rate (lb/MMBtu) Unit 3

Resulting NO

x Emission Rate (lb/MMBtu)

Existing Burners 0. 58 (a) 0. 54 (a) 0. 45 ( b )

Tune Existing LNB

-- -- 0.37

New LN B with advanced OFA 0.26 0.26

--

Existing Burners with ROFA 0.2 6 0.2 6 0.2 8

New LNB with advanced OFA and SNCR 0. 21 0. 21 0. 30

New LNB with advanced OFA and SCR 0.07 0.07 0.07

(a) Annual averaged NO

x emissions listed in Operating Permit 31

- 121

. ( b ) Annua l averaged NO

x emission listed in Operating Permit 3

- 2

- 121.

NO

x : EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the energy impacts associated with installing each of the proposed control technologies. Installing new LNB with advanced OFA on Naughton Units 1 and 2 and tuning the existing

LNB on Unit 3 will not significantly impact the boiler efficiency or forced draft fan power usage, two common potential areas for adverse energy impact often affected by changes in boiler combustion.

Installi ng the Mobotec ROFA system has a significant energy impact on Naughton

. One (1) 1,900 horsepower (hp) ROFA fan on Unit 1, one (1) 3,500 hp ROFA fan on Unit 2, and one (1) 6,000 hp ROFA

fan on Unit 3 are required to induct a sufficient volume of air into e ach boiler to cause rotation of the combustion air throughout the boiler. Th e annual energy impact from operating the proposed ROFA fans

is 11,200 Mega Watt

- hour ( MW

- hr )

, 20,600 MW

- hr, and 35,300 MW

- hr for Unit s 1, 2, and 3, respectively.

PacifiCorp dete rmined the SNCR sys tem would require between 200 k ilo Watt (kW) and 300 kW of additional power to operate pretreatment and injection equipment, pumps, compressors, and control systems. In addition to energy costs associated with the reagent handling and i njection, installation of the SCR catalyst will require additional power from the existing flue gas fan systems to overcome the pressure drop across the catalyst. Based on the S&L study, PacifiCorp estimated the additional power requirements for SCR insta llation on each unit at the Naughton Power Plant ranged from approximately

1.0 MW to 2.0 MW.PacifiCorp Naughton Plant

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PacifiCorp evaluated the environmental impacts from the proposed NO

x control technologies. Installing

LNB with advanced OFA may increase carbon monoxide (CO) emi ssions and unburned carbon in the ash, commonly referred to as loss on ignition (LOI). Mobotec has predicted CO emissions and LOI would be the same or lower than prior levels for the ROFA system. The installation of SNCR and SCR could impact the saleabil ity and disposal of fly ash due to higher ammonia levels, and could potentially create a visible stack plume sometimes referred to as a blue plume, if the ammonia injection rate is not well controlled. Other environmental impacts involve the storage of am monia, especially if anhydrous ammonia is used, and transportation of the ammonia to the power plant site.

PacifiCorp anticipates operating Naughton Units 1

- 3 indefinitely and did not include life extension costs in the economic analysis. A standard cont rol life of 20 years was used to calculate the capital recovery factor. The annual cost to control was determined using a capital recovery factor based on a 7.1% interest rate. PacifiCorp labor and service costs were used to calculate the annual operatin g and maintenance costs. Annual power costs, including a cost escalation factor, associated with the operation of pollution

controls were included.

Several different metrics can be considered when evaluating the cost

- benefit relationships of different

em ission control technologies. In 40 CFR part 51 Appendix Y two metrics are specifically mentioned: cost effectiveness and incremental cost effectiveness. Through the application of BACT, the Division has extensive experience using cost effectiveness (i.e. , dollars per ton of pollutant removed) to evaluate different control technologies. Incremental cost effectiveness is also used extensively by the Division when comparing emission controls under the BACT process. While the BART and the BACT processes

are not necessarily equivalent, control determinations from either process are based on cost effectiveness

and incremental cost effectiveness and are indicative of the economic costs to control emissions. In addition to providing cost effectiveness and incre mental cost effectiveness results, PacifiCorp provided cost information in terms of cost of applying emission controls and the level of visibility improvement achieved (i.e., dollars per deciviews). While this metric can illustrate the control cost and vi sibility improvement differences between control options, it is not commonly used to assess the overall effectiveness of pollution control equipment. When performing the presumptive BART limits analyses

for NO

x and SO 2 , EPA addressed cost effectiveness an d incremental cost effectiveness separate from visibility improvement. EPA did not use the dollars per deciview metric to compare control options. Visibility improvements from the application of the analyzed control measures used to establish presumptive levels were addressed in a separate visibility analysis. As discussed in the comprehensive visibility analysis presented later in this analysis as Step 5: Evaluate visibility impacts, the Division evaluated the amount of anticipated visibility improvemen t gained by the application of additional emission control technology. The Division considered capital cost, annual cost, cost effectiveness, and incremental cost effectiveness in the evaluation of each proposed NO

x emission control. Economic and

environ mental costs for additional NO

x controls on Naughton Units 1

- 3 are summarized in the following

tables.PacifiCorp Naughton Plant

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Table 5 : Naughton Unit 1 Economic Costs

Cost Existing

Burners New LNB

with advanced

OFA Existing

Burners with

ROFA New LNB with

advanced OFA

a nd SNCR New LNB with

advanced OFA

and SCR

Control Equipment Capital Cost $0 $9,600,000 $9,068,746 $17,526,855 $94,600,000

Capital Recovery Factor N/A 0.09513 0.09513 0.09513 0.09513

Annual Capital Recovery Costs $0 $ 913

, 248 $ 862

, 710 $ 1

, 667

, 330 $ 8 ,9 99

, 29 8

Annual O&M Costs $0 $ 8 0,000 $ 6 79

, 764 $ 30 5, 033 $ 1

, 231

, 912

Annual Cost of Control $0 $ 993

, 248 $ 1

, 542

, 474 $ 1

, 972

, 363 $ 10

, 231

, 210

Table 6 : Naughton Unit 1 Environmental Costs

Existing

Burners New LNB

with advanced

OFA Existing

Burners with

ROFA New LNB with

advanced OFA

and SNCR New LNB with

advanced OFA

and SCR

NO

x Emission Rate (lb/MMBtu) 0. 58 0.26 0.2 6 0.21 0.07

Annual NO

x Emission (tpy) ( a ) 4,230 1,896 1,896 1,531 510

Annual NO

x Reduction (tpy) N/A 2,334 2

, 334 2,699 3,720

Annual Cost of Control $0 $ 993

, 248 $ 1

, 542

, 474 $ 1

, 972

, 363 $ 10

, 231

, 210

Cost per ton of Reduction N/A $ 426 $ 661 $ 731 $ 2,750

Incremental Cost per ton of Reduction N/A $ 426 $ 661 (b) $ 1

, 178 $ 8

, 089

( a ) Annual emissions based on individual heat input rate of 1

, 850 MMBtu/hr for 7,884 hours of operation per year.

(b) Incremental cost cannot be calculated as the reduced tons of NO

x are anticipated to be the same as installing new LNB with advanced

OFA.

Table 7 : Naughton Unit 2 Economic Costs

Cost Existing

Burners New LNB

with advanced

OFA Existing

Burners with

ROFA New LNB with

advanced OFA

and SNCR New LNB with

advanced OFA

and SCR

Control Equipment Capital Cost $0 $9,100,000 $10,586,222 $19,878,765 $115,900,000

Capital Recovery Factor N/A 0.09513 0.09513 0.09513 0.09513

Annual Capi tal Recovery Costs $0 $865,683 $1,007,067 $1,891,067 $11,0 25,567

Annual O&M Costs $0 $80,000 $1,148,862 $369,890 $1,639,352

Annual Cost of Control $0 $945,683 $2,155,929 $2,260,957 $12,664,919PacifiCorp Naughton Plant

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Table 8 : Naughton Unit 2 Environmental Costs

Existing

B urners New LNB

with advanced

OFA Existing

Burners with

ROFA New LNB with

advanced OFA

and SNCR New LNB with

advanced OFA

and SCR

NO

x Emission Rate (lb/MMBtu) 0.54 0.26 0.26 0.21 0.07

Annual NO

x Emission (tpy) ( a ) 5,109 2,460 2,460 1,987 662

Annual NO

x R eduction (tpy) N/A 2,649 2,649 3,122 4,447

Annual Cost of Control $0 $945,683 $2,155,929 $2,260,957 $12,664,919

Cost per ton of Reduction N/A $357 $814 $724 $2,848

Incremental Cost per ton of Reduction N/A $357 $814 (b) $2 22 $ 7

, 8 52

( a) Annual emissions based on individual heat input rate of 2

, 400 MMBtu/hr for 7,884 hours of operation per year.

(b) Incremental cost cannot be calculated as the reduced tons of NO

x are anticipated to be the same as installing new LNB with advanced

OFA.

Table 9 : Naughton Un it 3 Economic Costs

Cost Existing

LNB Tuning

Existing LNB Existing LNB

and SNCR Existing LNB

with ROFA Existing LNB

and SCR

Control Equipment Capital Cost $0 $1,000,000 $15,788,530 $14,747,608 $136,800,000

Capital Recovery Factor N/A 0.09513 0.09513 0.0 9513 0.09513

Annual Capital Recovery Costs $0 $95,130 $1,501,963 $1,402,940 $13,013,784

Annual O&M Costs $0 $0 $414,076 $1,882,074 $2,668,918

Annual Cost of Control $0 $95,130 $1,916,039 $3,285,014 $15,682,702

Table 10 : Naughton Unit 3 Environmental Costs Existing

LNB Tuning

Existing LNB Existing LNB

and SNCR Existing LNB

with ROFA Existing LNB

and SCR

NO

x Emission Rate (lb/MMBtu) 0.45 0.37 0.30 0.28 0.07

Annual NO

x Emission (tpy) ( a ) 6,563 5,397 4,376 4,084 1,021

Annual NO

x Reduction (tpy) ) N/A 1,167 2,188 2,480 5,542

Annual Cost of Control $0 $95,130 $1,916,039 $3,285,014 $15,682,702

Cost per ton of Reduction N/A $82 $876 $1,325 $2,830

Incremental Cost per ton of Reduction N/A $1,783 $4,688 $4,049 $1,783

( a) Annual emissions based on individ ual heat input rate of 3

, 70 0 MMBtu/hr for 7,884 hours of operation per year.PacifiCorp Naughton Plant

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The cost effectiveness and incremental cost effectiveness of the four proposed BART technologies for

NO

x are all reasonable. PacifiCorp modeled the range of anticipated visibi lity improvement from the

company

- proposed BART controls for Units 1 and 2 by modeling LNB with advanced OFA and LNB

with advanced OFA and SCR

. PacifiCorp modeled the range of anticipated visibility improvement from the company

- proposed BART controls for Unit 3 by modeling tuning the existing LNB and OFA and tuning the existing LNB and OFA and installing SCR

. While the installation of SNCR and ROFA were not individually evaluated in Step 5: Evaluate visibility impact, the anticipated degree of visibility improvement from applying either control lies within the modeled range of visibility impacts.

The final step in the NO

x BART determination process for Naughton Units 1

- 3 , Step 5: Evaluate visibility impacts, is addressed in a comprehensive visibility anal ysis covering all three visibility impairing pollutants. The visibility analysis follows Steps 1

- 4 for SO 2 emissions in this application analysis. Tables

2 8

- 30 , on pages 3 7

- 3 9 , list the modeled control scenarios and associated emission r at es.

