08/02/2009 20:50 303-959-2822 NPS-ARD PAGE 01/70



### Date:

To: 

## From: Subject: 

# NATIONAL PARK**S~ERVICE** 

# AIRRESOURCES DIVISION

FACSIMILE COVER

# SHEE:T

August

## 4, 2009

DavidA. Finley
John Bunyak Wyoming

## BART LetterandEi1closures

Number of Pages: 69

- 

### prFax and68 

### 2/ld

### Fax (Including this coversheet)

. OfficeLocatl'on: 7333 HI: Jeffenol'l, Room450. Lakew()od. CO 80235 (SendMailto: 12795 W. AlamedaParkway,.Lakewood, CO 80228)

AUG-04-2009 15:07 303 969 2822 97% P.0108/02/2009 20:50 303-%9-2822 ,NPS-ARD PAGE 02/70

IN REPLYREFERTO, 

# United States,Department ofthe Interior NATIONAL PARK SERVICE 

### Air,Resources Division P.O. Box 25287 Denver; CO 80225 

# fb::;"J**,~J** TAKE PRJ DE" lNAMeFUCA



### August4, 2009


### N3615 (2350)

David A. Finley, Administrator Division ofAir Quality Department ofEnvironmental Quality 122 W. 25th Street Cheyenne) Wyoming 

### 82002
DearMr. Finley:


### Thank you for pro\liding this opportunity to comment upon the Wyoming Department of Environmental Qualit'J'·IS 

### (WY DEQ's) proposal for Best Available Retro:fit Technology (BART) for 

### the 13 Electric Generating Units (EGUs) in Wyoming that are snbject to BART. We are impressed with the effort an.d expertise that went into this effort, and we are pleased that 

### WY DEQ is proposing major reductions in the visibility-impairing pollutants nitrogen oxides (NOx) 

### andparticulate matter (PMIO). 

### However, we believe that additional reductions can be achieved underthe 13ART program. Based on our analyses summarized below and discussed in detail in the enclosed documents, we believe that sele9tive catalytic reduction (SCR) controls are BART for additional 

### EGUs beyond those 

### identified by WY DEQ. Our comments 

### below address the five-step 

### BART process described by 

### EPA"s BART Guidelines and documented by 

### WY DEQ. We first discuss NOx

### controls, then 

### PM1o. Sulfur dioxide 

### (802) controls have already beel) addressed 

### by WY under the 309 State: Implementation Plan and are discussed briefly at the end ofour comments.


### NOxStep 1: IDENTIFYAVAILABLE RETROFIT CONTROL TECHNOLOGIES Except for Basin Electric's analysis for Laramie River, all of the other (PacifiCorp) analyses included a reasonable suite ofoptions. Basinhas omittedthe most-effectiveNOx 

### control technology) the combination of Low-NO" Burners (LNB) plus Over-Fire 

### Air (OFA) plus 

### SCR. It is generally accepted that, although installation of combustion controls ahead of SCR will increase the capital cost of the system, the reduction in operating costs will more than offset that iriitial increase in capital cost. Virtually every new or retrofit SCR system includes combustion controls. Without this combination of 

### technologies, Basin's cost analysis is fundamentally 

### flawed.

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### , 2

NOxStep 2: ELIMINATE TECHNICALLYINFEASIBLE OPTIONS ThIs step was handledappropriately. '


### NOx 

### Step 3: EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES 

### The ability of SCR to reduce' 

### emissions was 

### consistently underestimated. For example, for' the LNB/OFA+SCR option, PacifiCorp, Basin Electric, 

### mId WY DEQ assumed 0.07 Ib/mmBtu for all averaging periods. However, WY DEQ has issued permits for new EGUs requiring that they meet 0.05 lb/mrnBtu over averaging periods of 24-hoUrs l and 30-days.2 Furthermore, 

### EPA's Clean Air Markets 

### (CAM) data (Appendix A) andvendor guarantees show that SCR cantypically meet0.05 lb/mmBtu (or lower) on an annual average basis. PacifiCorp, BasinElectric, and

### WY DEQ have nc>t provided any documentation orjustification to support 

### the higher values used in their analyses. Our review of operating data (Appendix A) suggests 

### that a NOx limit of0.06 lb/mmBtu is appropriate (with an adequate "safety:margin") for LNB/OFA+SCR for a 3D-day rolling average, and 0.07 Ib/mmBtu for a 24-hour limit and for modeling purposres, but a lower rate (e.g., 0.05 lb/mmBtu or lower) should be used for annuhl average and annual cost estimates. When the armual

### N~ reductions are

### Ullderestimat~d, the cost-effectiveness of

, the control option

### is negatively affected. I



### NOxStep 4: EVALUATE IMPACTS AND DOCUMENT RESULTS The cost 

### ofSCRwas 

### consistently overestimated. EPA's 

### BART Guidelines recommend
use ofthe OAQPS Control Cost 

### Manual. Neither PacifiCorP, Basin Electric, 

### nor WY DEQ provided justification or documentation for their coSt estimates. We were not provided with any vendor estimates orbids, and PacifiCorp, BasinElectric and

### WYDEQ did not use the recommended Control Cost Manual. This reJulted 

### in much-higher SCR costs than suggested by available litera.ture (see Appendix 

### C cost 

### summaries) which 

### shows SCR costs ranging from 

### $50

- $267/kW.

Our greatest concern with the cost analyses presented by

# WYiI DEQ is the over-emphasis on 

### the incremental costs resulting from addition of SCR to new oombustion controls. Incremental costs are an appropriate consideration, but they should not he:come the sole basis for a BART decision. We would like to see WY DEQ also consider the average costs calculatedfor combustion controls plus SCR. 

# 1

As recommended bythe 

### BART Guidelines, we appliedthe 

### 0 QPS Control CostMan,ual to 

### the BGDs and derived costs that 

### fell within the

## Append~~ C cost-survey range. As illustrated in Table 1 (and the relevant workbooks in Appendix C) our c:alculated SCR costs for 

### WY EGU are below $2000/ton at all units. As a rekult) we believe that capital and annual costs are overestimatedby PacifiCorp) BasinElecttic, and. WY DEQ. 

### The'basis for equipment cost estimates should 

### be docurnente1. either with 

### data supplied by an equipmentvendor (i.e., budget estimates orbids) or 

### by

### 4'referenc~d liource (such as the OAQPS Control Cost Manual, Fifth Edition, February 1996, 453/B-96-001). In order

I BasinElectric-DryFork 2WVGEN3

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### 3

to maintain and improve consistency, cost estimates should be based on the OAQJ:>S Control Cast Manual, where possible. The Control Cost Manual addresses 

### most control technologies 

### in sufficient detail for 

### a BART analysis. 

### The cost anitlysis should also 

### take into account any site-specific design or other conditions identified above that affect the cost 

### ofaparticular BARTteclulo10gy option.


### EPA's beliefthat the Control Cost Manual should be the primary source 

### for developing cost analyses that are transparent and consistent across the nation and. provide a common means for assessing costs is further supported by this 

### November 7,2007, statement 

### f'l'om 

### EPA Region 

### 8to theNorth

### DakotaDepartment 

### ofHealth: The 802and PM cost analyses were completed llSing the CUECostmodeL ACCI)rding to the BART Guidelines, in order to maintain and improve consistency, cost Mtirn·ates should be based on the OAQPS ConTIol Cost Manual. Therefore, these analyses should berevisedto adhereto the CostManual methodology. 

### According to WY DEQ, "PacifiCorp used the EPA Air Pollution Control Cost Manual, which is identified in 40 CPR part 51 Appendix Y(IV)(D)(4)(a)(5) as a reference source, to estimate capital costs and calculate cost effectiveness." This statement is misleading because, according to PacifiCorp, "Costs and 

### schedules for the LNBs and. OFA, 

### SNCR, and 

### ScR: were furnished to CH2M HILL 

### by PacifiCorp, develope£;]. using S&L's internal 

### proprietary database, and supplemented (as needed) 

### by vendor-obtained price quotes."

. WY DEQ goes on to 

### state 

### that, "Beginning on page 2-28 ofChapter 2.5.4.2, the manual. discusses retrofit cost consideration including the practice ofdeveloping Gl 

### retrofit factor to account for unanticipated additional costs of installation not directly related to the capital cost ofthe controls themselves. However, PacifiCorp did not present a retrofit factor in their cost analyses." If PacifiCorp had actually used the EPA Control Cost Manual Section 4.2 on SeR, the retrofit issue would have been explicitly and transparently accomJuodated by that approach. Instead, PacifiCorp provides insufficient informationto determine 

### ifand

### how itaddressed.this issue.

. 

### WY DEQ's statement that Basin used the 

### EPA Air 

### Pollution Control Cost Manual (Control Cost Manual) is misleading in the context of

### Bas~'s estimation of costs 

### for 

### SCR. Instead, Basin appears in Attachment 1 to its July**200~** 

### re-submittal to 

### have used a format similar to that found in**~eve:ral** 

### sections of the

## "IControl Cost Manual, but completely different from Section 4.2 of the Manual whJich deals**sp(~cifically** 

### with estimating costs for SCR.

. 