PM 10 : IDEN TIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Naughton Units 1 and 2 are currently equipped with mechanical dust collectors and electrostatic precipitators to control PM emissions from the boilers to 0.056 lb/MMBtu and 0.064 lb/MMBtu, respectively. Unit 3 is equipped with an ESP using FGC to control PM emission to 0. 0 94 lb/MMBtu . As discussed below in more detail, ESPs control PM/PM 10 from the flue gas stream by creating a strong

electro

- magnetic field in which fly ash particles gain electric charge. T hr ee PM control technologies were analyzed for application on the three Naughton units: fabric filters or baghouses, ESPs, and flue gas conditioning.

1. Fabric filters (FF)

– FF are woven pieces of material that collect particles with sizes ranging from

submic ron to several hundred microns in diameter at efficiencies generally in excess of 99%. The layer of dust trapped on the surface of the fabric, commonly referred to as dust cake, is primarily responsible for such high efficiency. Joined pores within the c ake act as barriers to trap particulate matter too large to flow through the pores as it travels through the cake. Limitations are imposed by the temperature and corrosivity of the gas and by adhesive properties of the particles. Most of the energy used to operate the system results from pressure drop across the bags and associated hardware and ducting.

2. Electrostatic precipitators

– ESPs use electrical forces (charge) to move particulate matter out the gas stream onto collection plates. The particles ar e given an electrical charge by directing the gas stream through a corona, or region of gaseous ion flow. The charged particles are acted upon by an induced electrical field from high voltage electrodes in the gas flow that forces them to the

walls or col lection plates. Once the particles couple with the collection plates, they must be

removed without re

- entraining them into the gas stream. In dry ESP applications, this is usually accomplished by physically knocking them loose from the plates and into a hopper for disposal. Wet ESPs use water to wash the particles from the collector plates into a sump. The efficiency of an ESP is primarily determined by the resistivity of the particle, which is dependent on chemical composition, and also by the ability to clean the collector plates without reintroducing the particles back into the flue gas stream.PacifiCorp Naughton Plant

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3. Flue Gas Conditioning (FGC)

– Injecting a conditioning medium, typically SO 3 , into the flue gas can lower the resistivity of the fly ash, improving the par ticles‟ ability to gain an electric charge. If the material is injected upstream of an ESP the flue gas particles more readily accept charge from the corona and are drawn to the collection plates. Adding FGC can account for large improvements in PM colle ction efficiency for existing ESPs that are constrained by space and flue gas residence time.

PM 10 : ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

PacifiCorp did not eliminate any of the three control technologies listed above as technically infeasible.

Pacif iCorp analyzed the impact of installing FGC using the existing ESPs and installing a polishing fabric filter downstream of the existing ESPs on Naughton Units 1 and 2

. PacifiCorp analyzed the impact of installing a full

- scale fabric filter on Unit 3.

PM 1 0 : EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

The Division considers the control effectiveness of a proposed control technology to be equivalent to the

BART

- determined permit limit. The limit is based on continuous compliance when the contr ol equipment is well maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions. In order to demonstrate continuous compliance with the permit limit it is important to consider that even well maintain ed and operated equipment will have some emissions variability. Complex emission control equipment, such as hot

- side electrostatic precipitators, generally have inherent variability that must be considered when establishing the limit. Otherwise, the sour ce will be out of compliance even though the equipment is operated and maintained as well as possible.

Naughton Units 1 and 2 have existing ESPs and rather than evaluate costs of replacing them, PacifiCorp evaluated additional controls to improve the PM 10 removal efficiency. An ESP is an effective PM control device, as the existing units are already capable of controlling PM 10 emissions to 0.05 6 lb/MMBtu, 0. 06 4 lb/MMBtu, and 0.0 94 lb/MMBtu for Units 1, 2, and 3, respectively. The technology continually

i mproves and is commonly proposed for consideration in BACT analyses to control particulate emissions from new PC boilers. Rather than demolishing the existing ESP and constructing an entirely new PM control device, PacifiCorp recognized the cost benefit o f keeping the existing ESP and augmenting the control. Installing FGC on Units 1 and 2 can improve the PM removal efficiencies on the existing ESPs

down to 0.0 4 0 lb/MMBtu. In addition to maintaining the existing ESPs, a polishing fabric filter can be

ins talled downstream of the existing ESPs. PacifiCorp proposed the use of Compact Hybrid Particulate Collector (COHPAC) licensed by Electric Power Research Institute (EPRI). The COHPAC unit is

smaller than a full

- scale fabric filter and has a higher air

- to

- cloth ratio (7 to 9:1), compared to a full

- size pulse jet fabric filter (3.5 to 4:1). COHPAC is effective at controlling particulates not captured by the primary PM control device, but is not designed to treat high PM concentrations in the entire flue gas stream immediately downstream of the boiler. The existing ESP must remain in service for the COHPAC fabric filter to effectively reduce PM/PM 10 emissions. PacifiCorp estimates the application of the COHPAC unit in addition to using FGC with the existing ESPs can reduce emissions an additional 63 % resulting in a PM emission rate of 0.015 lb/MMBtu. Demolishing the existing ESPs and i nstalling a new

full

- scale fabric filter on U nits 1 and 2 is anticipated to control emissions down to the same PM emission

l evel, 0.015 lb/MMBtu, as installing a polishing fabric filter downstream of the existing ESP.PacifiCorp Naughton Plant

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Naughton Unit 3 is currently equipped with an ESP and FGC system. PacifiCorp analyzed the impact of upgrading the existing FGC and resulting impact of install ing a new full

- scale fabric filter. PacifiCorp‟s proposed emission rates for each technology as applied to Naughton Units 1

- 3 are shown in Table 11

.

Table 11 : PM 10 Emission Rates Per Boiler

Control Technology Resulting PM 10 Emission Rate (lb/MMBtu)

Exi sting ESP 0.0 56, 0.064, 0.0 94 (a)

Existing ESP with FGC 0.0 4 0

Existing ESP and New Polishing Fabric Filter (b) 0.015

Full

- scale Fabric Filter (c) 0.015

(a) Current achievable PM 10 emissions from Unit 1, 2, and 3, respectively.

( b ) Applied to Naughton U nits 1 and 2.

( c ) Applied to Naughton Unit 3.

PM 10 : EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the energy impact of installing COHPAC on U nits 1 and 2 . The pressure drop created by the fabric filter and associated ductwork requires addit ional energy from the existing draft fan,

which will have to be upgraded. PacifiCorp calculated the additional energy costs based on a 90 percent annual plant capacity factor. The installation of a COHPAC fabric filter would require approximately 1.0

MW of power, equating to an annual power usage of approximately 8,000 M W

- hr for Unit 1 and 1.4 MW of power, equal to an annual power usage of approximately 10,900 MW

- hr for Unit 2 . Installing a full

scale fabric filter on Unit 3 would require approximately 2

. 1 MW of power, equating to an annual power usage of approximately 16,240 MW

- hr.

Installing FGC on Units 1 and 2 will require a minimal amount of additional power , about 100 kW which equates to an annual power consumption of 400 kW

- hr

. Upgrading the exis ting ESP on Unit 3 is not anticipated to require additional power.

PacifiCorp evaluated the environmental impacts associated with the proposed installati on of FGC and COHPAC on Units 1and 2, and did not anticipate negative environmental impacts from the a ddition of either of these PM control technologies. Upgrading the existing FGC and installing a new full

- scale

fabric filter on Unit 3 are not anticipated to have significant negative environmental impacts.

PacifiCorp anticipates operating Naughton U nits 1

- 3 indefinitely and did not include life extension costs in the economic analysis. A standard control life of 20 years was used to calculate the capital recovery factor. The annual cost to control was determined using a capital recovery factor based on a 7.1% interest rate. PacifiCorp labor and service costs were used to calculate the annual operating and maintenance costs. Annual power costs, including a cost escalation factor, associated with the operation of pollution

controls were included.PacifiCorp Naughton Plant

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- 6042 BART Application Analysis Page 19

Se veral different metrics can be considered when evaluating the cost

- benefit relationships of different emission control technologies. In 40 CFR part 51 Appendix Y two metrics are specifically mentioned:

cost effectiveness and incremental cost effectiveness . Through the application of BACT, the Division has extensive experience using cost effectiveness (i.e., dollars per ton of pollutant removed) to evaluate different control technologies. Incremental cost effectiveness is also used extensively by the Divi sion when comparing emission controls under the BACT process. While the BART and the BACT processes are not necessarily equivalent, control determinations from either process are based on cost effectiveness

and incremental cost effectiveness and are indic ative of the economic costs to control emissions. In addition to providing cost effectiveness and incremental cost effectiveness results, PacifiCorp provided cost information in terms of cost of applying emission controls and the level of visibility impro vement achieved (i.e., dollars per deciviews). While this metric can illustrate the control cost and visibility improvement differences between control options, it is not commonly used to assess the overall effectiveness of pollution control equipment. W hen performing the presumptive BART limits analyses

for NO

x and SO 2 , EPA addressed cost effectiveness and incremental cost effectiveness separate from visibility improvement. The dollars per deciview metric was not used to compare control options.

Visibi lity improvements from the application of the analyzed control measures used to establish presumptive levels were addressed in a separate visibility analysis. As discussed in the comprehensive visibility analysis presented later in this analysis as Step 5 : Evaluate visibility impacts, the Division evaluated the amount of visibility improvement gained in relation to each proposed emission control technology. The Division considered capital cost, annual cost, cost effectiveness, and incremental cost

effecti veness in the evaluation of each proposed PM emission control. Economic and environmental

costs for additional PM control on Naughton Units 1

- 3 are summarized in the following tables

Table 1 2 : Naughton Unit 1 Economic Costs

Cost Existing

ESP Existing ES P With

Flue Gas Conditioning Existing ESP With

New Polishing Fabric Filter

Control Equipment Capital Cost $0 $1,298,352 $29,798,898

Capital Recovery Factor N/A 0.09513 0.09513

Annual Capital Recovery Costs $0 $123,512 $2,834,769

Annual O&M Costs $0 $ 77,319 $601,825

Annual Cost of Control $0 $200,831 $3,436,594PacifiCorp Naughton Plant

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Table 1 3 : Naughton Unit 1 Environmental Costs Existing

ESP Existing ESP With

Flue Gas Conditioning Existing ESP With

New Polishing Fabric Filter

PM 10 Emission Rate (lb/MMBtu) 0.056 0.040 0.015

Annual PM 10 Emission (tpy) (a) 408 292 109

Annual PM 10 Reduction (tpy) N/A 117 299

Annual Cost of Control $0 $200,831 $3,436,594

Cost per ton of Reduction N/A $1,721 $11,494 Incremental Cost per ton of

Reduction N/A $1,721 $17,748

(a) Annual emissions based on unit heat input rate of 1

, 850 MMBtu/hr and 7,884 hours of operation per year.

Table 1 4 : Naughton Unit 2 Economic Costs

Cost Existing

ESP Existing ESP With

Flue Gas Conditioning Existing ESP With

New Polishing Fabric Filte r
Control Equipment Capital Cost $0 $1,298,352 $34,898,710

Capital Recovery Factor N/A 0.09513 0.09513

Annual Capital Recovery Costs $0 $123,512 $3,319,914

Annual O&M Costs $0 $91,904 $781,791

Annual Cost of Control $0 $215,416 $4,101,705

Table 1 5 : Naughton Unit 2 Environmental Costs Existing

ESP Existing ESP With

Flue Gas Conditioning Existing ESP With

New Polishing Fabric Filter

PM 10 Emission Rate (lb/MMBtu) 0.064 0.040 0.015

Annual PM 10 Emission (tpy) (a) 605 378 142

Annual PM 10 Reduction ( tpy) N/A 227 464

Annual Cost of Control $0 $215,416 $4,101,705

Cost per ton of Reduction N/A $949 $8,848 Incremental Cost per ton of

Reduction N/A $949 $16,431

(a) Annual emissions based on unit heat input rate of 2,4 00 MMBtu/hr and 7,884 hours of oper ation per year.PacifiCorp Naughton Plant

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Table 1 6 : Naughton Unit 3 Economic Costs

Cost Existing

ESP Existing ESP With

Flue Gas Conditioning New Full

- scale

Fabric Filter

Control Equipment Capital Cost $0 $13,299,508 $121,000,000

Capital Recovery Factor N/A 0.09513 0.0951 3

Annual Capital Recovery Costs $0 $1,265,182 $11,510,730

Annual O&M Costs $0 $0 $1,120,813

Annual Cost of Control $0 $1,265,182 $12,631,543

Table 1 7 : Naughton Unit 3 Environmental Costs Existing

ESP Existing ESP With

Flue Gas Conditioning Ne w Full

- scale

Fabric Filter

PM 10 Emission Rate (lb/MMBtu) 0.094 0.040 0.015

Annual PM 10 Emission (tpy) (a) 1,371 583 219

Annual PM 10 Reduction (tpy) N/A 788 1,152

Annual Cost of Control $0 $1,265,182 $12,631,543

Cost per ton of Reduction N/A $1,606 $10 ,963 Incremental Cost per ton of

Reduction N/A $1,606 $31,172

(a) Annual emissions based on unit heat input rate of 3

, 7 00 MMBtu/hr and 7,884 hours of operation per year.

The cost effectiveness and incremental cost effectiveness of applying a new polish ing fabric filter to Units

1 and 2 are not reasonable. The cost effectiveness and incremental cost effectiveness of applying a new

full

- scale fabric filter to Unit 3 are also not reasonable

. However, the control was included in the final step in the PM/P M 10 BART determination process for Naughton Units 1

- 3 , Step 5: Evaluate visibility impacts, which is addressed in a comprehensive visibility analysis covering all three visibility impairing pollutants and associated control options. The visibility analysi s follows Steps 1

- 4 for SO 2 emissions in this application analysis. Tables 28

- 30, on pages 3 7

- 3 9 , list the modeled control scenarios and associated

emission r at es.

SO 2 : IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

PacifiCorp reviewed a broad range o f informative sources, including EPA‟s RACT/BACT/LAER clearinghouse, in an effort to identify applicable SO 2 emission control technologies for Naughton Units 1

- 3 . Based on the results of this review, PacifiCorp proposed wet flue gas desulfurization (WFGD) and dry flue gas desulfurization (DFGD) as potential retrofit technologies to reduced SO 2 emissions.PacifiCorp Naughton Plant

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1. Wet FGD

– SO 2 is removed through absorption by mass transfer as soluble SO 2 in the exhaust gas

mixture is dissolved in an alkaline water solvent that has low volatility under process conditions.

SO 2 diffuses from the gas into the scrubber water when the liquid contains less than the equilibrium concentration of the gaseous SO 2 . The rate of SO 2 mass transfer between the two phases is largely dependent on the surface area exposed and the time of contact. A properly designed wet scrubber or gas absorber will provide sufficient contact between the gas and the liquid solvent to allow diffusion of SO 2 . Once the SO 2 enters the alkaline water phase, it will form a weak acid and react with the alkaline component dissolved in the scrubber water to form a sulfate (SO 4 ) or sulfite (SO 3 ). The acid/alkali chemical reaction prevents the SO 2 from diffusing back into the flue gas stream. When the alkaline scrubber w ater is saturated with sulfur compounds, it can be converted to a wet gypsum by

- product that may be sold. SO 2 removal efficiencies for wet scrubbers can be as high as 99%.

2. Dry FGD

– Dry scrubbers are similar to sorbent injection systems in that both syst ems introduce media directly into the flue gas stream, however the addition of the dry scrubber vessel provides greater contact area for adsorption and enhances chemical reactivity. A spray dryer dry scrubber sprays an atomized alkaline slurry into the fl ue gas upstream of particulate control system, often a fabric filter. Water in the slurry evaporates, hydrolizing the SO 2 into a weak acid, which reacts with the alkali to form a sulfate or sulfite. The resulting dry product is captured in the particulat e control and physically moved from the exhaust gas into a storage bin. The dry by

- product may be dissolved back into the lime slurry or dried and sold as a gypsum by

- product. Spray dryer dry scrubbers typically require lower capital cost than a wet scru bber. They also require less flue gas

after

- treatment. When exhaust gas leaves the wet scrubber, it is at or near saturation. A wet scrubber can lower exhaust gas temperatures down into a temperature range of 110 to 140 F, which may lead to corrosive co ndensation in the exhaust stack. A spray dryer dry scrubber does not enhance stack corrosion like a wet scrubber because it will not saturate the exhaust gas or significantly lower the gas temperature. Removal efficiencies for spray dryer dry scrubbers c an range from 70% to 95%.

SO 2 : ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

PacifiCorp did not eliminate either of the two control technologies listed above as technically infeasible. PacifiCorp analyzed the impact of installing dry FGD using the existing E SP, installing dry FGD using a polishing fabric filter, and installing wet FGD using the existing ESP on U nits 1 and 2. Upgrading the existing wet waste sodium liquor FGD system with the existing ESP and upgrading the existing wet FGD including switching to a soda ash reagent with the existing ESP were two SO 2 control options analyzed by PacifiCorp for Unit 3.

SO 2 : EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES

The Division considers the control effectiveness of a proposed control technology to be equivalent to the

BART

- determined permit limit. The limit is based on continuous compliance when the control equipment is well maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions. In order to demonstrate continuous compliance with the permit limit it is important to consider that even well maintained and operated equipment will have some emissions variability. Complex emission control equipment, such as wet FGD, generally have inherent var iability that must be considered when establishing the limit. Otherwise, the source will be out of compliance even though the equipment is operated and maintained as well as possible.PacifiCorp Naughton Plant

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Naughton Units 1 and 2 currently achieve emission rates of 1.20 lb/MMBt u. Both low sulfur coal, 0.58% sulfur by weight, and high sulfur coal, 1.02% by weight, are used to fuel the boilers in the Naughton

units. Installing a new dry FGD system and utilizing the existing ESP on Naughton Units 1 and 2 may reduce uncontrolled S O 2 emissions from each unit by 85% . R esulting SO 2 emission rates for Units 1 and

2 would be 0. 18 lb/MMBtu, based on an average coal sulfur content of 0.58% by weight , and 0.41 lb/MMBtu, based on an average coal sulfur content of 1.02% by weight. Replacin g the existing ESP with

a new full

- scale fabric filter will increase the SO 2 removal efficiency to 87.5%. SO 2 emission rates for Units 1 and 2 from the new fabric filter would be 0.15 lb/MMBtu, based on an average coal sulfur content of 0.58% by weight , a nd 0.21 lb/MMBtu, based on an average coal sulfur content of 1.02% by weight.

As mentioned earlier in this analysis, BART p resumptive SO 2 levels do not apply to Naughton. However, PacifiCorp used the presumptive SO 2 levels for uncontrolled units

, 95% emi ssions reduction or 0.15

lb/MMBtu , as a reference for comparison. PacifiCorp does not anticipate achieving presumptive SO 2 emission levels using dry FGD. The application of wet FGD on Units 1 and 2 is anticipated to lower SO 2 emissions to 0.10 lb/MMBtu, based on an average coal sulfur content of 0.58% by weight , and 0.15 lb/MMBtu, based on an average coal sulfur content of 1.02% by weight, which meet presumptive SO 2 l evels

.

The existing wet FGD system on Naughton Unit 3 reduce s emissions by 83% to achiev e a SO 2 emissions

rate of 0.50 lb/MMBtu when burning high sulfur coal , 1.02% by weight

. Wet FGD is a state

- of

- the

- art
SO 2 emissions control technology and continually improves over time

. PacifiCorp evaluated potential changes to the existing wet FGD syst ems to improve the SO 2 removal efficiencies. I mproving inlet gas distribution, adding a second tray to improve gas/liquid contact, and upgrading the reagent and waste solids systems are projected to reduce emissions by 90% to achieve an emission rate of a pproximately

0.21 lb / MMBtu. Switching to a refined soda ash reagent in the upgraded wet FGD system is anticipated

to reduce uncontrolled emission s by 95%

, resulting in a SO 2 emission rate of 0.10 lb/ MMBtu. PacifiCorp‟s proposed emission rates for each SO 2 emission reduction technology applied to Naughton

Units 1

- 3 are shown in Table 1 8

.

Table 1 8 : SO 2 Emission Rates Per Boiler (a)

Control Technology Unit 1

SO 2 Emission Rate (lb/MMBtu) Unit 2

SO 2 Emission Rate (lb/MMBtu) Unit 3

SO 2 Emission Rate (lb/MM Btu)

Existing Uncontrolled 1.2 1.2

--

Existing Wet FGD

-- -- 0.50

New Dry FGD with Existing ESP 0.41 0.41

--

New Dry FGD with Polishing Fabric Filter 0. 21 0. 21

--

New Wet FGD with Existing ESP 0.15 0.15

--

Upgraded Wet FGD with Waste Liquor

-- -- 0.2 1

Upgraded Wet FGD with Soda Ash Reagent

-- -- 0.10

(a) SO 2 emissions based on an average coal sulfur content of 1.02% by weight.PacifiCorp Naughton Plant

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SO 2 : EVALUATE IMPACTS AND DOCUMENT RESULTS

PacifiCorp evaluated the energy impacts of installing both dry FGD and wet FGD systems on Units 1 and 2. PacifiCorp noted that dry FGD systems using the existing ESP require the least amount of power. A dry FGD system using the existing ESP installed on Naughton Units 1 and 2 would require approximately 1.6 MW and 2.2 MW of power

, respectively . Wet FGD would require approximately 2.4 MW and 3.3 MW of power for Units 1 and 2 , respectively. Based on an annual ope r ating factor of 90%, the cost savings of using dry FGD on Units 1 and 2 would equate to approximately 5

, 9 00 MW

- hr and 8

, 3 00 MW

hr, respectively.

PacifiCorp estimates that upgrading the existing wet sodium FGD system on Naughton Unit 3 would require approximately 330 kW of additional power. Using a 90% annual operating factor, the annual power cost is 2,602 MW

- hr.

There ar e no anticipated environmental impacts from upgrading the existing wet sodium FGD system on Naughton Unit 3 except for an incremental addition to scrubber waste disposal and makeup water requirement. R ecycling the waste liquor into the scrubber would save on disposal of these materials and

conserve resources.

PacifiCorp compared the environmental impacts of dry FGD versus wet FGD technology. PacifiCorp concluded that dry FGD has five significant environmental advantages over wet FGD. These advantages

ar e taken directly from PacifiCorp‟s environmental analyses for SO 2 controls on Naughton Units 1 and 2

and listed below.

Sulfuric Acid Mist Sulfur trioxide (SO 3 ) in the flue gas, which condenses to liquid sulfuric acid at temperatures below the acid dew po int, is removed efficiently with a lime spray dryer system. Wet scrubbers capture less than 40 to 60 percent of SO 3 and may require the addition of a wet electrostatic precipitator (ESP) or hydrated lime injection when medium to high sulfur coal is

burned in a unit to remove the balance of SO 3 . Otherwise, the emission of sulfuric acid mist, if above a threshold value, may result in a visible plume after the vapor plume dissipates.

Plume Buoyancy Flue gas following a dry FGD system is not saturated with water (gas temperature 30°F to 50°F above dew point), which reduces or eliminates a visible moisture plume. Wet FGD scrubbers produce flue gas saturated with water, which would require a gas

- gas heat exchanger to reheat the flue gas if it were to operate as a dry stack. Because of the high capital and operating costs associated with heating the flue gas, all recent wet FGD systems in the United States have used wet stack operation.