## I
NOx

### Step 5: VISIBILITY IMPROVEMENT DETERMINATION We believe that it is appropriate to consider both the degree

# bfvisibility improvement in 

### agiven Class I area as well as the cumulative effects 

### ofimptpving 

### visibility across all of the Class I areas affected. \Vhile we agree with WY DEQ's assessment that the modeling analyses likely captured the greatest impacts, we typically rbquest that aU Class I areas within 300 

### km ofthe source be included in the modeling arlalysis; WY DEQ addressed 

### visibility impacts in a partially-cumulative analysis of

### so~e multiple Class I arelils, howeverit did not typically include all ofthe Class I areas V-lithin 

### 300 km. 

### In addition to Bridger Wilderness Area (WA),**~itzpatrick** 

### WA, and Mount Zirkel WA, we request that

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### 4

WY DEQ' also consider impacts at:Grand Teton National Park**(NP)~** 

### Yellowstone NP, Rocky,Mountain

### NP. Washakie

## wPi., Teton WA, FlatTops WA, Rawah

### V·lA, and Eagles**Nes~** 

### WA.
As illustrated in Table I, consideringjustthe incremental benefits ofSCR at Jim Bridger Units 1 and 3, calculatedfor 3 Class:! areas, the deciview Cdv) improvement would be 

### 0.6 dv. Comparing the benefits ofSCR combined with combustion controls to the current baseline 'Without controls yields a 

### 1:7 dv improvement. We believe the latter benefit is the appropriate basis for evaluating the benefits ofBART controls at Bridger Units 1 and 3. '


### In evaluating the benefits of BART controls, it 

### does not make sense to use the same' metric to evaluate the effects ofreducing emissions from a BART source that 

### impacts only one Class I area as for a BART source that impacts multiple Class I areas. And, it does not make sense to evaluate impacts at one Class 

# r area, while ignoring others that are similarly significantlyimpaired. Ifwe lookat onlythe most-impacted Class I area; we ignore thatthe other Class I areas are all suffering from impainnentto visibility caused or contributed to 

### by the BART source. 

### Itfollows that, ifemissions from the BART source are reduced, the'benefits will be spread well beyond only the**most-impact~:d** 

### Class I area, andthis should be accounted for. ' 

### Our greatest concern with the visibility analyses presented by WY DEQ is the total emphasis on the incremental improvements to visibility resulting from SCR-it calculated only the incremental**imp~ovement** 

### in visibilityresulting 

### from addition ofSCR to the proposed combustion controls. Although incremental benefits are an appropriate consideration, they should not become the sole basis for a BART decision. WY DEQ should have presented the total visibility improvement that would result from a combination ofcontrol options instead ofpresenting only the incremental improvement.
We have an additional concem with:the emissions modeled by PacifiCorp and

## WY DEQ as presented in the "Post-Control Scenario A" and "Post-Control Scenario B" columns of WY DEQ's related tables. For exanitple, in the Jim Bridger Table 27, sulfuric acid mist (I-hS04) emissions are estimated tOlincrease from 55.2 nblhr under Scenario A to 94.7 lb/hr under Scenario B. Althoughno:explanation is provided, we assume thatthe increase in 

### H2

### S04 

### is due to the oxidation of

### S02 to 

### 803 and on to I-hS04 in the flue gas. Because an increase in 

### primary sulfate may adversely impact visibility and reduce the**estimat~d** 

### benefits ofadding SCR, we are providing infonnation inthe enclosed documents relating to the estimation ofI-hS04**emissio~** 

### and requestthat WY DEQ evaluate a:nd explain this issue as 

### itpertains to all ofthe Pacifi:Corp BA.RT analyses.
BART CONCLUSIONS FOR

### NOX: CONTROLS WY DEQ's conclusions and rationales weredearly' stated, but sometimes lacked a basis by whichthereader couldunderstandthe conclusion.

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### 5

NPS recommends.that $/dv be used as an additional metric for evaluating 

### BART controls. In Table 1, using the EPA Control Cost Manual and dv improvement for combustion controls plus SCR, we calculate $/dv benefits for the WY EGUs in the range of$1.1 to 8.7 Million/dv. These benefits are calculated forjust the three nearest Class I areas andwouldbe greaterifbenefits for the additional impacted Class I areas within 300 

### km ofthese facilities had been considered. Nonetheless, the benefits are well withinthe range that has been identified as reasonable for BART controls 

### in other states.3 

### Prom these data, we conclude that 

### 8CR controls are reasonable BART coniTols for the 

### 'NY 

### EGUs. Our

### conoerns with 

### WY's BART conclusions areJurther documentedbelow: According to WY 

### DEQ, "Several different metrics can be considered when evaluating the cost-benefit relationships ofdifferent emission control technologies. In 40 CPR 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 ofpollutant removed) to evaluate different control technologies. Incremental cost effectiveness is also used extensivelyby the Division when comparing eniission controls under the BACTprocess. \Vhile 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 ofthe economic costs to control emissions. In addition to providing cost effectiveness and incremental cost effectiveness results, PacifiCorp provided cost infonnation in terms ofcost ofapplying emission controls and the level of visibility ·improvement achieved (i.e., dollars per deciviews). '\ihile 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 p.olllution control equipment. When performing the presumptive BART limits analyses for NOx and 802, EPA addressed cost effectiveness and incremental cost effectiveness separate from visi1;>ility improvement. EPA did not 

### use the dollars per deciview metric to compare control options. Visibility improvements from the applioation of the analyzed control measures used to establish presumptive levels were addressed in a separate visibility analysis

...the Division evaluated the amount ofanticipatedvisibility improvement gained by the application of additional emission control technology. The Division considered oapital cost, annual cost, cost effectiveness, and incremental cost effectiveness in the evaluation ofeachproposed NOxemissioncontrol."


### NPS: 'While we recognize the expertise of WY DEQ in its use of average and incremental cost-effectiveness in conducting its BACT analyses, WY DEQ should provide the benchmarks itused to determine 

### ifthe average or incremental cost ofagiven control option was ''reasonable.'' Furthennore, we believe that WY DEQ has not given enough consideration to the core purpose oftIle 

### BART program, which is to improve visibility in our Class I areas. 

### BART is not

.necessarily the most cost-effective solution

3http://www.wrapair.orgiforumsJssjfJbart.h1ml

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### 6

but instead, BART represents a broad consideration oftechnical, economic, energy, and environmental (including visibility improvement) factors.
We 

### agree that 

### dollars per deciview (dV) 

### "is not commonly used to 

### ass,ess the overall effectiveness ofpollution control equipment" in the BACT context. However, 

### EPA did explicitly suggest costldV 

### in its 

### BART Guidelines4 

### and it is becoming common in the 

### BART program and 

### has been cited either by a state or by a 

### BART source 

### in at least 

### 18 reviews.s 

### Furthennore, both PacifiCorp and Basin Electric apparently considered costJdV 

### a useful metric when they 

### made statements 

### in their BART proposals indicating that costs ofmillions ofdollars per deciviewwere reasonable. Compared to the typical control cost analysis in which estimates fall into the range of $1,000

- $10,000 perton ofpollutantremoved, spending millions ofdollat·s per deciview (dV) to improve visibility may appear extraordinarily expensive. However, our compilation6 

### of BART analyses across the U.S. reveals that the 

### averag,e cost per dV 

### proposed by either 9. st9.te Qr a BART source is $10

- $17 million,7 with 

### amaximum of almost $50 million per dV proposed by Colorado at the Martin Drake lpower plant in Colorado Springs.
While 

### itis appropriate to consider incremental costs in addition to average costs, wehave a concern with the over-emphasis placed byWY DEQ upon this factor and with the way in which the incremental cost analysis was conducted. 8 

### Vihen rejecting SCR, WY DEQ consistently stated that ('the cost of compliance for installing SCR 011'

### each unit is significantly higher than [combustion controls]." It is generally understood that 

# the cost/ton ofpollution control is an exponential function with an increasing slope as higher control efficiencies are approached. 

### Thus,' the in,cremental cost ofmovi:n.g from lower control to higher control 

### \\'111 increase as higher control efficiencies are sought. Addition of SCR is always going to be «significantly higher" than combustion c<mtrols. IfWY DEQ were to 

### apply this reasoning to its Best Available Control Technology (BACT) analyses, it would nev.er require any controls more stringent than**lO\~l-sulfur** 

### fuels,

4E. How do I selectthe "best" alternar:ive, using the results ofSteps I through 5? 1. Summary ofthe Impacts Analysis Fromthe alternativesyou evaluated in Step 3, werecommendyou develop achart(orcharts) displaying for each ofthe alternatives: (4) costs of compliance

-- total annualized costs ($), cost effectiveness (S/ton), and incremental cost effectiveness (S/ton), and/or any othercost effectiveness measures (such as $/deciview); , 5 BeIining'Road (PES), Boardman (OR), Bridger (PacifiCorp), Ft. Churchill (NVE), FOllI" Comers (APS), Gardner (NVE), Gerald Gentleman (NPPD), Healy (AK), Iolmston (pacifiCorp), Laramie River (Basin), Naughton (PacifiCorp), Navajo (SRP), O-N Minerals (VA), San Juan (PSNM:), Sherburne County (Xcel), Tracy (NVE), TriGen (CNEC) Wyodak (PacifiCorp) , 6 http://www.wrapair.org/forums!ssjflbart.html

, For example, PacifiC{)rp has stated in its BART analysis for its Bridger Unit #2 that "The incremental cost effectiveness for Scenario I com.pared with the baseline fOJ: the Bridger WA, for example, is reasonable at $580,000 perday and $1,8.5 million per deciview." sEPA BART Guideline: "You should consider the incre:mental cost effectiveness in combination with the average cost effectiveness when considering whether to eliminate a control option.'·

... "You should exercise caution not to misuse these [average arid incremental COSt effectiveness]**techniqu~s...** [but considerthem in situations where an option shows]

...slightly greateremission reductions

..."