Liquid Waste Disposal There is no liquid waste from a dry FGD system. H owever, wet FGD systems produce a wastewater blowdown stream that must be treated to limit chloride buildup in the absorber scrubbing loop. In some cases, a wastewater treatment plant must be installed to treat the liquid waste prior to disposal. The was tewater treatment plant would produce a small volume of solid waste, which may be contaminated with toxic metals (including mercury), requiring proper disposal.PacifiCorp Naughton Plant

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Solid Waste Disposal The creation of a wet sludge from the wet FGD process creates a soli d waste handling and disposal challenge. This sludge must be handled properly to prevent groundwater contamination. Wet FGD systems can produce saleable gypsum if a gypsum market is available, reducing the quantity of solid waste from the power plant to be disposed.

Makeup Water Requirements Dry FGD has advantages over a wet scrubber, producing a dry waste material and requiring less makeup water in the absorber. Given that water is a valuable commodity in Wyoming, the reduced water consumption required for dry FGD is major advantage for this technology.

PacifiCorp anticipates operating Naughton U nits 1

- 3 indefinitely and did not include life extension costs in the economic analysis. A standard control life of 20 years was used to calculate the capital recovery factor. The annual cost to control was determined using a capital recovery factor based on a 7.1% interest rate. PacifiCorp labor and service costs were used to calculate the annual operating and maintenance costs. Annual power costs, including a cost escalation factor, associated with the operation of pollution

controls were included.

Several different metrics can be considered when evaluating the cost

- benefit relationships of different emission control technologies. In 40 CFR part 51 Appendi x Y two metrics are specifically mentioned: cost effectiveness and incremental cost effectiveness. Through the application of BACT, the Division has extensive experience using cost effectiveness (i.e., dollars per ton of pollutant removed) to evaluate

dif ferent control technologies. Incremental cost effectiveness is also used extensively by the Division when comparing emission controls under the BACT process. While the BART and the BACT processes are not necessarily equivalent, control determinations fro m either process are based on cost effectiveness

and incremental cost effectiveness and are indicative of the economic costs to control emissions. In addition to providing cost effectiveness and incremental cost effectiveness results, PacifiCorp provided cost information in terms of cost of applying emission controls and the level of visibility improvement achieved (i.e., dollars per deciviews). While this metric can illustrate the control cost and visibility improvement differences between control option s, it is not commonly used to assess the overall effectiveness of pollution control equipment. When performing the presumptive BART l imits analyses

for NO

x and SO 2 , EPA addressed cost effectiveness and incremental cost effectiveness separate from

visibili ty improvement. The dollars per deciview metric was not used to compare control options. Visibility improvements from the application of the analyzed control measures used to establish presumptive levels were addressed in a separate visibility analysis. The Division considered capital cost, annual cost, cost effectiveness, and incremental cost effectiveness in the evaluation of each proposed SO 2 emission control. Economic and environmental costs for additional controls on Naughton Units 1

- 3 are summariz ed in the following tables.PacifiCorp Naughton Plant

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Table 1 9 : Naughton Unit 1 Economic Costs

Cost Existing Dry FGD with Existing ESP Dry FGD with

Polishing Fabric Filter Wet FGD with

Existing ESP

Control Equipment Capital Cost $0 $64,297,623 $108,995,970 $89,400,0 00

Capital Recovery Factor N/A 0.09513 0.09513 0.09513

Annual Capital Recovery Costs $0 $6,116,633 $10,368,787 $8,504,622

Annual O&M Costs $0 $3,226,295 $4,006,095 $4,563,874

Annual Cost of Control $0 $9,342,928 $14,374,882 $13,068,496

T abl e 20 : Naughton Unit 1 Environmental Costs

Existing Dry FGD with

Existing ESP Dry FGD with

Polishing Fabric Filter Wet FGD with Existing ESP

SO 2 Emission Rate (lb/MMBtu) 1.20 0.41 0.15 0.15

Annual SO 2 Emission (tpy) (a) 8,751 6 2,990 1,094 1,094

Annual SO 2 Reduction (tpy) N/A 5,761 7,657 7,657

Annual Cost of Control $0 $9,342,928 $14,374,882 $13,068,496

Cost per ton of Reduction N/A $1,622 $1,877 $1,707 Incremental Cost per ton of

Reduction N/A $1,622 $2,654 $1,965 (b)

(a) Annual emissions based on an average coal sulfur content of 1.02%, a heat input rate of 1

, 850 MMBtu/hr , and 7, 884 hours of operation per year

. (b) Incremental cost from installing dry FGD with a polishing fabric filter cannot be calculated since the reduced tons of SO 2 are anticipa ted to be the same. Therefore, the i ncremental cost from installing dry FGD with the existing ESP was calculated.

Table 2 1 : Naughton Unit 2 Economic Costs

Cost Existing Dry FGD with Existing ESP Dry FGD with

Polishing Fabric Filter Wet FGD with

Existin g ESP

Control Equipment Capital Cost $0 $88,896,713 $141,244,778 $117,400,000

Capital Recovery Factor N/A 0.09513 0.09513 0.09513

Annual Capital Recovery Costs $0 $8,456,744 $13,436,616 $11,168,262

Annual O&M Costs $0 $4,251,261 $5,259,175 $5,7 21,158

Annual Cost of Control $0 $12,708,005 $18,695,791 $16,889,420PacifiCorp Naughton Plant

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T able 2 2 : Naughton Unit 2 Environmental Costs

Existing Dry FGD with

Existing ESP Dry FGD with

Polishing Fabric Filter Wet FGD with Existing ESP

SO 2 Emission Rate (lb/MMBtu) 1 .2 0 0.41 0.15 0.15

Annual SO 2 Emission (tpy) (a) 11 ,3 53 3,879 1,419 1,419

Annual SO 2 Reduction (tpy) N/A 7,474 9,934 9,934

Annual Cost of Control $0 $12,708,005 $18,695,791 $16,889,420

Cost per ton of Reduction N/A $1,700 $1,882 $1,700

Incremental C ost per ton of

Reduction N/A $1,700 $2,434 $1,700 (b)

( a) Annual emissions based on an average coal sulfur content of 1.02%, a heat input rate of 2

, 400 MMBtu/hr , and 7, 884 hours of operation per year.

(b) Incremental cost from installing dry FGD with a po lishing fabric filter cannot be calculated since the reduced tons of SO 2 are anticipated to be the same. Therefore, the i ncremental cost from installing dry FGD with the existing ESP was calculated.

Table 2 3 : Naughton Unit 3 Economic Costs

Cost Existing

Wet FGD Upgraded

Wet FGD with Waste Liquor Upgraded

Wet FGD with Soda Ash Reagent

Control Equipment Capital Cost $0 $6,000,000 $27,798,972

Capital Recovery Factor N/A 0.09513 0.09513

Annual Capital Recovery Costs $0 $570,780 $2,644,516

Annual O&M Costs $0 $615,513 $1,656,269

Annual Cost of Control $0 $1,186,293 $4,300,785

Table 2 4 : Naughton Unit 3 Environmental Costs

Existing

Wet FGD Upgrade

Wet FGD Using Waste Liquor Upgrading

Wet FGD Using Soda Ash Reagent

SO 2 Emission Rate (lb/M MBtu) 0. 50 0.21 0.15

Annual SO 2 Emission (tpy) (a) 7,293 3,063 2,188

Annual SO 2 Reduction (tpy) N/A 4,230 5,105

Annual Cost of Control $0 $1,186,293 $4,300,785

Cost per ton of Reduction N/A $280 $842

Incremental Cost per ton of Reduction N/A $280 $3,5 59

( a) Annual emissions based on an average coal sulfur content of 1.02%, a heat input rate of 3

, 700 MMBtu/hr , and 7, 884 hours of operation per year.PacifiCorp Naughton Plant

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The cost effectiveness and incremental cost effectiveness of the proposed wet FGD and dry FGD controls

fo r Units 1

– 3 are reasonable

. The final step in the SO 2 BART determination process for Naughton Units

1

- 3 , Step 5: Evaluate visibility impacts, is addressed in a comprehensive visibility analysis presented in the next section of this BART application anal ysis. The Division evaluated the amount of visibility improvement gained from the application of additional NO

x , PM/PM 10 , and SO 2 emission control technology in relation to all three visibility impairing pollutants. Tables 2 8

- 30, on pages 3 7

- 3 9 , list the

modeled control scenarios and associated emission r ate s.

VISIBILITY IMPROVEMENT DETERMINATION :

The fifth of five steps in a BART determination analysis, as required by 40 CFR part 51 Appendix Y, is

the determination of the degree of Class I area visibil ity improvement that would result from installation

of the various options for control technology. This factor was evaluated for the PacifiCorp Naughton facility by using an EPA

- approved dispersion modeling system (CALPUFF) to predict the change in

Class I area visibility. The Division had previously determined that the f acility was subject to BART based on the results of initial screening modeling that was conducted using current (baseline) emissions from the facility. The screening modeling, as well as m ore refined modeling conducted by the applicant

, is described in detail below.

Bridger Wilderness Area (WA) and Fitzpatrick WA in Wyoming are the closest Class I areas to the PacifiCorp Naughton facility, as shown in F igure 2 below. Bridger W A is loc ated approximately 140 kilometers (km) north east of the facility and Fitzpatrick WA is located approximately 1 6 5 km north east of the facility.

Only those Class I areas most likely to be impacted by the Naughton Power Plant sources were modeled,

as determi ned by source/Class I area locations, distances to each Class I area, and professional judgment considering meteorological and terrain factors. I t can be reasonably assumed that areas at greater

distance s and in directions of less frequent plume transport will experience lower impacts than those predicted for the modeled areas

.PacifiCorp Naughton Plant

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Figure 2 Naughton Power Plant and Class I AreasPacifiCorp Naughton Plant

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SCREENING MODELING

To determine if the PacifiCorp Naughton facility would be subject to BART, the Division conducted CALPUFF modeling using three years of meteorological data. These data, from 1995

- 1996 and 2001, consisted of surface and upper

- air observations and gridded output from the Mesoscale Model ( MM5 )

. Resolution of the MM5 data was 36

- km for all thre e of the modeled years. Potential emissions for current operation from the three c oal

- fired boilers at the Naughton plant were input to the model.

Results of the modeling showed that the 98 th percentile value for the change in visibility ( in units of de lta deciview [Δdv]) was above 0.5 Δ dv for Bridger W A and Fitzpatrick WA for all three years of meteorolog y . A s defined in EPA‟s final BART rule, a predicted 98 th percentile impact equal to or greater

than 0.5 Δ dv fr om a given source indicates that the sou rce contributes to visibility impairment, and therefore is subject to BART. The results of the screening modeling are shown in the table below.

Table 2 5 : Results of the Class I Area Screening Modeling

Class I Area Maximum

Modeled Value (Δdv) 98 th

Perce ntile Value (Δdv)

1995 Bridger WA 5.984 3.119 Fitzpatrick WA 3.305 1.632

1996 Bridger WA 6.185 4.364 Fitzpatrick WA 5.253 2.378

2001 Bridger WA 7.331 4.277 Fitzpatrick WA 4.789 2.428

Δdv = delta deciview

WA = wilderness area

REFINED MODELING

Because of the results of the Division‟s screening modeling, PacifiCorp was required to conduct a refined BART analysis that included CALPUFF visibility modeling for the facility. The modeling approach followed the requirements described in the Division‟s BART modeling protocol, BART Air Modeling

Protocol

- Individual Source Visibility Assessments for BART Control Analyses (WDEQ

- AQD, September 2006).