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### 7
multiple cyclones, and combustion controls. Instead, we have observed that WY DEQ has been very successful in requiring 

### that new sources 

### install both combustion controls and 

### SCRunderits 

### BACTprogram atvery low limits. We suggest thatthe I::ombination of combustion controls plus 

### SCR should instead be viewed 

### as apackage ofcomplementary parts, andthat

### WY DEQ should detennine ifaddition ofSCRis 

### unusually expensive at 

### a specific 

### BART source compared to other installations. 

### Our analysis shows that boththe total cost and the incremental cost of SCR is 

### less expensive at the EGUs 

### evaluated by 

### WY 

### DEQ than the 

### $10 million

- 

### $17 million average c9stper deciview proposed and/or accepted BARTbythe sources and/orstates referenced above. Because, in most cases, the 

### cost of pollution control rises exponentially Vlith control efficiency, the slope of the cost-versus-efficiency curve 

### will also increase. For this reason, rigid use ofincremental cost effectiveness 

### will always result in the choice 

### ofthe cheapest optionifcarried to this extent. According to the 

### NSR Workshop manual, "As a 

### precaution, the difference 

### in incremental costs among dominant alternatives cannot be usedby itselfto argue one dominant alternative is 

### preferred to 

### another." Instead, it should be usedto compare closelyperfonning options. 

### In most cases,9 

### WY 

### DEQ determined that both the. average and incremental costs were "reasonable," but still rejected, the option 

### as BART. 

### WY DEQ should explain the rationale for such decisions.
Additionalreasons givenby

### WY DEQ for**r~jeeting** 

### SCRinclude:


### WYDEQ: Additional non-air quality environmental mitigationis required for the 

### use of chemicalreagents. 

### NPS: We are aware of

### at least

### three pennitsID 

### issued by 

### WY DEQ requiring application



### . ofSCRto 

### new sources and wonderwhythis issue is raised in theseparticul.ar cases.



### WYDEQ: Operation of

### LNB with separated 

### OFA and 

### SCR is parasitic 

### and requires

... powerfrom each

### unit. NPS: the cost ofthis demand

### has been correctly included 

### i:h the cost 

### analyses and should not

### be double-countedunless thatparasitic demandwouldresultinapoweI' shortage. PacijiCorp and WY

### DEQ also state 

### that

### installa.tion of

### SCR could:. .• impact the salability and disposal of 

### fly ash due to higher ammonia levels. NPS-PacifiCorp and WY

### DEQ should·presentevidence that this is actually

### true,

,and quantify

### the economic impact. • potentially create a visible stackplume sometimes referred to as a blue plume, if the ammonia injection rate is not well controlled. NPS--Wel assume that PacifiCorp has the 

### capabilityto 

### controlthe 

### ammoniainjectionrate properly. • potentially create other environmental impacts involving the 

### transportation ofthe ammonia to, and 

### the storage of ammonia at the power plant site), especially 

### if anhydrous ammonia is 

### used. NPS-We recognize these risks, but note that SCR has been in use at many 

### facilities for many ye<lIS with minimal act\lal 

### problems if

9

. . loBridger#1

-#4 forNO", Naughton#1

-#3 for NOx , WyodakforNOx, WYGEN 2 & 3 andBasin ElectricDry Fork.

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### 8
properly 

### addressed 

### by the operating company. We also 

### note that 

### "WY DEQ has requiredinstallation and operation ofSCR atotherfacilities.
WY DEQ notes that "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:' Considering that Minnesota Power supplied a construction schedulell 

### to install SCR plus a new scrubber, fabric filter, and chimney at its 330 MW Boswell Unit #3 in just over' half the time proposed 

### by PacifiCorp, PacifiCorp should explainwhy so muchextratime 

### is needed.


### PM10 

### BART CONTROLS 

### Our only significant 

### and consistent 

### concern 

### v.ith WY DEQ's BART proposals for PMlO relates to 

### PMIO 

### Step 3: EVALUATE EFFECTIVENESS 

### OF REMAINING CONTROL TECHNOLOGIES. Considering that WY DEQ has issued at 

### least 

### three pennits12 

### for new 

### EGUs with fabric filters limited to 0.012lb/mmBtu, WI{ DEQ should explain why the equivalent BART options cannot achieve the same limit, or the 0.010 

### Ib/mmBtu limitpennitted

### byEPA fOf

### the

### DesertRockpo,;iveT

### plant. 

### Our concern is further illustrated

### by WY DEQ's decisionthat, while 

### it considers the cost of the installation of fabric filters proposed 

### by PacifiCoIp to be unreasonable, it has determined

### that fabric filter control strategy

### is BART for

### those EGUs: \Vb.i1e the Division considers the cost ofcompliance fora full-scale fabri,c filter (In Unit3 not reasonable, PacifiCorp is comm.itted to installing this control device and has permitted the installation ofa full-scale fabric filter on Unit 3 in a recently issued New Source Review constnlction permit. A full-scale fabric filter is the most stringent PWPMlO control tech.c.ology and tberefore the Division will accept it as BART. Naughton Unit 3: Installing a new full-scale fabric fJlter and meeting PMJPM 10 mission limits of0.015 lb/nunBtu, 561blhr, and243 tpy as BARTforP.M.t1'MlO• 

### We believe that 

### it is 

### highly 'Lmlikely that PacifiCoIp would propose a BART strategy

,unless it finds the strategy to bereasonable or is otherwise compelled to do 

### so. WY DEQ

should either accept 

### that 'addition 

### offabric filtration is a reasonable BART alternative in the context of providing addition PMJO 

### reductions and the costs that go with those reductions, or 

### state what it 

### considers reasonable average and**incremental,~osts** 

### for 

### PM10 control to be. 

### Our calculations ofPMlO BART control costs' are further illustratedin Table 2. SO,,: REGIONAL 

### 802 MILESTONE AND BACKSTOP TRADING 

### PROGRAM PacifiCorp evaluated S02 control technologies that can achieve a S02 emission rate of 

### 0.15 lb/mmBtu or lower from the coal-fired boilers. PacifiCorp's proposed BART controls are upgrading the existing wet 

### FGD on each ofthe units. Wyoming is a §309 

### state participating in the Regional S02 Nlilestone and Backstop Trading Program. §308(e)(2) provides States 

### with the option to implement or require participation in 

### an

1) See Appendix B '
12 WYGEN2, WYGEN3, BasinElectric-Dry Fork

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### NPS-ARD PAGE 10170



### 9

emissions trading 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 achieve greater reasonable progress 

### 1han 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 ofconcem is 

### 802, 

### this demonstration 

### has been performed under §309 as part of the state implementation plan. 

### §309(d)(4)(j) requires that the 

### 802 milestones established underthe plan "

...must be shown to provide for greaterreasonable progress than would be 

### achieved by application ofBART pursuant to 

### §5IJ08(e)(2)." \Vyoming participated in creating 

### a detailed report entitled 

### Demonstration that the 

### 802 

### Milestones Pro'vide Grea.ter Reasonable .Progress than 

### BART covering 

### SO,2 emissions from 

### all states participating in the Regional 

### S02 Milestone and Backstop Trading Program. The document was submitted to EPA in 

### support ofthe §309 Wyoming Regional

### Haze SIP in

### November of2008. 

### NPS will work 

### with Wyoming, the other §309 participating States, and EPA regarding any issues raised by EPA 

### as it reviews the demonstration that the 

### backstop trading program meets the requirements for an alternative to BART for sulfurdioxide sources. 

### We are enclosing ourtechnical support documents thatprovide greater details concerning each of

### the EOU BART analyses, and request that WY DEQ consider this information before making a final BART detennination for Wyoming BGUs.
Onc:e again, we commend 

### v..ry DEQ 

### for the significant progress its proposals represent. We look forward to working 

### with 

### \Ivy DEQ and EPA as this process advances. 

### -We believe that good communication and sharing 

### of information will help expedite 

### this

, process, and suggest that you contact Don Shepherd (don shepherd@nps.gov, 303-969-

2075) ifyou 

### have any questions or comments. Sinoerely,

# Ju&-~ JohnBunyak Chief, Policy, Planning andPermitReview Branch
Enclosures



### cc: 

### CallieVidetich AirTechnical Assistance Unit 8P-AR U.S. EPARegionV-III 999 18th 

### St., Suite 300 

### Denver, 

### Colorado 80202-2466

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### Wyoming DepartmentofEnvironmental 

### Quality

Chizen Business**~~PS-ARD** PAGE 11/70 

### Page 1 of1

OFFICE ADDRESS TE/..EPHONEIFAX Cheyenne**r~lephona** Hsrschler Building 307·777·7391 122 W. 2S IIl St, I"ax Cheyenne.VVV 82002 S07·m..s818 Telepn.on<!! C3$p(lr 1S2 N. Durbin Sl 307**·473·3~55 Sui~**  100**~ax** Casper. VI/'( 82601 307**.~73-3458** La'1der**Telep!1o~e** 510 Meadowview Dr. 307·332·5755 Lander, VI/'( 82520 Fax 307·332·7726 1eeS S. Stleridan Ave. Telephone Sheridan S07·813.9337 Sheridan, VVY 82801 Fax 307·57'2.2213

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### http://deq.state.wy.us(aqd!contacts.asp 8(4/2009
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....... I\.l Table 1. NOx BART Summary
VVY DEO BART PcoJ>Osals WY OEO lNBfOFA<·SCR Estimates NJ'S lNBJOFA+SCR EsUml3les. BART Avelage Proposed Ave/age Assumed InClomental**Incr~menlal** Proposed OecivieIY CosllDeciviolY Plant Incremental Incleilionfal Deciview CosUdecMew Avenge (ncremen'al Vniles) Cosl Co.1I**(~ItOllJ** BARTlimil COOl Cos! (iJlon) BARTlimil Jrropro'/ameni Impiovemenl CO$I (3Itonl Cosl**(~Il(jnl** BARTliml1 ImpJovemenl ImprovomE-III (Sllon) (lllfmmBlu) (Mon) (lbll11mSlu) (ifvj ($l(lvj (11l/fIlmSlu) (d'/) (.fJduj Bridllef 1&3 $255 5255 0.26 S2,2511 $5,721 0.07**0.~27** So 30,544,547 S 750 S 1060 C.O:> 1.6D7 $ 3.448,496 BriclCler -4 $255 $255 0.26 52,258 $5,721 0.07 0.63:> S 30, 15!U::t4 S 750 S 1060 0.05 1.527 3 3.632,4 15 Bridqer 2 NA NA 0.26 54.275 $:>,6J6 0.G7 0.627 S 30637.329 $ 1,000 0.05 0.626 3 7.064.663 .)o!lnsloll 3 5646**~646** 0.28 S:l.2.o1J S10.324 0.07 0.754 Ii 21,661,U60 S 1,011 

# • 1.400 0.05 4.312 Ii 1 148.639 Jollnsfon 

# " SIS7 $131 0_15 $2,210 $11.662 0.01 (HOS $ 40,5<39,205 $ 1,400 $ 2.674 0.05 3.242 Ii 1,507.692 laramie Riw 1 32,071 S2.0n 0.23 $3,372 $7.196 0.07 0.675 .$ 23,386,14ll $ 1,459 $ 1,258 0.05 0.615 S 7,928,305 l.aramie Rillet 2 52,Oll8 $2,033 .0.23 $3.391 57.242 0.07 0.672 $ 23,492.560 $ 1,446 5 1,300 0.05 0672 1- 8:334,590 L.aralTie River 3 62.036 $2,036 0.23 $3,305 67.054 0.01 0.658 $ 23.992,401 S 1,.0121 S 1,293**O.O~** O.GSll $ 6.694,299