CALPUFF System

Predicted visibility impacts from the PacifiCorp Naughton sources were determin ed with the EPA CALPUFF modeling system, which is the EPA

- preferred modeling system for long

- range transport. As described in the EPA Guideline on Air Quality Models (Appendix W of 40 CFR p art 51), long

- range transport is defined as modeling with source

- r eceptor distances greater than 50 km . Because all modeled

areas are located more than 50 km from the facility , the CALPUFF system was appropriate for use.PacifiCorp Naughton Plant

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The CALPUFF modeling system consists of a meteorological data pre

- processor (CALMET), an air dispe rsion model (CALPUFF), and post

- processor programs (POSTUTIL, CALSUM, CALPOST). The CALPUFF model was developed as a non

- steady

- state air quality modeling system for assessing the

effects of time

- and space

- varying meteorological conditions on pollutant t ransport, transformation, and

removal.

CALMET is a diagnostic wind model that develops hourly wind and temperature fields in a three

dimensional, gridded modeling domain. Meteorological inputs to CALMET can include surface and

upper

- air observations fro m multiple meteorological monitoring stations. Additionally, the CALMET model can utilize gridded analysis fields from various mesoscale models such as MM5 to better represent regional wind flows and complex terrain circulations. Associated two

- dimension al fields such as mixing height, land use, and surface roughness are included in the input to CALMET. The CALMET model allows the user to “weight” various terrain influence parameters in the vertical and horizontal directions by defining the radius of inf luence for surface and upper

- air stations.

CALPUFF is a multi

- layer, Lagrangian puff dispersion model. CALPUFF can be driven by the three

dimensional wind fields developed by the CALMET model (refined mode), or by data from a single surface and upper

- a ir station in a format consistent with the meteorological file s used to drive steady

- state dispersion models. All far

- field modeling assessments described here were completed using the

CALPUFF model in a refined mode.

CALSUM is a post

- processing program that can operate on multiple CALPUFF output files to combine the results for further post

- processing. POSTUTIL is a post

- processing program that processes

CALPUFF concentrations and wet/dry flux files . The POSTUTIL model operates on one or more output

da ta files from CALPUFF to sum, scale, and/or compute species derived from those that are modeled , and outputs selected species to a file for further post

- processing . C ALPOST is a post

- processing program that can read the CALPUFF (or POSTUTIL or CALSUM) out put files and calculate the impacts to visibility.

All of the refined CALPUFF modeling was conducted with the version of the CALPUFF system that was recognized as the EPA

- approved release at the time of the development of the Division‟s modeling

protoco l. Version designations of the key programs are listed in the table below.

Table 2 6 : Key Programs in CALPUFF System
Program Version Level

CALMET 5.53a 040716

CALPUFF 5.711a 040716

CALPOST 5.51 030709PacifiCorp Naughton Plant

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Meteorological Data Processing (CALMET)

As required by the Division‟s modeling protocol, the CALMET model was used to construct an initial

three

- dimensional windfield using data from the MM5 model . Surface and upper

- air data were input to CALMET to adjust the initial windfield, but because of the relative scarcity of wind observations in the modeling domain, the influence of the observations on the initial windfield was minimized . Because the MM5 data were afforded a high degree of influence on the CALMET windfields, the Division obtained

MM5 data at 12

- km resolution that spanned the years 2001

- 2003. Locations of the observations that were input to CALMET , including surface, upper

- air, and precipitation stations, are shown in the figure below. Default settings were used in the CALMET input f iles for most of the technical options. The following table lists the key user

- defined CALMET settings that were selected.

Table 2 7 : Key User

- Defined CALMET Settings

Variable Description Value

PMAP Map projection LCC

DGRIDKM Grid spacing (km) 4

NZ Number of layers 10

ZFACE Cell face heights (m) 0, 20, 40, 100, 140, 320, 580, 1020, 1480, 2220, 3 4 00

RMIN2 Minimum distance for extrapolation

- 1

IPROG Use gridded prognostic model output 14

RMAX 1 Maximum radius of influence (sur face

layer, km) 30

RMAX 2 Maximum radius of influence (layers

aloft, km) 50

TERRAD Radius of influence for terrain (km) 15

R1 Relative weighting of first guess wind field and observations (km) 5

R2 Relative weighting aloft (km) 25PacifiCorp Naughton Plant

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F igure 3 Observations Input to CALMETPacifiCorp Naughton Plan t

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CALPUFF Modeling Setup

To allow chemical transformations within CALPUFF using the recommended chemistry

mechanism (MESOPUFF II), the model required input of background ozone and ammonia

concentrations . For ozone, h ourly data collected from the following stations were used:

Rocky Mountain National Park (NP) , Colorado
Craters of the Moon National Monument, Idaho Highland, Utah Thunder Basin, Wyoming Yellowstone NP, Wyoming Centennial, Wyoming Pinedale, Wyoming

For a ny hour that was missing ozone data from all stations, a default value of 44 parts per billion (ppb) was used by the model as a substitute. For ammonia, a domain

- wide background value of 2 ppb was used.

Latitude and longitude coordinates for Class I ar ea d iscrete receptors were taken from the National Park Service ( NPS ) Class I Receptors database and converted to the appropriate

Lambert Conformal Conic coordinates. Figure s 4 and 5 show the receptor configuration s that

w ere used for Bridger WA and Fitzp atrick WA

. Receptor spacing for the modeled areas was approximately 1.3 km in the east

- west direction and approximately 1.8 km in the north

- south

direction.PacifiCorp Naughton Plant

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Figure 4 Receptors for Bridger WAPacifiCorp Naughton Plant

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Figure 5 Receptors for Fitzpatrick WA

C ALPUFF Inputs

– Baseline and Control Options

S ource release parameters and emissions for baseline and control options for each unit at the Naughton Plant are shown in the table s below

.PacifiCorp Naughton Plant

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Table 2 8 : CALPUFF Inputs for Naughton Unit 1PacifiCorp Naughton Plant

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Table 2 9 : CALPUFF Inputs for Naughton Unit 2PacifiCorp Naughton Plant

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Table 30 : CALPUFF Inputs for Naughton Unit 3PacifiCorp Naughton Plant

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V isibility Post

- Processing (CALPOST)

The changes in visibility were modeled usi ng Method 6 within the CALPOST post

- processor. Method 6 requires input of monthly relative humidity factors [f(RH)] for each Class I area. Monthly f(RH) factors that were used for Bridger WA and Fitzpatrick WA are shown in the table below.

Table 3 1 : Re lative Humidity Factors for CALPOST

Month Bridger WA

& Fitzpatrick

WA January 2.50

February 2.30

March 2.30

April 2.10

May 2.10

June 1.80

July 1.50

August 1.50

September 1.80

October 2.00

November 2.50

December 2.40

According to the final BART rule, n atural background conditions as a reference for determination of the

modeled Δdv change s hould be representative of the 20 percent best natural visibility days in a given

Class I area . EPA BART guidance provides the 20 percent best days deciview values for each Class I area on an annual basis, but does not provide the individual s pecies concentration data required for input

to CALPOST

.

S pecies concentrations corresponding to the 20 percent best days were calculated for each Class I area by scaling back the annual average (natural background) concentrations given in Table 2

- 1 of th e EPA

document Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule. A separate scaling factor was derived for each Class I area such that, when multiplied by the g uidance table annual concentrations, the 20% best days decivie w value s for that particular Class I area would be

calculated.

The scaling procedure is illustrated here for Bridger WA. From Appendix B in the EPA natural visibility guidance document, the deciview value for the 20 percent best days at Bridger WA is 1. 96 dv. To obtain the speciated background concentrations representative of the 20 percent best days, the deciview value (1.96 dv) was first converted to light extinction. The relationship between deciviews and light extinction is expressed as follows:

d v = 10 ln (b ext

/10) or b ext = 10 exp (dv/10)PacifiCorp Naughton Plant

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where: b ext = light extinction expressed in inverse megameters (Mm

- 1 ).

Using this relationship with the known deciview value of 1.96, one obtains a n equivalent light extinction

value of 12.17 Mm

- 1 . Next, the an nual average natural visibility concentrations were set equal to a total

extinction value of 12.17 Mm

- 1 . The relationship between total light extinction and the individual components of the light extinction is as follows:

b ext = (3)f(RH)[ammonium sulfate ] + (3)f(RH)[ammonium nitrate] + (0.6)[coarse mass] + (4)[organic carbon] + (1)[soil] + (10)[elemental carbon] + b ray

where: bracketed quantities represent background concentrations in μg/m 3

values in parenthesis represent scattering efficiencies
f(RH) is the relative humidity adjustment factor (applied to hygroscopic species only)

b ray is light extinction due to Rayleigh scattering (10 Mm

- 1 used for all Class I areas)

Substituting the annual average natural background concentrations, the average f(RH) fo r Bridger WA, and including a coefficient for scaling, one obtains:

12.17 = (3)(2.1)[0.12]X + (3)(2.1)[0.1]X + (0.6)[3.0]X + (4)[0.47]X + (1)[0.5]X + (10)[0.02]X + 10

In the equation above, X represents a scaling factor needed to convert the annual avera ge natural background concentrations to values representative of the 20 percent best days. Solving for X provides a

value of 0.376. Table 32 presents the annual average natural background concentrations, the calculated scaling factor, and the calculated background concentrations for the 20 percent best days for Bridger WA.



### Table 3 2 : Calculated Background Components for Bridger WA

Component Annual Average for

West Region 

### (μg/m 3 

### ) Calculated Scaling

Factor 20% Best Days for

Bridger WA 

### (μg/m 3 

### )

Ammonium Su lfate 0.12 0.376 0.045

Ammonium Nitrate 0.10 0.376 0.038 Organic Carbon 0.47 0.376 0.176

Elemental Carbon 0.02 0.376 0.008

Soil 0.50 0.376 0.188

Coarse Mass 3.00 0.376 1.127

The scaled aerosol concentrations were averaged for Bridger WA and Fitzpatr ick WA because of their geographical proximity and similar annual background visibility. The 20 percent best days aerosol

concentrations for the two Class I areas in question are listed in the table below.PacifiCorp Naughton Plant

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Table 3 3 : Natural Background Aerosol Concent rations (μg/m 3 )

Aerosol Component Fitzpatrick

WA & Bridger WA

Ammonium Sulfate 0 .045

Ammonium Nitrate 0 .038

Organic Carbon 0 .178

Elemental Carbon 0 .008

Soil 0 .189

Coarse Mass 1.136

Visibility Post

- Processing Results

The results of the visibility modeling for each of the three units for the baseline and control scenarios are shown in the table s below. For each scenario, the 98 th percentile Δdv results are reported along with the total number of days for which the predicted impacts exceeded 0.5 dv. Following the tables are figures that present the results graphically for baseline, the BART configuration proposed by PacifiCorp, and for the proposed BART configuration with the addition of SCR.PacifiCorp Naughton Plant

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Table 3 4 : CALPUFF Visibility Modeling Results: Unit 1

Class I Area 2001 2002 2003 3

- Year Average

98th

Percentile

Value (Δdv) No. of

Days > 0.5

Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv

Baseline

– Current Operations with ESP
Bridger WA 1 .777 48 1.763 41 1.797 45 1.779 45
Fitzpatrick WA 0.966 23 0.881 18 0.84 0 20 0.896 20

Post

- Control Scenario 1

– LNB with advanced OFA, Dry FGD, ESP with Flue Gas Conditioning
Bridger WA 0.644 14 0.741 14 0.694 16 0.693 1 5
Fitzpatrick WA 0.357 3 0.314 5 0.361 5 0.344 4

Post

- Control Scenario 2

– LNB with advanced OFA, Dry FGD, New Fabric Filter
Bridger WA 0.479 7 0.635 9 0.493 7 0.536 8
Fitzpatrick WA 0.235 2 0.205 2 0.266 3 0.235 2

Post

- Control Scenario 3

– LNB with advanced OFA and SCR, Dry FGD, New Fabric Filter
Bridger WA 0.217 1 0.274 1 0.234 3 0.242 2
Fitzpatrick WA 0.119 0 0.105 0 0.123 0 0.116 0