NauQhtoll I t425 $426 0.26 $2,75() $9,089 0.01 0.405 $ 25.261.738 S 1.073 S 1,735 0.05**~.121** S 1.519.119 Naughton 2 $3:>7 $351 0.26 SZ,a4ll 57,5-52 0.07 0.500 $ 25,023.986 S 902 $ 1,676 0.05 2440 $ 1,487,903 Nau!lh(on J $2,830 $1,783 , 0.07 $2,630 $1,783 0.07 1.D23 $ 15,329,818 $ 791 S B60 0.05 1.a.49 S 1791.020 Wyooa'i. 1 $681 seal 0.23 54,252 -$5,141 0.07 0.665 S 26,437,2fi5 $ l,IHO $ 1.610 0.05**1.€6~** $ 3,416,738 SCR is pJopose<l as BART 101 Naughton**~3.** SCR is proposed as. Reasonable Progress Ill<' Bridger 1i3 & if4, and (or lvt1her analvsls ror Blk/gel II! &. #2. rn CD "- rn to "- to rn rn L.D

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I· PAGE 13/70

AUG-04-2009 15:07 303 969 2822 98% P.1308/02/2009 20:50 303-959-2822 NPS-ARD PAGE 14/70**Nation~.l** 

### Park Service (NPS) Comments 

### on the Wyoming Department ofEnvjronmental Quality's proposed BestAvailable Retrofit Technolqgy 

### (BART) Determination for 

### Jim Bridger 

### PowerPlant August 3, 2009


### DESCRIPTION OF BART ELIGIBLE SOURCES PacifiCorp's Jim Bridger Power Plant (Bridger) is comprised of four idelltically·sized 

### nominal 530 

### Megawa.tt (MW) tangentially-fired 

### Electric Generating Units 

### (EGUs) burning pulverized coal 

### tor a 

### total net 

### generating capacity of

### 2,120 MW. Unit 

### I was 

### placed in service in 1974 and Unit 2 commenced 

### service in 1975. Unit 3 entered service in 1976, tollowed by Unit 4, which commenced service in 1979. Each unit was initially equipped with early-generation Low-NOx 

### bumers 

### (LNB) manufactured 

### by Combustion Engineering 

### to**con~ol** emissions ofnitrogen oxides 

### (NOx). They 

### an: also equipped 

### with dry Flakt 

### wire-frame electrostatic 

### precipitators (ESPs) to control particulate matter (PM emissions). 

### Finally, to control sulfur dioxide 

### (S02) emissions, 

### each unit is equipped with 

### a three-absorber-tower wet-sodium 

### flue gas desulfurization 

### (WFGD)**~ystl;:m** made 

### by Babcock & Wilcox.


### On April 

### 1, 

### 2005, Permit MD-1138 was issued to PacitiCorp 

### to replace the firstgeneration LNB on Unit 2 with 

### anew ALSTOM TFS 2000TM 10w·NOx firing system including 

### two elevations ofseparated overfire air (SOFA). 

### The new LNBs were installed and placed into 

### service 'May 29, 2005. The permitted 

### NOx emission limit of 0.26 Ib/mmBtu, 

### annual average, 

### authorized in MD-1138 for Unit 2 Vient into effectin 2005.
On 

### October 6, 2006, after the LNB 

### modification to Unit 2 

### was completed, PacifiCorp submitted 

### a construction 

### pennit application 

### to modify Units 

### l, 2, 3 and 

### 4 by 

### replacing the existing first-generation LNBs 

### on Units 1,3 and 4 with 

### Alstom TFS 2000TM LNB with two elevations ofSOFA, in.stall a flue gas conditioning (FOe) system which injects SOj 

### gas into the flue gas to improve the efficiency 

### ofthe ESPs on Units 

### 1-4, and upgrade the existing FGD systems on all tourunits to achieve greater than 90% 

### S02 removal.
Permit MD-I552 was issued April 9: 

### 2007, authorizing the new 

### LNB, FGe, and 

### WFGD modifications to Bridger. 

### The LNB upgrades 

### to Unit 3 started up May 30, 2007. The new LNBs on Unit 4 started 

### up June 8, 2008.·The 

### final LNB upgrade 'is planned 

### for 2010 on Unit 

### 1.
Modifications to 

### the scmbber vessels on Unit 4 

### were not necessary in order 

### to meet the SOl emission limits 

### permitted in MD-1552. 

### Unit 4 can meet 

### the limits by 

### reducing the amount of 

### flue gas 

### bypassing the 

### scrubber. However, this would increase the 

### moisture content ofthe gas entering the exhaust stack and modifications to the stack drain system were required to accommodate the increased moisture. PacifiCorp is currently evaluating 

### the upgraded stack drain system on the Unit 4 exhaust 

### stack. Upon completion 

### of wet scrubber 

### upgrades permitted in MD-1552, 

### the S02 limits fOT the:' corresponding unit



### 1

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### NP5-ARD PAGE 15/70

become 0.15 Ib/mmBtu on a 12-month rolling average and 900 Ibfhr on a 24-hr rolling average. According to 

### EPA's Clean Air Markets (CAM) 

### database, 2007 NO.'( emissions from Bridger were 25,620 tons which ranked the plant #15 in the U.S.


### Coal characteristics affect

### the design ,!nd efficiency 

### ofpollution 

### control equipment. 

### Units 2-4 are 

### currently equipped 

### with new 

### ALSTOM TFS 2000TM 

### LNB and. SOFA combustio.n control 

### systems. PacitiCorp 

### contends that actual data demonstrate that, 

# ror the Bridger units with the LNB emission systems installed and 

### burning a combination of 

### the Bridger, Black Butte, and Leucite Hill coals, the 

### likely NOx emission rate will 

### be closer to the 

### bituminous (0.28 Ib/mmBtu) BART presumptive NOx Limit, rather than the BARTpresumptive NOx limit of0.15 Ib permmBtu for sub-bituminous coal.
BART Analysis for NOx NOx Step 1: 

### IDENTIFY AV

### AILABLE RETROFIT CONTROL 

### TECHNOLOGIES 

### WYDEQ: PacifiCorp identified four 

### technologies to control 

### NOx emissions:: 

### LNB with SOFA, 

### rotating opposed 

### fire air (ROFA), selective 

### non-catalytic reduction (SNCR), and selective catalytic reduction 

### (SCR). In addition 

### to applying these 

### control technologies separately, they can 

### be coinbined to increase overall NOx reduction. 

### PaciflCorp evaluated the application ofLNB 

### with SOFA 

### in combination with both SNCR and SCR add-on controls. ' . , 

### NPS: We agree 

### that this is a reasonable suite ofoptions.
NOxStep 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS None 

### ofthe four control technologies proposed was deemed technically 

### infeasible 

### by PacifiCorp.
NOx Step 3: EVALUATE EFFECTIVENESS OF 

### REMAINING CONTROL 

### TECHNOLOGIES WYDEQ: PacifiCorp contracted with Sargent and Lundy (S&L) to conduct 

### a. study of applicable NOx control technologies for the Jim Bridger units and to collect data from boiler vendors. Based 

### on results from the study, PacifiCorp indicates that 

### neviLNB with SOFA on the Jim Bridger units would result in a NOx 

### emission rate as low as 0.24 Ib/mmBtu. PacifiCorp has indicated that this 

### rate [0.24 IbimmBtu] corresponds to a vendor guarantee, not

# a' vendor prediction, and they believe that this emi.ssion 

### rate can be. 

### sustained as an average between 

### overhauls. However, due to 

### unforeseen operational issues associated with retrofitting the 

### boilers, including' site 

### specitic challenges, PacifiCorp proposes an additional NOx increase of 0.02 Ib/mmBtu to total 0.26 Ib/mmBtu.
8&L prepared the design conditions and cost estimates for installing SCR in each ofthe units. A high-dust SCR contiguration, where the catalyst is located do",mstream from the economizer 

### before the air heater and 

### any particulate control 

### equipment, was used in the analysis. Based on the S&L design, which included installing both LNB 

### with SOFA and SCR, PacifiCorp concluded the Jim Bridger units could achieve a NOx emission rate of

2

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0.07 lb/mmBtu. The potential NOx control 

### options and their emissions are shmN11 in Table 1.

Table I:**NO~** Emission Rates Per Boiler



### . Control Technology Resulting NOx Emission Rat.: (lbimmBtu) EXlstin£! LNB 0.45 (a) .-..-_., New LNB with separated OFA 0.26 (b) 

### •.. Existing LNB

..... \lith ROFA 0.22 New LNB with separated OFA and SNCR 0.2 New LNB with separated OFA and SCR 0.07



### .. (a) Annual averaged NOx emiSSions estaol1shed through 40 CFR Part 76 which valY among the four Jim Bridger units from 0.40·0.45 Ib/mmBcu. (b) Jim Bridger Units 2-4 have installed new LNB with separated OFA and are subject to a new NO." emission limit ofO.26Ib/mmBtu, annual average, established in MD-1552. NPS: 

### PacifiCorp and 'WY DEQ have 

### underestimated tbe ability of SCR to reduce 

### emissions. 

### For example, 

### for the 

### LNB/SOFA+SCR option, 

### PacifiCorp**a~,sllmed** 

### 0.07 Ib/mrnBtu for all operating periods. However, WY DEQ has issued permits for new 

### EGUs requiring that they 

### meet 0.05 Ib/mmBtu over 

### averaging periods of24-hours l 

### and 30-days.2 

### Furthermore, EPA's CAM datCl? (Appendix A) and vendor guar,mtees4 show that 

### SCR can typically 

### rneet' 0.05 Ib/t11mBtu (or

.

### lower),on an annual average basis. PacifiCorp has not**pr~vided** 

### any documen1ation or justification 

### to s1.Lppmt the 

### higher values used in 

### its analyses. Based on the 0.026 lb/mmBtu NOx emission rate predicted by

. PacifiCorp for the LNB/SOFA option, outlet emissions at 0.07 Ib/mmBtu 

### representonly a 

### 73% SCR control 

### efficiency as oppo.sed to the generally-accepted 

### 90% for a· welldesigned system. Our review ofoperating data (included in the tangential boilers porti<m ofAppendix A) suggests that a NOx limit of0.06 Ib/mmBtu is appropriate (with R safetymargin) Jor LNB/SOFA+SCR 

### for a 30-day 

### rolling average, and 0.07 

### Ib/m111Btll for a 24- hour limit and for modeling purposes, but a lower rate (e.g., 0.05 lb/mmBtu or k'wer)

. . shoul.d be used for annual cost estimates.


### NOx Step 4: EVALUATE IMPACTS AND DOCUMENT RESULTS 

### NPS: PacifiCorp and WY DEQ have overestimated the costs of SCR. Neither PacitlCorp n.or WY DEQ 

### providedjustificati,on or documentation for their cost estimates. We were not provided with any vendor estimates or bids, and PacifiCorp and WY DEQ

I Basin Electric-.Dry Fork 2 WYGEN3 ; We found at least 20 examples (Please see Appendix A" Table A.I.) oftangemi:llly-fired boilcrs similar to those at Bridgerthat have been retrofitted with SCR and are achieving annual emission ratcs below 0.06 Ib/mmBtu. We were able to find 2006 hourly emissions in EPA's CAM**dat~lba5c** for ten ofthose EGUs. and charts showing. those emissions are included in the tangential boilers portion of Appendix A. We**believ~** that inspection ofthe data leads to the conclusion that these SCRs retrofit to eastern EGUs burning. bituminous coal can typically reduce NO, emissions by 90% and achieve 0.05 Ib/rnmBtu (or lower) '011 a 3D-day rolling average basis during the eastem ozone season. '
J Minnesota Powerhas stated in its Taconite Harbor BART analysis that "The use ofan SCR is expected to achieve a NO" emission rate of 0.05 Ib/mmBtu based on recent ernission guarantees ofrcl"ed by SCR system suppliers."



# .. :J

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did not use the Control Cost Manual. According 'to information provided 

### by PacifiCorp 

### and WYDEQ:

• SCRwould reduce 

### NO;.: by 73% and result-in an annual emission rate of0.07 

### 1 b/mmBtu.



### • SCRcapital cost would 

### be 

### $314/kW. This result is much

### higherthan suggested by available literature (see Appendix C cost swnmaries) which shows'SCR costs ranging from $50

- 

### $267/kW. 

### PacifiCorp has 

### provided no justi±ic:ation for its extraord.inarily high costs. '

• The Average Cost ofLNB/OFA+SCR would 

### be $2,258/ton.

• The Incremental Cost ofSCR would be $5,721/ton.


### As recommended by the 

### BART Guidelines, we applied 

### the Control Cost 

### Manual to Bridger. (Please see the Bridger workbooks in Appendix C.) The following'information 

### was generated by

### NPS using 

### the assumption that LNB/SOFA+SCR wouldreduce NOx 

### by 81 % (from 0.26 Ib/mroBtu) and result in an annual emission rate of0.05 lb/mmBtu.

• SCR capital cost would be $68/kW. This result is much more consistent with available literature (see Appendix 

### C cost summaries) which suggests 

### SCR 

### costs ranging 

### from $50

- $267/kW. ' '



### • The Average 

### Cost ofLNB/SOFA+SCR\),.'ould 

### be $750/ton.

• The 

### Incremental Cost of

### adding SCR

### would'be $1,060Iton

.. 

### As a result of 

### higher emission reductions5 and lower Total Annual Cost:;, our costeffectiveness6 estimates are much lowerthanthe 

### wy DEQ estimates.
Even though PacifiCorp and WY DEQ have overestimated the cost 

### of SCR, 

### WY DEQ determined that Uthe cost effectiveness 

### and incremental cost effectiveness of

### the four 

### proposed BART technologies 

### for NOx are all reaso'nable."
NOxStep 5: VISIBILITY IMPROVEMENT DETERMINATJfON 

### WYDEQ: Only those Class I areas most likely to be imJPacted 

### by Jim Bridger were modeled, 

### as determined by source/Class I area locations, distances to each Class I area, 

### and professional judgment considering meteorological and 

### terrain ta,ctors. 

### It can be reasonably assumed that areas at greater distances and in directions of less frequent plume transport 

### will experience lower impacts thanthose predicted for the three 

### modeled
areas. 

### All source-Class 

### I area 

### distances from Bridger Power 

### Plant to Bridger 

### WA [Wilderness Area], Fitzpatrick WA, and Mount Zirkel WA exceed 50 km and are less than 300 km, thus falling within the range recommended for CALPUFF application. 

### NPS: 

### While we agree with WY DEQ's assessment that the modeling analysis has likely captured the greatest impacts, we are also interested 

### in the cumulative impacts on all Class I areas within 300 km. Therefore, we typically request that all Class 

### J areas within 300 km ofthe source be indu.ded in the modeling analysis. In this case, in addition to the, three Class I areas noted by WY DEQ, we recommend tbat impa.cts at Grand Teton

S We based our analysis on the annual limits proposed by WY DEQ which appear to represent 100% utilization.
I; Wrt bdieve that the comparison ofcosts and benefits for adding SCRto LNB/SOFA is the most valid test for incremental cost·effectiveness because these are the (Wo most·1 ikcly candidates for BART.

4

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### National Park (NP), 

### Yellowstone NP, Rocky Mountain NP, Washakie WA, Teton WA,

. FlatTops WA, Rawah W A, and Eagles Nest WA be included inthe modeling analysis.


### NPS: We are concerned about 

### the emissions modeled by 

### PaciJiCorp and 

### WY DEQ as presented in the 

### "Post-Control Scenario A" and 

### '·post-Control Scenario B" 

### columns of 

### WY DEQ's Tahles 27

- 30. For example. in 

### Table 27. sulfuric 

### acid mist 

### (H2

### S04) emissions are estimated to increase from 55.2 lb/hr under Scenario A to 94.7 Ib/hr under Scenario 

### B. Although no explanation is provided: we 

### assume that 

### the increase 

### in H2

### SOJ 

### is due to the oxidation ofS02by 

### SCRto S03 and on to H2S04 in the flue**ga~"** 

### Because. H2S04 must be reported as a hazardous air pollutant, the Electric Power Research Institute (EPRI) has developed a widely-accepted method7 

### for estimating those emissions. We 

### have created an Excel workbook (in 

### Appendix D) 

### derived from that EPRl method and used it to predict that total S04 emissions from each unit at Bridgerwith'out SCR are about 2 lb/hr (versus 54 lb/hr estimated by PacifiCorp and WY DFQ). We also used 

### the EPRl method 

### to predict that 

### total S04 

### emissions from each 

### unit at Bridger

### with SCR are about 10 

### lb/hl" (versus 108 

### lb/hr estimated by 

### PacifiCorp and WY DEQ), 

### Furthennore, PacitiCyrp lind WY DEQ failed 

### to ilPply conservation of

### mass principles and did not adjust their predicted S02 emissions dov,,'nward to re.'l1ect the increa!'ed oxidation of

### S02 to 504; we estimated that 63 lb/hr of"potential"**SO~** 

### wouJ<l have been emitted 

### to the' control systems 'as S04. The. net effect ofadding 

### SCR is to reduce 

### that potential S02 by 63 lb/hr while increasing 

### 804 by 10 Ib/hr. Ifone assumes that all 802 emitted would eventually oxidize to S04 

### anyway, the addition of SCR results in a net reduction

# in atmospheric sulfate by converting the 

### S02, thatwould otherwise escape, i.nto a fonn that can be captured in the airpreheater and emission control system. 

### WYDEQ: While 'visibllity impacts were addressed in a ctlmulative analysis ofall three pollutants, 

### Post-Control Scenario B is directly comparable to Post-Control A, as the only difference is directly attributable to the installation of SCR. Suhtr.:lcting the modeled Scenario B values from Scenario A 

### yield the incrememalvisibilily improvement from SCR. The cumulative 3-year averaged visibility improvement from addir.ig SCR

# was 0.627 6dV

### per unitfrom Units 1-3 and 0.635 6dV 

### from Unit 4. 

### NPS: The WY DEQ approach provides only the incremental improvement in visibility resulting from addition ofSCR to the p(Qposed/installed combustion controls. The total improvements resulting from combustion controls plus SCR can be found 

### by subtracting Post- Control Scenario B from the Baseline case. The average 98th percentile visibility improvements from LNB/SOFA+SCR are 1.7**~dV** 

### per unit from Units 1 - 3 and 1..5**~dV** 

### from Unit 4. '

7 "Estimating Total Sulfuric Acid Emissions from. Stationary Power. Plants". Electric Power Research Institute, Technical Update, March,.200S and Hardman et al., 1998



### 5

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### BART CONCLUSIONS 

### NPS: PacifiCorp 

### apparently considered cost/dV a useful metric when 

### it made the 

### following statements in 

### its BART proposals:



### • Unit #1: The average 

### incremental 

### cost effectiveness 

### for Scenario 1 compared 

### to the Baseline for the Bridger Wilderness area 

### is reasonable at 

### $300,000 per day and 

### $7.7 million per 

### dV.

• Unit 

### #2: The incremental cost effectiveness for Scenario 

### 1 compared with the baseline for the Bridger 

### WA, for 

### e:-<ample, is reasonable 

### at $580,000 per day 

### and $18.5 million per cieciview.

. 

### • Unit #3: The 

### incremental cost-effectiveness 

### for**Sc~nario** 

### I compared 

### to the Baseline for the Bridger WA, for example, 

### is reasonable 

### at $320,000 per day 

### and $7.9 millionJdV.

.
• Unit #4: The incremental 

### cost effectiveness 

### for Scenario 

### 1 compared to the Baseline 

### for the Bridger Wilderness Area; for example, is 

### reasonable at $290,000 

### per day and 

### $5.6 million per 

### dV.


### WYDEQ determined 

### BART for**NO~** 

### is LNB with SOFA 

### at 0.26 Ib/mrnBtl.:l 

### on a 30-day rolling average, 

### for Units 

### 1-4 foc based, 

### inpart, on 

### the following 

### conclusions:

.