Post

- Control Scenario 4

– LNB with advanced OFA and SCR, Wet FGD, ESP with Sulfur Trioxide Injection, New Stack
Bridger WA 0.387 4 0.288 3 0.397 4 0.357 4
Fitzpatrick WA 0.153 1 0.108 1 0.135 0 0.132 1

Post

- Control Scenario A

– C ommitted Controls : LNB with advanced OFA, Wet FGD, ESP with Flue Gas Conditioning
Bridger WA 0.733 14 0.623 9 0.698 12 0.685 1 2
Fitzpatrick WA 0.32 0 3 0.221 2 0.28 0 2 0.2 74 2

Post

- Control Scenario B

– Committed Controls and SCR
Bridger WA 0.406 5 0.37 0 4 0.413 5 0.396 5
Fitzpatrick WA 0.175 1 0.131 1 0.168 0 0.158 1PacifiCorp Naughton Plant

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Table 3 5 : CALPUFF Visibility Modeling Results: Unit 2

Class I Area 2001 2002 2003 3

- Year Average

98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv

Baseline

– Current Operations with ESP
Bridger W A 2.127 61 1.86 0 56 2.087 55 2.025 57
Fitzpatrick WA 1.158 26 1.099 24 1.11 0 22 1.122 24

Post

- Control Scenario 1

– LNB with advanced OFA, Dry FGD, ESP with flue gas conditioning
Bridger WA 0.838 28 0.926 18 0.882 19 0.882 2 2
Fitzpatrick WA 0.462 6 0.41 3 5 0.448 6 0.441 6

Post

- Control Scenario 2

– LNB with advanced OFA, Dry FGD, New Fabric Filter
Bridger WA 0.642 14 0.745 11 0.614 12 0.667 12
Fitzpatrick WA 0.312 3 0.286 4 0.313 4 0.304 4

Post

- Control Scenario 3

– LNB with advanced OFA and SCR, Dry F GD, Fabric Filter
Bridger WA 0.284 2 0.321 3 0.291 3 0.299 3
Fitzpatrick WA 0.158 1 0.141 1 0.148 0 0.149 1

Post

- Control Scenario 4

– LNB with advanced OFA and SCR, Wet FGD, ESP

, New Stack
Bridger WA 0.482 7 0.354 4 0.526 8 0.454 6
Fitzpatrick WA 0.20 8 2 0.138 1 0.162 0 0.169 1

Post

- Control Scenario A

– Committed Controls: LNB with advanced OFA, Wet FGD, ESP with Flue Gas Conditioning
Bridger WA 0.944 20 0.757 14 0.921 15 0.874 16
Fitzpatrick WA 0.404 4 0.288 4 0.326 2 0.339 3

Post

- Control Scenario B

– C ommitted Controls and SCR
Bridger WA 0.544 10 0.45 0 7 0.555 9 0.516 9
Fitzpatrick WA 0.221 2 0.167 1 0.186 0 0.191 1PacifiCorp Naughton Plant

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Table 3 6 : CALPUFF Visibility Modeling Results: Unit 3

Class I Area 2001 2002 2003 3

- Year Average

98th

Percentile

Value (Δd v) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv 98th

Percentile

Value (Δdv) No. of

Days >

0.5 Δdv

Baseline

– Current Operations with Wet FGD and ESP
Bridger WA 1.978 66 1. 618 56 2.171 53 1.922 58
Fitzpatrick WA 1.126 24 0.893 21 0.871 21 0.963 22

Post

- Control Scenario 1

– Tuning Existing LNB with OFA, Wet FGD with Waste Liquor, Existing ESP
Bridger WA 1.413 12 1.175 32 1.555 39 1.381 2 8
Fitzpatrick WA 0.735 16 0.564 11 0.549 9 0.616 12

Post

- Control Scenario 2

– Tuning Existing LNB with OFA & SCR, Wet FGD with Waste Liquor, Enhanced ESP
Bridger WA 0.716 19 0.650 10 0.828 14 0.731 14
Fitzpatrick WA 0.371 4 0.290 3 0.260 1 0.307 3

Post

- Control Scenario 3

– Tuning Existi ng LNB with OFA and SCR, Wet FGD with Waste Liquor, Fabric Filter
Bridger WA 0.697 16 0.635 10 0.810 14 0.714 13
Fitzpatrick WA 0.363 4 0.279 3 0.253 1 0.298 3

Post

- Control Scenario 4

– Tuning Existing LNB with OFA and SCR, Wet FGD with Soda Ash, Fabric Filter
Bridger WA 0.553 12 0.494 7 0.662 11 0.570 10
Fitzpatrick WA 0.265 2 0.203 3 0.214 0 0.227 2

Post

- Control Scenario A

– Committed Controls: Tuning Existing LNB with OFA, Wet FGD, New Fabric Filter
Bridger WA 1.46 0 45 1.21 34 1.583 40 1.418 40

F itzpatrick WA 0.766 17 0.586 11 0.572 11 0.641 13

Post

- Control Scenario B

– Committed Controls and SCR
Bridger WA 0.71 0 17 0.65 0 10 0.83 0 14 0.730 1 4
Fitzpatrick WA 0.372 4 0.287 3 0.259 1 0.306 3PacifiCorp Naughton Plant

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Figure 6 Modeled BART Impacts: 98th Percentile (delta

- dv)PacifiCorp Naughton Plant

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Fi gure 7 Modeled BART Impacts: Number of Days > 0.5 delta

- dvPacifiCorp Naughton Power Plant

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BART CONCLUSIONS:

After considering (1) the costs of compliance, (2) the energy and non

- air quality environmental impacts of compliance, (3) any pollution equipment in use or in existe nce at the source, (4) the remaining useful life of the source, and (5) the degree of improvement in visibility (all five statutory factors) from each proposed control technology, the Division determined BART for each visibility impairing pollutant

emitted from the three units subject to BART at the Naughton Power Plant.

NO

x

LNB with advanced OFA is determined to be BART for Units 1 and 2 for NO

x based, in part, on the following conclusions:

1. LNB with advanced OFA on Units 1 and 2 was cost effective with a capital cost of $ 9

, 6 00,000 and $9,100,000 per unit , respectively. The average cost effectiveness, over a twenty year operational life , is $ 426 per ton of NO

x removed for Unit 1 and $357 per ton for Unit 2.

2. Combustion control using LNB with advanced OFA does not require non

- air quality environmental mitigation for the use of chemical reagents (i.e., ammonia or urea) and there is a minimal energy impact.

3. After careful consideration of the five statutory factors, especially the costs of compliance and the existing pollution control equipment, a NO

x control level of 0.26 lb/MMBtu on a 30

- day rolling average, above EPA‟s established presumptive limit of 0.15 lb/MMBtu for tangential

- fired boilers burning sub

- bituminous coal, though not applicable, is justified

.

4. Visibility impacts were addressed in a comprehensive visibility analysis covering all three visibility impairing pollutants and associated control options. The cumulative 3

- year averaged

98 th percentile visibility improvement from the baseline summed a cross both Class I areas

achieved with LNB with advanced OFA, wet FGD , and existing ESP with FGC (Post

- Control

Scenar io A) was 1. 716 Δdv from Unit 1 and 1.934 Δdv from Unit 2.

5. Annual NO

x emission reductions from baseline achieved by applying LNB with adva nced OFA

on Unit s 1 and 2 are 2,334 tons and 2,649 tons , respectively.

LNB with advanced OFA and SCR was not determined to be BART for Units 1 and 2 for NO

x based, in part, on the following conclusions:

1. The cost of compliance for installing SCR on each un it is significantly higher than LNB with

advanced OFA. Capital cost for SCR on Unit 1 is $94,600,000 and $115,900,000 for Unit 2.

Annual SCR O&M c osts for Unit 1 are $ 1

, 231

, 912 and $1,639,352 for Unit 2.

2. Additional non

- air quality environmental mitigati on is required for the use of chemical reagents.

3. Operation of LNB with advanced OFA and SCR is parasitic and requires an estimated 1.0 MW

from Unit 1 and 1.3 MW from Unit 2

.PacifiCorp Naughton Power Plant

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4. While visibility impacts were addressed in a cumulative analysis of all three po llutants, Post

Control Scenario B is directly comparable to Post

- Control Scenario A as the only difference is directly attributable to the installation of SCR. Subtracting the modeled 98 th percentile values from each other yield the incremental 98 th perce ntile visibility improvement from SCR. The

cumulative 3

- year averaged 98 th percentile visibility improvement from Post

- Control Scenario A

a cross both Class I areas achieved with Post

- Control Scenario B was 0. 405 Δdv from Unit 1 and

0.5 06 Δdv from Unit 2.

Tuning the existing LNB with OFA and installing SCR is determined to be BART for Unit 3 for NO

x based, in part, on the following conclusions:

1. The cost effectiveness of t uning the existing LNB with OFA and installing SCR on Unit 3 was reasonable at $2,830 per ton of NO

x removed. The incremental cost effectiveness when compared to e xisting LNB with ROFA was $1,783 per ton of NO

x and reasonable as well. Both the cost effectiveness and average cost effectiveness were based on a twenty year operational life for the proposed controls

.

2. The cumulative 3

- year averaged 98 th percentile visibility improvement from the baseline summed

across both Class I areas achieved by tuning the existing LNB with OFA, wet FGD and installing

a n ew full

- scale f

abric f ilter

, Post

- C ontrol Scenario A

, was 0.826 Δdv from Unit 3. Units 1 and 2 yielded notably higher visibility improvements from baseline, 1.716 Δdv and 1.934 Δdv

, respectively, u sing Post

- Control Scenario A which included new LNB with advanced OFA , but

not SCR.

3. Modeled 98 th percentile v isibility r esults from Unit 3 Post

- Control Scenario B are directly comparable to those from Post

- Control Scenario A

, as the only difference is directly attributable

to the installation of SCR. The cumulative 3

- year averaged 98 th percentile visibility improvement

acr oss the two Class I areas achieved by installing SCR on Unit 3 was 1. 023 Δdv , approximately

twice the 98 th percentile visibility improvement s , 0.405 Δdv from Unit 1 and 0.506 Δdv from

Unit 2

, using Post

- Control Scenario B which included installing SCR

.

4. The cumulative 3

- year averaged 98 th percentile visibility improvement from the baseline summed across both Class I areas achieved by tuning the existing LNB with OFA, SCR, wet FGD, and installing a new full

- scale fabric filter, Post

- Control Scenari o B, was 1.849 Δdv . This visibility improvement is less than the improvement achi eved by Post

- Control Scenario A using new LNB and advanced OFA on Unit 2, 1. 934 Δdv , but higher than Post

- Control Scenario A using new LNB and advanced OFA on Unit 1, 1.716 Δdv

.

5. Annual NO

x emission reductions from baseline achieved by t uning e xisting LNB with OFA and installing SCR are 5,542 tons as compared to only 1,167 tons from tuning existing LNB with

OFA.

6. After careful consideration of the five statutory factors, especially the costs of compliance and the existing pollution control equipment, a NO

x control level of 0. 37 lb/MMBtu on a 30

- day rolling

average for Unit 3 , above EPA‟s established presumptive limit of 0.15 lb/MMBtu for tangential

fired boilers burning sub

- bituminous coal, though not applicable, is not justified.PacifiCorp Naughton Power Plant

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- 6042 BART Application Analysis Page 50

The Division considers the installation and operation of the BART

- determined NO

x controls, new LNB

with advanced OFA on Units 1 and 2 and tuning existing LNB with OFA and installing SCR on Unit 3 to meet corresponding emission limit s on a continuous basis

, to meet the statutory req uirements of BART.