.1. LNB with separated OFA 

### on Units 

### 1, 3, and 

### 4 

### was**cost-eff~ctive** 

### with 

### a capita] cost 

### of$11,300,000 per unit**·~.md** 

### a $255 per 

### tqn of

### NOx removed average cost effectiveness for 

### each unit 

### over a twenty-year operational 

### life. LNB with SOFA 

### on Unit

### 2 did 

### not require 

### any additional

### ,capital 

### CQst or 

### annual 

### O&M ,;os1. 2. Combustion control 

### using· 

### LNB with SOFA does 

### not require 

### non-air quality 

### environmental mitigation for the 

### use ofchemical reagents 

### (Le., ammonia or urea) 

### and there is aminimal energy 

### impact. 3. Annual 

### NOx emission**reduc~ions** 

### {Tom LNB 

### with SOFA 

### on Unit 1,3, and 

### 4 arc 4,493 tons per 

### unit for 

### a total 

### annual reduction 

### at Bridger ()f 

### 13,479 tons. 

### There arc no 

### NOxreductions from 

### Unit 2 as 

### LNB with SOFA is baseline for the unit.
LNB with SOFA and SCR was not determined to be BART 

### tor Units] -4 

### for NOx

### based, in part, onthe 

### following conclusions: 

### 1. The 

### cost ofcompliance 

### for installing SCR on 

### each unit is 

### significantly higher than LNB with SOFA. Capital costs for SCR on Units 1-4 are 

### $166,500,000 per unit. 

### Annual operating 

### costs for Units 

### 1, 3, and 4 are $3,382,286 per 

### unit and Unit 2 is 

### $3)70,466.**NP~WY** 

### DEQ determined that "'the cost effectiveness and incremental cost effectiveness of the 

### four proposed BART technologies for NOx are all reasonable." 2. Additional 

### non-air. quality 

### environmental mitigation is required for the use of chemical reagents. 

### 3. Operation ofLNB \vith SOFA and SCR is parasitic and requires an 

### estimated 3.22 

### MWto 3.36 MW ofpo\verfrom eachunit. 4. While 

### visibility impacts 

### were addressed in a 

### cumulative analysis of all 

### three pollutants, Post-Control 

### Scenario B is directly 

### comparable to Post-Control A 

### as the only ditlerence is directly attributable to the installation ofSCR. 

### SUbtracti.ng the modeled values ftom each other

### yield the 

### incl:emental visibility improvement 

### trom SCR. The 

### cumulative 

### 3-year averaged visibility improvement from Post

### 6

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Control Scenario A across 

### the three Class 

### I areas achieved with Post-Control Scenario B was 0.627 LidV per unit from Units 1-3 and 0.635 ildV from Unit 4. Wy DEQ considers the installation'and operation ofthe BART-detennined

### NO~ controls, 

### LNB with 

### SOFA, to meet the corresponding emission 

### limits of0.26 IblmmBtu, 30-day roIling average, 1,560 lb/hr, 3D-day rolling average, and 6,833 tpy on a continuous basis to meet the statutory requirements'of

### BART.


### NPS: Using the Control Cost manual as recommended 

### by EPA's 

### BART Guideline:,. \Ve have estimated the average cost of installing combustion controls 'plus SCR at less than 

### $800/ton, and the incremental cost ofadding SCR to the proposed**combl\.~tifm** controls at less than $l,lOO/ton. 

### Considering that WY DEQ found that the much higher estimates provided 

### by PacifiCorp for its LNB/SOF

### A option were**'4reasonable,~'** we conclude 

### that our estimates indicate that addition of

### SCR is even more "reasonable."
In its BART**analyses~** PacifiCorp stated that costs per deciview of$5.6 million $18.5 million 

### per deciview are "reasonable," and 

### it is even reasonable to spend 5)31.7 million 

### per dV**t~** 

### reduce NOx emissions at its Dave Johnston power plant. 

### Furthe:mlore, these PacitiCorp conclusions are consistent with those reached across the countri that the average cost per 

### dV proposed by either a state or a BART source 

### is $10

- S17 

### million, with 

### a maximum 

### ofalmost $50 million per dV proposed 

### by Colorado at the 

### Martin Drake power 

### plant. ' Combining the modeling results 

### provided -by WY DEQ (which we believe have underestimated SCR benetIts) and our cost analyses based 

### upon EPA guidance, we estimate that addition ofSCR at each ofthe Bridger units would improve visibility at a cost

# of$7 'million'

### per dV at the Bridger Wilderness Area alone and for less than $4 million per dV across the three Class I areas e'\laluatcd 

### by WY DEQ. Not only is addition ofSCR cost-effective by these**criteri~,** it would be even more so ifthe issues we have noted above are addressed.
'BART Analysis for 

### PMID
PMIO 

### Step 1: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES Bridger Units 1·4 are currently equipped with electrostatic precipitators (ESP's) to control PM emissions from the boilers. PacifiCorp states the existing ESPs are able to control 

### PMIPMlo emissions to 0.045 Ib/mm}3tu, 0.074 Ib/mmBtu, 0.057 Ib/mmBtu, and 0.030 Ib/mmBtu from Units 1, 2, 3, and 4, respectively. Three PM control technologies were analyzed for application on the four Bridger units: 

### fabric filters or 

### baghOllses, ESPs, and flue gas conditioning (FGC). We agree that this is a reasonable suite of

### options.
PMIO Step 2: ELIMINATE TECHNICALLY INFEASIBLE 

### OPTlONS PacifiCorp did not eliminate any of the three control technologies**ll~lcd** above**a~** technically infeasible.

Rhttp://www.wrapair.org/fol.1Jms/ssjf /bart.htmI

7

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### PM10 

### Step 3: EVALUATE EFFECTIVENESS OF REMAINING CONTROL' TECHNOLOGIES 

### Wy DEQ: Bridger Units 1-4 have existing ESPs and rather than evaluate costs of replacing 

### them, PacitiCorp 

### evaluated additional controls to improve the 

### PMw removal efficiency. Rather than. demolishing the existing ESPs and constructing an entirely new PM con.trol device, PacifiCorp recognized the cost 

### benefit ofkeeping the 

### existing unit and augmenting the control. Installing FOC on Units 1-4 can improve the PM removal efficiencies on 

### the existing ESPs down to 

### 0.030 lb/mmBtu. In addition to**ma~ntaining** the existing ESPs, a polishing fabric filter can be installed downstream ofthe existing ESPs. , PacifiCorp proposed the use of Compact Hybrid Particulate Collector (COHPAC). 

### PacifiCorp estimates the 

### application of

### the COHPAC unit 

### in addition to using 

### FGC with the existing ESPs can 

### reduce emissions an additional 50% resulting in a PM,o emission rate of 0.015 Ib/mmBt'l.1. PacifiCorp's proposed 

### emission rates for each technology as applied to Units 

### 1-4 are shown in Table 2 below.

Table 2: PM10 Emission Rates Per Boiler Control Technology ResuItin!? PMI0 Emission**Rab~(Ib/mmBtu)** Existing ESPs 0.030-0.074 (3) Existing ES?s with FGC 0.03 Existing ESP and New Polishing Fabric: Filter 0.015 (a) Achievable baseline emission rates using existing ESPs on Jim BridgerUnits 1-4. 

### NPS.- Considering

### th~t WY 

### DEQhas

### iss,~~d at least 

### three pe1TI1its9 for new 

### EGUs with fabric 

### filters limited 

### to 0.012**lb/mmBtu~** 

### WY DEQ should 

### explain why 

### the COHPAC option cannot achieve 

### the same 

### limit, or 

### the 0.010 lb/mmBtu limit 

### permitted 

### by EPA for 

### the Desert 

### Rock powerplant.' 

### PMIO Step 

### 4: EVALUATE IMPACTS AND DOCUMENT RESULTS 

### Wy DEQ: The cost-effectiveness and incremental cost-effectiveness 

### ofapplying a new polishing fabric filter 

### are not 

### reasonable. However, the control was included 

### in the final step in the 

### PM/PMlo BART detennination process for Jim BTidger Units 1-4, 

### NPS: WY 

### DEQ should re-evaluate 

### the COHPAC option 

### on the basis of

### its ability to 

### achieve a lower limit (e.g., 0.010 lb/mmBtu) and 

### compare 

### its cost-effectiveness 

### to other baghouse installations to properly assess the "reasonabieness" ofits cost.
PM10 

### Step 5: VISIBILITY IMPROVEl.\'IENT DETERMINATION 

### l'v'PS: None of the options modeled 

### by PacifiCorp or WY DEQ**provid(~** 

### sufficient information to evaluate the visibility irnprovement resulting 

### trom 'the 

### COHPAC option.

9 WYGEN2, WYGEN3, Basin ElectriC-Dry Fork·



### 8

AUG-04-2009 15:07 303 969 2822 98% P.2108/02/2009 20:50 303-959-2822 

### NPS-ARD PAGE 22/70



### BART CONCLUSIONS 

### WYDEQ: Existing,ESP with FGC 

### is determinedto be BART for Units 1-4 for PM/PM 10 

### based, in part, onthe following conclusions: ' 

### 1. Recognizing the cost benefit associated with using the existing ESPs and the minimal energy impact ofinstalling FGe.the 

### cost ofcompliance 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 $

### 1,544 tor 

### Unit 1, $526 for Unit 2, $857 for Unit 3. Unit 4 didnot require additional capital cost. 2. No negative non
....air environmental impacts are anticipated from existing ESPs with FOC. 

### J. Visibility impacts were addressed ,in a comprehensive visibility analysis covering all , three 'visibility impairing,pollutants and associated control options. The cumulative 3- year averaged visibility improvement from the baseline 

### across the three Class I areas achieved with LNB 

### with separated OFA. upgraded wet FaD, 

### and FGC for enhanced ESP 

### (Post-Control Scenario A) 

### was 1.070 6dV 

### from Unit 1, 0.199 6dV 

### from Unit 2, 

### 1.068 Ll.dV from Unit 3, 

### and 0.892 t,.dV from Unit 4.' While the visibility improvement attributable to the installation ofFGC on existing ESPs can't be directly determined from the visibility modeling, the Division 

### does not anticipate the PM cOl1:tribution 

### to be 

### significa.ntwhen compa.red to 

### NOx and S02 contributions. 

### NPS: WY DEQ has presented no factual basis 

### for this 

### assertion.
WYDEQ: Existing ESP with apolishing fabric filter was not determined to be BART for

, Units 1.:.4 for 

### PMIPMlo**based~** 

### in part, onthe following conclusions:

1. The cost ofcompliance for a polishing fabric filter on ea,ch unit is not reasonable over a twenty year operational life. The cost effectiveness for installing a new polishing fabric 

### tilter 

### on the existing ESP is $8,980 fot' Unit 1, $4,557 for 

### Unit 2, $6,382 for Unit 3, and '$17,936 for 

### Unit 4. Incremental cost effectiveness is $16,396, $16,369, $16,312, and

$17,936 for Units 1, 2, 3, and4, respectively. NPS: WY DEQ should re-evaluate the COHPAC option on the basis ofits ability to achieve a lower limit (e.g., 0.010 Ib/mmBtu) and compare its**cost-eff~ctiveness** to 

### other baghouse installations to properly assess the "reasonableness" ofits cost.
2. The cumulative 3-year averaged visibility improvement from new LNB with separated 

### OFA, upgraded wet 

### POD, and FOC for enhanced ESP with FOC (Post-Control**SC~'1lario** 

### 1) acJ:Oss the three Class I areas achieved with LNB and separated OFA, 

### upgraded. wet FGD, 

### and adding a polishing fabric 

### filter (post-Control Scenario 2) was 0.095**~dv** 

### f)'om Unit 1, 

### 0.090**~dv** 

### from Unit 2. 

### 0.089 lldv from Unit 3 and 0.025 i1dv from Unit4. 

### NPS: None of the opti.ons modeled 

### by PacifiCorp or WY DEQ provide sufticient infonnation to evaluatethe visibility improvement resulting from the COHPAC option.
WYDEQ: The Division cc:msiders the installation and operation oUhe BART-detennincd 

### PM/PMJo controls, existing ESP with FGC, 

### to meet the corresponding emission**Iimit~** 

### nf 0.030 Ib/mmBtu, 180 lb/hr, and 788 tpy on a continuous basis to meet the statutory requirements ofBART. 

### NPS: WY DEQ has notconducted aproper BART analysis because 

### it underestimated the effectiveness ofCOHPAC and did not evaluate.its 

### visibility improvements.

9

AUG-04-2009 15:07 303 969 2822 98% P.2288/82/2889 28:58 383-959-2822**t~PS-ARD** PAGE 23178·



### LONG-TEAAI STRATEGY FOR REGIONAl. HAZE: 

### WYDEQ: Based on the cost of 

### compliance and 

### visibility improvement presented 

### by PacifiCorp 

### in the BART applications for Bridger Units 

### 1-4 and 

### taking into 

### c:onsideration the logistical 

### challenge 

### ofmanaging multiple pollution control 

### installatjon.s within the 

### regulatory time allotted 

### for installation

### ofBART by the 

### Regional Haze Rule, the Division. is requiring 

### the installation 

### ofSCR on Bridger Unit 

### 3 in 2015 and on Bridger Unit 

### 4 in 2016 for 

### the 

### Long-Tenn Strategy 

### ofthe Wyoming Regional Haze State 

### Implern.entation Plan. 

### The Division is also requiring PacifiCorp to 

### submit a permit application to install additional add-on

### NO;..: control 

### on Units 

### 1 and 2 that 

### includes an 

### analysis of: 

### (1) the costs 

### ofcompliance; 

### (2) the 

### time necessary for compliance; 

### (3) the 

### energy and 

### non-air quality 

### .environmental impacts of compliance; and 

### (4) the remaining 

### useful life 

### of existing sources 

### that contribute to visibility 

### impaillllent (i.e., the four statutory factors 

### taken into consideration when establishing reasonable progress goals5) 

### and the 

### associated visibility impacts 

### from the application 

### ofeach proposed 

### NOx control. 

### Each 

### proposed**.~dd-on** 

### NOx control shall achieve an emission rate, on an 

### individual unit 

### basis, at 

### or below. 0.07 

### lb/mmBtu on 

### a 30-day 

### rolling average. The permit 

### application shall be 

### submitted by 

### January 1, 2015. Apditional 

### add-on NOx 

### control shall be 

### installed and operational no later

### than the end of2023 calendar 

### yearon Jim 

### Bridger Units I 

### and 2.

. 

### NPS: As noted above, not only have we shown 

### that SCR can achieve a 

### lower

### NOx limit, 

### it can be 

### installed more-expeditiously 

### than proposed by PacifiCorp.·

### In addition, we are concerned 

### that WY DEQ is 

### setting installation requirements beyond the 2018 calendar 

### year sinc'e that predetermines the outcome 

### of the next round of 

### reasonable progress review required by the

### Regional Hazerule. '

.



### 10

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### National Park

### Sen'ice (NPS) Comments on the Wyoming Department ofEnvironmental Quality's proposed BestAvailable Retrofit Technology (BART) Determination f,r>l" 

### Naughton Power Plant August 3, 2009 

### DESCRIPTION OF BART 

### KLIGJBLE SOURCES 

### PacitlCorp's Naughton Power Plant (Naughton) is 

### comprised of three 

### (3) pulveril',-'J coal-fired Electric 

### Generating Units (EGUs) with 

### a total net generating 

### capacity of 7l)O megawatts (MW). 

### Naughton Unit 1 generates 

### a nominal 160 MW and 

### commenced. operation in 1963. The 

### boiler on Unit I is tangentially-fired 

### and was manufactured 

## by Combustion Engineering 

### (now ALSTOM).The unit uses good 

### combustion practices 

### (GCP) to control**NO~** 

### emissions. 

### It was originally constructed with 

### a Research CottreIl 

### mechanical dust collector 

### to control particulate matter 

### emissions, and in 

### 1974 a 

### Lodge Cottrell 

### electrostatic precipitator (ESP) was added 

### to further reduce 

### particulate emissions. S02 emissions 

### are 

### controlled using low 

### sulfur coal to maintain 

### emissions below 1.2 

### Ib/mmBtu. Naughton Unit 2 

### generates a 

### nominal 210 MW and 

### commenced operation in 1968. The boiler 

### on Unit 2 

### is also tangentially-fired and was 

### manufactured by ALSTOM. 

### The unit 

### uses GCP to control NOx

### emissions. It was 

### originally constructed with a United Conveyormechanical dust 

### collectorto control particulate 

### matter emissions and 

### in 1976 

### a Lodge Cottrell 

### ESP was added to further 

### reduce particulate 

### emissions. 502 

### emissions are controlled using low 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 tangentially-fired and 

### was manufactured by 

### ALSTOM. The unit was retroti.tted 

### with ALSTOM LCCFS II low-NOll: 

### burners 

### (LNB) in 1999. 

### Particulate emissio.ns are controlled using 

### a BueH weighted wire 

### ESP and tlue gas conditioning 

### (FOC).**SO~** 

### emissions 

### are controlled using low 

### sulfur coal 

### and a UOP LLC two-tower**sodium-b<L,,~d** 

### wet tlue gas 

### desulfurization 

### (WFGD) system 

### that was 

### installed in 

### 19C)7.

r 

### PacifiCorp recently received 

### an Air Quality 

### permit to modify the three 

### Naughton units. 

### Units 1 and 2 will be 

### equipped with new 

### state-of-the-art LNB 

### sY$tems wIth advanced overtire air (OFA) and 

### FOC systems to help improve 

### the particulate 

### removal efficiency ofthe existing ESPs. New WFGD systems 

### will be installed on Naughton 

### Units 1 and 2. The 

### existing ESP on 

### Naughton 

### Unit 3 will be replaced with a new 

### full-scal.e 

### fanric filter 

### (FF) at 

### which time the existing FGC system 

### will be removed. Table I lists the new emission limits for the 

### Naughton units. 

### They.become effective 

### after 

### the corresponding controls are installed and the applicable initial performance tests are 

### comp1ete:d.

AUG-04-2009 15:07 303 969 2822 98% P.2408/02/2009 20:50 303-969-2822 NPS-ARD PAGE 25/70

T bl 1 N h U' I 3 P E

a e : llUl!1 ton OIts 

## - roposed mission Limits (a) Source Permitted Controls**NO.~** 802 Pi\1/PM,o New LNB with 0.75 Ib/mmBtLl (3-hr 0.15 Ib/mmAtu ([2- Unit I advanced OFA, rolling) 0.26 Ib/mmBtu month rolling) 1.2 0.042 Ib/mmBtu (b) 78 FGC, ESP, WFGD (l2-month ro] ling) 481 lb/mmBlll (2-hrrolling) Iblhr (b) 340 tpy (b) Ib/hr (12-month rolling) 833 lb/hr(3-hr block) New LNB with 0.75 lb/mmBtu (3-hr 0.15 lb/mmBtu (12- 0.054 IlbhnmBtu (b) rolling) 0.26 lb/mmBtu month roUing) 1.2 Unit2 advanced OPA, (12-month rolling) 624 Ib/mmBtu (2-hr rolling) J30 lb/hr (b) 568 tpy FOe, ESP, WfGD lb/hr(12-monthrolling) 1,080 Ib/hr (3-hrblock) ·(b)

, 0.75 lb/mmBtu (3-hr 0,5 lb/mmBtL! (2-houJ' 0.015 Ib!mmBtu (24- Unit3 Existing LNB with rolling) 0.45 Ib/mmBtu rolling) 1,850 lb/hr (3- hourbh,ck)56lb/hr OFA, FF, WFGD (12-month rolling) 1,665 hrblock) (24-hour block) 243 tpy lb/hr(ll-month rolling)

. 