Unit

- by

- unit NO

x BART determinations:

Naughton Unit 1 : I nstalling new LNB with advanced OFA and meeting NO

x emission

limits of 0.26 lb/MMBtu (30

- day rolling average), 481 lb/hr (30

- day rolling average), and 2

, 107 tpy as BART for NO

x .

Naughton Unit 2 : I nstalling new LNB with advanced OFA and meeting NO

x emission

limits of 0.26 lb/MMBtu (30

- day rolling average), 624 /hr (30

- day rolling average), and 2,733 tpy as BART for NO

x .

Naughton Unit 3 : T uning existing LNB with OFA and install ing SCR meetin g NO

x

emission limits of 0. 07 lb/MMBtu (30

- day rolling average), 259 lb/hr (30

- day rolling average), and 1,134 tpy as BART for NO

x .

PM/PM 10

Existing ESP with FGC is determined to be BART for Units 1 and 2 for PM/PM 10 based, in part, on the following conclusions:

1. Recognizing the cost benefit associated with using the existing ESPs and the minimal energy impact of installing FGC, the cost of compliance for the control technology is cost effective for each unit, over a twenty year operational life, for reducing PM emissions. The cost effectiveness for existing ESP with FGC is $1, 721 for Unit 1 and $ 949 for Unit 2.

2. No negative non

- air environmental impacts are anticipated from existing ESPs with FGC.

3. Visibility impacts were addressed in a c omprehensive visibility analysis covering all three visibility impairing pollutants and associated control options. The cumulative 3

- year averaged

98 th percentile visibility improvement from the baseline summed across both Class I areas

achieved with LNB with advanced OFA, wet FGD , and existing ESP with FGC (Post

- Control Scenario A) was 1.716 Δdv from Unit 1 and 1.934 Δdv from Unit 2. While the visibility improvement attributable to the installation of FGC on existing ESPs can‟t be directly determined from the visibility modeling, the Division d oes not anticipate the PM contribution to be significant when compared to NO

x and SO 2 contributions.

Existing ESP with FGC and a polishing fabric filter was not determined to be BART for Units 1 and 2 for

PM/PM 10 based, in part, on the following conclusio ns:

1. The cost of compliance for a polishing fabric filter on each unit is not reasonable over a twenty year operational life. The cost effectiveness for installing a new polishing fabric filter on the existing ESP is $8, 848 for Unit 1 and , $ 11

, 494 f or Uni t 2 . Incremental cost effectiveness is $ 17

, 748 for Unit 1 and $16, 431 for Unit 2.PacifiCorp Naughton Power Plant

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2. The cumulative 3

- year averaged 98 th percentile visibility improvement from applying a polishing fabric filter can be calculated by subtracting Post

- Control Scenario 2 resul ts from Post

- Control Scenario 1 results and summing across both Class I areas . The achieved 98 th percentile visibility improvement was 0. 266 Δdv from Unit 1 and 0. 352 Δdv from Unit 2.

A new full

- scale fabric filter is determined to be BART for Unit 3 for PM/PM 10 based, in part, on the following conclusions:

1. While the Division considers t he cost of compliance for a full

- scale fabric filter on Unit 3 not
reasonable , PacifiCorp is committed to installing this control device and has permitted the

installation of a full

- scale fabric filter on Unit 3 in a recently issued New Source Review construction permit. A full

- scale fabric filter is the most stringent PM/PM 10 control technology and therefore the Division will accept it as BART.

The Division considers the installation and operation of the BART

- determined PM/PM 10 controls, existing ESP with FGC on Units 1 and 2 and a new full

- scale fabric filt er on Unit 3 to meet corresponding

emission limits on a continuous basis

, to meet the statutory requirements of BART.

Unit

- by

- unit PM/PM 10 BART determinations:

Naughton Unit 1 : I nstalling FGC on the existing ESP and meeting PM/PM 10 emission

limit s of 0. 0 4 0 lb/MMBtu , 74 lb/hr, and 324 tpy as BART for PM/ PM 10

.

Naughton Unit 2 : I nstalling FGC on the existing ESP and meeting PM/PM 10 emission

limit s of 0.0 4 0 lb/MMBtu , 96 lb/hr, and 421 tpy as BART for PM/ PM 10

.

Naughton Unit 3 : I nstalling a new full

- scale fabric filter and meeting PM/PM 10 emission

limit s of 0.0 15 lb/MMBtu , 56 lb/hr, and 243 tpy as BART for PM/ PM 10

.

SO 2 : WESTERN BACKSTOP SULFUR DIOXIDE TRADING PROGRAM

PacifiCorp evaluated control SO 2 control technologies that can achieve a SO 2 emission rat e of 0.15

lb/MMBtu or lower from the coal

- fired boilers. PacifiCorp proposed SO 2 BART controls are installing

wet FGD with FGC using the existing ESPs on Units 1 and 2, and upgrading the existing wet FGD using waste liquor and removing the existing ESP an d installing a new full

- scale fabric filter on Unit 3.

Wyoming is a §309 state participating in the Regional SO 2 Milestone and Backstop Trading Program. §308(e)(2) provides States with the option to implement or require participation in an emissions trad ing program or other alternative measure rather than to require sources subject to BART to install, operate, and maintain additional control technology to meet an established emission limit on a continuous basis. However, the alternate program must achiev e greater reasonable progress than would be accomplished by installing BART. A demonstration that the alternate program can achieve greater reasonable progress is prescribed by §308(e)(2)(i). Since the pollutant of concern is SO 2 , this demonstration has been performed under §309 as part of the state implementation plan. §309(d)(4)(i) requires that the SO 2 milestones established under the plan “...must be shown to provide for greater reasonable progress than would be achieved by application of BART pursuant to §51.308(e)(2).”PacifiCorp Naughton Power Plant

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Wyoming participated in creating a detailed report entitled Demonstration that the SO 2 Milestones Provide Greater Reasonable Progress than BART covering SO 2 emissions from all states participating in the Regional SO 2 Milestone and Back stop Trading Program. The document was submitted to EPA in support of the §309 Wyoming Regional Haze SIP in November of 2008.

As part of the §309 program, participating states, including Wyoming, must submit an annual Regional

Sulfur Dioxide Emissions an d Milestone Report that compares actual emissions to pre

- established milestones. Participating states have been filing these reports since 2003. Each year, states have been

able to demonstrate that actual SO 2 emissions are well below the milestones. The actual emissions and their respective milestones are shown in Table 37.

Table 3 7 : Regional Sulfur Dioxide Emissions and Milestone Report Summary

Year Reported SO 2 Emissions (tons) 3

- year Milestone Average (tons)

2003 330,679 447,383

2004 337,970 448,25 9

2005 304,591 446,903

2006 279,134 420,194

2007 273,663 420,637

In addition to demonstrating successful SO 2 emission reductions, §309 states have also relied on visibility modeling conducted by the WRAP to demonstrate improvement at Class I areas. T he complete modeling demonstration showing deciview values was included as part of the visibility improvement section of the §309 SIP, but the SO 2 portion of the demonstration has been included as Table 3 8 to underscore the improvements associated with SO 2 reductions.PacifiCorp Naughton Power Plant

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Table 3 8 : Visibility

- Sulfate Extinction Only

Class I Area Monitor
(Class I Areas Represented) 20% Worst Visibility Days (Monthly Average, Mm - 1 ) 20% Best Visibility Days (Monthly Average, Mm - 1 )

2018 1

Base Case (Base 18b) 2018 2

Preliminary

Reasonable Progress Case (PRP18a) 2018 1

Base Case (Base 18b) 2018 2

Preliminary

Reasonable Progress Case (PRP18a) Bridger, WY (Bridger WA and Fitzpatrick WA) 5.2 4.3 1.6 1.3

North Absaroka, WY

(North Absaroka WA and Washakie WA) 4.8 4.5 1.1 1.1

Yellowstone, WY

(Yellowstone NP, Grand Teton NP and Teton WA) 4.3 3.9 1.6 1.4

Badlands, SD 17.8 16.0 3.5 3.1
Wind Cave, SD 13.0 12.1 2.7 2.5
Mount Zirkel, CO

(Mt. Zirkel WA and Rawah WA) 4.6 4.1 1.4 1.3

Rocky Mountain, CO 6.8 6.2 1.3 1 .1
Gates of the Mountains, MT 5.3 5.1 1.0 1.0
UL Bend, MT 9.7 9.6 1.8 1.7
Craters of the Moon, ID 5.8 5.5 1.5 1.5
Sawtooth, ID 3.0 2.8 1.2 1.1 Canyonlands, UT
(Canyonlands NP and Arches NP) 5.4 4.8 2.1 1.9

Capitol Reef, UT 5.7 5.4 1.9 1.8

1 Represen ts 2018 Base Case growth plus all established controls as of Dec. 2004. No BART or SO 2 Milestone assumptions were included.

2 Represents 2018 Preliminary Reasonable Progress growth estimates and established SO 2 limits.

All Class I areas in the surround ing states show a projected visibility improvement for 2018 with respect

to SO 2 on the worst days and no degradation on the best days. More discussion on the visibility improvement of the §309 program can be found in the Wyoming §309 Regional Haze SIP rev ision

submitted to EPA in November 2008.

Therefore, in accordance with §308(e)(2), Wyoming‟s §309 Regional Haze SIP, and WAQSR Chapter 6, Section 9, PacifiCorp will not be required to install the company

- proposed BART technology and meet the corresponding achievable emission limit. Instead, PacifiCorp is required to participate in the Regional

SO 2 Milestone and Backstop Trading Program authorized under Chapter 14 of the WAQSR.PacifiCorp Naughton Power Plant

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LONG

- TERM STRATEGY FOR REGIONAL HAZE:

In this BART analysis, the tec hnology available, the costs of compliance, the energy and non

- air quality environmental impacts of compliance, any pollution control equipment in use at the source, the remaining useful life of the source, and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology were taken into consideration when determining BART. When evaluating the costs of compliance the Division recognized a time limitation to install BART

- determined controls imposed by the Regional Haze Rule. In addressing the required elements, including documentation for all required analyses, to be submitted in the state implementation plan, 40 CFR 51.308(e)(1)(iv) states: “A requirement that each source subject to BART be required t o install and operate BART as expeditiously as practicable, but in no event later than 5 years after approval of the implementation plan revision.” As a practical measure, the Division anticipates the requirement to install

the BART

- determined controls to occur as early as 2015.

PacifiCorp used the EPA Air Pollution Control Cost Manual , which is identified in 40 CFR part 51 Appendix Y(IV)(D)(4)(a)(5) as a reference source, to estimate capital costs and calculate cost effectiveness. Section 1 Chapter 2 of the EPA Air Pollution Control Cost Manual

- Sixth Edition (EPA 452/B

- 02

- 001) describes the concepts and methodology of cost estimation used in the manual. Beginning on page 2

- 28 of Chapter 2.5.4.2, the manual discusses retrofit cost consideration includi ng the practice of developing a retrofit factor to account for unanticipated additional costs of installation not directly related to the capital cost of the controls themselves. However, PacifiCorp did not present a retrofit factor in their cost analyses . PacifiCorp estimated that the installation of SCR requires a minimum of 6 years of advanced planning and engineering before the control can be successfully installed and operated. This planning horizon would necessarily be considered in the scheduled

m aintenance turnarounds for existing units to minimize the installation costs of the pollution control

systems.

PacifiCorp‟s BART

- eligible or subject

- to

- BART power plant fleet is shown in Table 39 . While the majority of affected units are in Wyoming, th ere are four units in Utah and one in Arizona. Since the 5

- year control installation requirement is stated in the federal rule it applies to all of PacifiCorp‟s units requiring additional BART

- determined controls. Although BART is determined on a unit

- by

- unit basis taking into consideration the statutory factors, consideration for additional installation costs related to the logistics of managing more than one control installation, which are indirect retrofit costs, was afforded under the statutory factor : costs of compliance.PacifiCorp Naughton Power Plant

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Table 39 : PacifiCorp’s BART

- Eligible/Subject Units

Source State

Hunter Unit 1 (a) Utah

Hunter Unit 2 (a) Utah Huntington Unit 1 (a) Utah Huntington Unit 2 (a) Utah

Cholla Unit 4 (b) Arizona

Dave Johnston Unit 3 Wyo ming

Dave Johnston Unit 4 Wyoming Jim Bridger Unit 1 Wyoming Jim Bridger Unit 2 Wyoming Jim Bridger Unit 3 Wyoming Jim Bridger Unit 4 Wyoming Naughton Unit 1 Wyoming Naughton Unit 2 Wyoming Naughton Unit 3 Wyoming Wyodak Wyoming

(a) Units identif

ied in Utah‟s §308 Regional Haze SIP.

(b) Unit identified on the Western Regional Air Partnership ‟s BART Clearinghouse.

B ased on the cost of compliance and visibility improvement presented by PacifiCorp in the BART applications for Naughton Units 1

- 3 and taking into consideration the logistical challenge of managing multiple pollution control installations within the regulatory time allotted for installation of BART by the Regional Haze Rule, the Division is not requ iring additional controls under the Long

- Term Strategy of the Wyoming Regional Haze State Implementation Plan in this permitting action. Additional controls may be required in future actions related to the Long

- Term Strategy of the Wyoming Regional Haze S tate Implementation Plan.

CHAPTER 6, SECTION 4

– PREVENTION OF SIGNIFICANT DETERIORATION (PSD):

PacifiCorp‟s Naughton Power Plant is a “major emitting facility” under Chapter 6, Section 4, of the Wyoming Air Quality Standards and Regulations because emis sions of a criteria pollutant are greater than 100 tpy for a listed categorical source. PacifiCorp should comply with the permitting requirements of Chapter 6, Section 4 as they apply to the installation of controls determined to meet BART.

CHAPTER 5, SE CTION 2

– NEW SOURCE PERFORMANCE STANDARDS (NSPS):

The installation of controls determined to meet BART will not change New Source Performance Standard applicability for Naughton Units 1

- 3

.

CHAPTER 5, SECTION 3

– NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS (NESHAPs) AND CHAPTER 6, SECTION 6

– HAZARDOUS AIR POLLUTANT (HAP) EMISSIONS AND MAXIMUM AVAILABLE CONTROL TECHNOLOGY (MACT):

The installation of controls determined to meet BART will not change Nation Emission Standards For

Hazardous Air Pollutants applicability for Naughton Units 1

- 3

.PacifiCorp Naughton Power Plant

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CHAPTER 6, SECTION 3

– OPERATING PERMIT:

The Naughton Power Plant is a major source under Chapter 6, Section 3 of the Wyoming Air Quality Standards and Regulations. The most recent Operating Permit, 3

- 2

- 1 2 1 , was issued for the facility on

March 19 , 200 8 . In accordance with Chapter 6, Section 3 of the Wyoming Air Quality Standards and Regulations (WAQSR), PacifiCorp will need to modify their operating permit to include the changes authorized in this permit ting action.

CONCLUSION:

The Division is satisfied that PacifiCorp‟s Naughton Power Plant will comply with all applicable Wyoming Air Quality Standards and Regulations. The Division proposes to issue a BART Air Quality

Permit for modification to install new LNB with advanced OFA on Naughton Units 1 and 2, and install FGC in combination with the existing ESP s to meet the statutory requirements of BART. B efore

December 31 , 201 4, PacifiCorp shall tune t he existing LNB and OFA on Naughton Unit 3 and install

SCR and a new full

- scale fabric filter to meet the statutory requirements of BART.

PROPOSED PERMIT CONDITIONS:

The Division proposes to issue an Air Quality Permit to PacifiCorp for the modification of the Naughton Power Plant with the following conditi ons:

1. Authorized representatives of the Division of Air Quality be given permission to enter and inspect any property, premise or place on or at which an air pollution source is located or is being constructed or installed for the purpose of investigati ng actual or potential sources of air pollution, and for determining compliance or non

- compliance with any rules, standards, permits

or orders.

2. All substantive commitments and descriptions set forth in the application for this permit, unless superseded by a specific condition of this permit, are incorporated herein by this reference and are enforceable as conditions of this permit.

3. That PacifiCorp shall modify their Operating Permit in accordance with Chapter 6, Section 9(e)(iv) and Chapter 6, Secti on 3 of the WAQSR.

4. All notifications, reports and correspondence associated with this permit shall be submitted to the Stationary Source Compliance Program Manager, Air Quality Division, 122 West 25th Street, Cheyenne, WY 82002 and a copy shall be subm itted to the District Engineer, Air Quality Division, 510 Meadowview Drive, Lander, WY 82520.PacifiCorp Naughton Power Plant

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5. Effective upon completion of the performance tests to verify the emission levels below, as required by Condition 6 of this permit, emissions from Naugh ton Units 1 and 2 shall not exceed

the levels below. The lb/hr and tpy limit s shall apply during all operating periods. The

lb/MMBtu limit s shall apply during all operating periods, except startup. Startup begins with the introduction of natural gas int o the boiler and ends no later than the point in time when the ESP reaches a temperature of 225 F

.

Unit Pollutant lb/MMBtu lb/hr tpy

1 PM/PM 10 (a) 0.040 74 324

2 PM/PM 10 (a) 0.040 96 421

(a) Filterable portion only

.

6. That no later than 90 days after the installation of new low NO

x burners with advanced overfire

air PM/PM 10 performance tests shall be conducted and a written report of the results shall be submitted. If a maximum design rate is not achieved within 90 days of installing new low NO

x burn ers with advanced overfire air , the Administrator may require testing be done at the rate achieved and again when a maximum rate is achieved.

7. Effective upon completion of the initial performance tests to verify the emission levels below, as required by Condition 8 of this permit, emissions from Naughton Units 1

- 3 shall not exceed the

levels below. The NO

x limits shall apply during all operating periods. Unit 3 PM/PM 10 lb/hr and

tpy limit s shall apply during all operating periods. Unit 3 PM/PM 10 lb/MM Btu limit shall apply during all operating periods except startup. Startup begins with the introduction of natural gas

into the boiler and ends when the boiler is switched over to coal as fuel.

Unit Pollutant lb/MMBtu lb/hr tpy

1 NO

x 0.26 (30

- day rolling) 481 (30

- day rolling) 2

, 107

2 NO

x 0.26 (30

- day rolling) 624 (30

- day rolling) 2

, 7 33

3 NO

x 0. 07 (30

- day rolling) 259 (30

- day rolling) 1,134

3 PM/PM 10 (a) 0.0 15 (b) 56 (b) 243

(a) Filterable portion only

. (b) Upon installation of a PM con tinuous emissions monitoring system, the averaging period shall become a 24

- hour block average.

8

. That initial performance tests be conducted, in accordance with Chapter 6, Section 2(j) of the WAQSR, within 30 days of achieving a maximum design rate but not later than 90 days following initial start

- up, and a written report of the results be submitted. If a maximum design rate is not achieved within 90 days of start

- up, the Administrator may require testing be done at the rate achieved and again when a m aximum rate is achieved.PacifiCorp Naughton Power Plant

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9

. P erformance tests shall consist of the following:

Coal

- fired Boilers ( Naughton Units 1 through 3 ):

NO

x Emissions

– Compliance with the NO

x 30

- day rolling average shall be determined using a continuous emissions monitorin g system (CEMS) certified in accordance with 40 CFR part 60.

PM/PM 10 Emissions

– Testing shall follow 40 CFR 60.46 and EPA

Reference Test Methods 1

- 4 and 5

.

Testing required by the Chapter 6, Section 3, Operating Permit may be submitted to satisfy the

te sting required by this condition. If a PM CEMS is installed on Unit 3, PM CEMS monitoring data collected in accordance with 40 CFR part 60, subpart Da may be submitted to satisfy the

tes ting required by this condition for Unit 3.

10

. Prior to any testing required by this permit , a test protocol shall be submitted to the Division for approval, at least 30 days prior to testing. Notification should be provided to the Division at least 15 days prior to any testing. Results of the tests shall be submitted t o this office within 45 days of completing the tests.

1 1

. PacifiCorp shall comply with all requirements of the Regional SO 2 Milestone and Backstop Trading Program in accordance with Chapter 14 , Sections 2 and 3, of the WAQSR.

1 2

. Compliance with the NO

x limits set forth in this permit for the coal

- fired boilers ( Naughton Units

1

- 3 ) shall be determined with data from the continuous monitoring systems required by 40 CFR

Part 75 as follows:

a. Exceedances of the NO

x limits shall be defined as follows:

i. A ny 30

- day rolling average of NO

x emissions which exceeds the lb/MMBtu

limits calculated in accordance with the compliance provisions and monitoring requirements of §60.48Da and §60.49Da. The definition of “boiler operating day” shall be consistent with th e definition as specified in 40 CFR part 60, subpart Da.

ii. Any 30

- day rolling average calculated using valid data (output concentration and average hourly volumetric flowrate) from the existing CEM equipment which

exceeds the lb/hr NO

x limit established in this permit. Valid data shall meet the requirements of WAQSR, Chapter 5, Section 2(j) and follow the compliance provisions and monitoring requirements of §60.48Da and §60.49Da. The 30

- day average emission rate shall be calculated as the arithmetic av erage of hourly emissions with valid data during the previous 30

- day period. The definition of “boiler operating day” shall be consistent with the definition as specified in 40 CFR part 60, subpart Da.PacifiCorp Naughton Power Plant

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b

. PacifiCorp shall comply with all reporting and record keeping requirements as specified

in WAQSR, Chapter 5, Section 2(g) and 40 CFR part 60, subpart D. All excess emissions shall be reported using the procedures and reporting format specified in WAQSR, Chapter 5, Section 2(g).

1 3

. PacifiCorp shall u se EPA‟s Clean Air Markets reporting program to convert the monitoring system data to annual emissions. PacifiCorp shall provide substituted data according to the missing data procedures of 40 CFR, Part 75 during any period of time that there is not monit oring data. All monitoring data must meet the requirements of WAQSR, Chapter 5, Section 2(j).

1 4

. Compliance with the PM/PM 10 limits set forth in this permit for Naughton Units 1

- 3 shall be

determined with data from testing for PM conducted annually, or more frequently as specified by the Administrator, following 40 CFR 60.46 and EPA Reference Test Methods 1

- 4 and 5. Testing required by the Chapter 6, Section 3, Operating Permit may be submitted to satisfy the testing required by this condition. If a PM CEM S is installed on Unit 3, PM CEMS monitoring data collected in accordance with 40 CFR part 60, subpart Da may be submitted to satisfy the tes ting required by this condition for Unit 3.

1 5

. Records required by this permit shall be maintained for a peri od of at least five (5) years and shall be made available to the Division upon request.

1 6

. PacifiCorp shall install new low NO

x burners with advanced overfire air on Unit s 1 and 2, in accordance with the Division‟s BART determination, and conduct the per formance tests required

in Condition s 6 and 8 no later than December 31, 201 2 and June 1 , 201 2 , respectively.

1 7

. PacifiCorp shall, for Units 1 and 2, install flue gas conditioning on the existing ESPs, in

accordance with the Division‟s BART determination

, within 90 days of permit issuance.

1 8

. PacifiCorp shall tune the existing low NO

x burners with overfire air and install selective catalytic

reduction and a full

- scale fabric filter on Unit 3 , in accordance with the Division‟s BART
determination, and con duct the initial performance tests required in Condition 8 no later than December 31, 201 4

.

# Appendix A Facility Locatio n