## . (ll)EmlsSl0ns limits tab:n trom recent New Source ReVlew constructIon permit torNaughton UnIts 1-3

. (\IJ Avr:raging period b Ihouras determined by 40 CFR 60.46and EPA**Rd~NI1CC** Test Methods 1-4 and 5.
A construction schedule for installing new 

### LNB with advanced OFA, FGC, and WFGD on Naughton Units 1 and 2, and a full-scale FF on Unit 3 ,vas submitted in the permit application. The installation of

### fOC on Units 1 and 2 was or ginally proposed to occurin 2008, however since the authorizationto install the controls s depend.ent on the issuance ofthe pendin.g Air Quality permit, in?tallation 

### will be**dela~** ed until permit issuance. A**construc~ion** summary is provided in Table 2. '.
Table 2: Upgrades,to Naughton Units 1-3

Source NO;,: Control Equipment, 502 Control Equipment, PM/PM 10 Control Installation year Installation year Equipment, !ns:tallation year Unit 1 New LNB with OPA, 2012 WFGD,2011 FGC, 2009 (a) Unit2 New LNB with OFA, 201l WFGD,2011 FOC. 2009 (a) Unit 3 LNB with OFA, Existing WFGD. Existing Ff. 20 [4

w Pac:iliCorp originally proposed**in~ialJing** FOC on Units 1 and 2 ill 20D8: however the inswllut[c>n date**ha.~** becl1ll1owd to th«!**dat~** ofp.:rmit**is~uance.** According to EPA's Clean Air Markets (CAM) database. 2007 NO;>; emi!;sions from Naughton were 13,797 rons which ranked the plant #69 in the U.S. 

### BART Analysis for 

### NO! 

### NOx Step 1: IDENTIFY AVAILABLE RETROFIT CON!rROL TECHNOLOGIES WYDEQ: PacifiCorp identified four technologies to contrcl NOx 

### emissiol1S: (1) LNB with advanced OFA, (2) rotating opposed fire air (ROFA). (3) selective non-catalytic reduction (SNCR), and. (4) selective catalytic reduction (SCR). 

## rn addition to applying 

### these control technologies 

### separately, they' 

### can be combine

### d to increase overall NOx reduction. PacifiCorp evaluated the 

### application of LNI with advanced OFA in cornbinati,on with·both SNCR and SCR add-on controls. 

### NPS: We agree that that is a reasonable suite ofoptions.



### 2

AUG-04-2009 15:07 303 969 2822 98% P.2508/02/2009 20:50 303-969-2822**r~PS-ARD** PAGE 25/70



### NOxStep 

### 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS 

### None ofthe four control 

### technologies proposed were deemed technically infeasible.
NO

### x Step 3: EVALUATE EFFECTIVENESS OF REMAINING CONTROL 

### TECHNOLOGIES 

### WYDEQ: PacitiCorp contracted with 

### Sargent and Lundy (S&L) to conduct a 

### study of 

### applicable NOx control technologies 

### for the Naughton units and to collect data from boiler vendors. Based on results from 

### the study, 

### PacifiCorp ind.icates that new LNB with advanced OFA on Naughton Units 1 and 2 would 

### result in a NOxernission rate as low as 0.24 Ib/mmBtu. However, due to unforeseen operational issues associated with retrofitting the boilers, including site specific challenges, PacifiCorp proposes an additional NOx increase of0.02 Jb/mmBtuto total 

### 0.26 Ib/mmBtu. 

### Naughton Unit 3 is equipped with LNB and has demonstrated compliance with a 0.40 Ib/mmBtuNOx emission rate. PacitiCorp reviewed the option oftuning the existing LNB 

### to further reduce NOxemissions and indicates 

### that lowering 

### emissions to 0.35 Ib/mmBtu 

### is possible. 

### In 

### the March 

## 26, 2008, Addendum 

### for 

### Unit 3, PacitiCorp proposed 

# a penuitted rate 

### of 0.37 

### Ib/mmBtu to account for 

### unforeseen operational 

### i.ssues and site 

### specific challenges.
S&L 

### pJ:"epared'the design conditions and cost estimates for 

### installing SCR in eaci i 

### ofthe 

### 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 inthe analysis. Based on 

### the S&L design, which included 

### instaJling both 

### new LNB with 

### advanced OFA 

### and SCR, PacitiCorp concluded the Naughton units could achieve a NOx 

### emission rate 

### of0.07 Jb/mmBtu. The 

### potential NOx 

### control options, and theiremissions are shown in Table 3.

Table 3: NOx Emission Rates Per Boiler Unit 1 Resulting NOx Unit 2 Resulting NO>; Unit3 R.esulting: NCh: Control Technology Emission Rate Emission Rate Emission**Rat~** (lb/mI'l1Btu) (lb/mmBtu) (lb/mmBtu)



# -- Existing Burners 0.58 (a) 0.54 (a) OA5 (b)

....

# _- Tune Existing LN8



### -- 

# -- 0,37 New LNB with advanced OFA 0.26 0.26


## -- Existing Burners with ROFA 0.26 0.26 0,28 New LNB with advanced OFA 0.2l 0.2 J 0..3 and SNCR



# -- New LNB with advanced OFA 0.07 0,07 0,07 and SCR (a) Annual,averaged NOx emissIons listed In Opera.ting Pennlt 31-121. (b) Annual averaged NOx emission listed in Operating Permit3-2·121. 

### NPS: PadfiCorp 

### and WY ,DEQ 

### have underestimated the ability ofSCR to reduce emissions. For example, for the. LNB/OFA+SCR 

### option, PacifiCorp**as:~umed** 

### 0.07 lbimmBtu for all operating periods. However, WY DEQ has issued permits for new

3

AUG-04-2009 15:07 303 969 2822 98% P.2608/02/2009 20:50 303-959-2822 

### NPS-ARD PAGE 27170



### EGUs requiring that they meet 0.05 lb/mmBtu over averagin¥ periods of24-hours I 

### and 3D-days.::! FurthenTlore, EPA's Clean 

### Air Markets (CAM) clata (Appendix A)' and vendor guarantees4 

### show that 

### SCR can typically meet 0.05 lb/mmBtu (or lower) on an annual average basis. Paci1iCorp has not provided any documentation orjustification to support the higher values used in its analyses. Based on the proposed NOx emission rates, outlet emissions at 0.07 

### lb/mmBtu represent 

### a 73% reduction from the 

### LNB/OFA emission estimate for Units #1 & 

### #2, and 84% from SCR 

### on Unit#3, as opposed to the generaIlyaccepted 90% for a well-designed system. Our review ofoperating data (included in the tangential boilers portion ofAppendix A) suggests that a 

### NOx limit of

### 0.06 lb/mmBtu is appropriate (with a safety-margin) for 

### LNB/OFA+SCR for a 3D-day rolling average, and 0.07 

### lb/mmBtu for 

### a24-hourlimit 

### and formodeling purposes, 

### bLlt·a lowerrate (e.g., 

### 0.05 Ib/mmBtu orlower) 

### should be 

### used for 

### annual average and 

### annual cost 

### estimates.
NO

### xStep4: 

### EVALUATE IMPACTS AND DOCUMENT RESULTS


### NPS: PacifiCorp and WY DEQ have overestimated the costs of 

### SeRe Neither Pac.itiCorp nor WY DEQ providedjustification or documentation for their cost estimates. We were 

### not provided with any 

### vendor estimates or bids, and 

### PacifiCorp and WY DEQ did 

### not lise 

### the Control Cost Manual. 

### According to information provided by 

### PacifiCorp an.d WY 

## DcQ, at Naughton #1:



### • SCR

### would reduce**NO~** 

### by 73% and result in an 

### annual emission rate·of0.07 Ib/mmBtu.

• SCR 

### capltal cost would 

### be $5311kW. This result is much 

### higherthan suggested 

### by available literature (see Appendix C cost summaries) which suggests SCR costs ranging from $50

- $267/kW. PacitiCorp has provided no justificati.on for these extraordinarilyhigh costs.

• The Average Cost would be $2,750/ton.

• The Incremental Cost would be $8,089Iton. At Naughton #2:

• SCRwould reduce 

### NO" by 73% and 

### result in an annual emission rate of0.07 

### lb/mmBtu.

• SCR capital cost would be $509/kW. 

### This result is much higher than suggested 

### by available literature (see Appendix C cost summaries) which suggests SCR costs ranging from 

### $50

- $267/kW. PadfiCorp 

### has provided no justification for these extraordinarily high costs.

I Basin Electric-I)ry Fork 2 WYG£N3

We found at leasr20 examples (Please see Appendix A., Table A.I.) ofmngenIially-fired boilers similar to rhose at Naughton that have been retrofitted with SCR and are**achi~ving** annual emission rates below 0.06 IbfmmBtu. We were able to find 2006 hourly emissions in EPA's CAM database for ten ofthose EGUs, and charts showing those errrissions are included in the tangential boilers pOliion ofAppendix A. We**beli~ve** that inspection ofthe data leads to the conclusion that these SCRs retrofit to eastern ECUs burning bitllminous coal can typically reduce NOx**emission~** by 90% and ach·ieve 0.05 Ibfli1rnBtu (or lower) on a 30.day rolling average basis during the eastern ozone season.
. .

Minnesota Powerhas stated in its Taconite Harbor BART analysis that "The use ofall SCR is expected to achieve a NOx emission rate of 0.05 Ib/mmBtu ba.sed on recent emission guarantees offt:red by SCR system supplie.rs,'·



### 4

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### • The Average Cost would be $2,848/tol1.

• Th·e Incremental Cost would be $7,852/ton. 

### AtNaughton #3:

• SCR

### would reduce NO:< by 84% and

### resultin 0.11 

### anmJal emission rate ofO.07 

### Ib/mmBtu.

• SCR capital cost would be $415IkW;This

### resultis muchhigherthan suggested 

### by available literature (see Appendix C cost summaries) which suggests SCR costs

. ranging 

### from $50

- $267/kW. 

### PacifiCorp has provided no justification for 

### these

extraordinarily-high costs.

.
• The Average Cost would be $2,830/ton.

• The Incremental Costwould be $1,783/ton.
As recommended 

### bythe 

### BART Guidelines, we applied the OAQPS (\,ntrol Cost manual to the Naughton EGUs. (Please see the Naughton workbooks in A.ppc·ndix: C.) We 

### assumed that LNB/OFA+SCR would 

### result in an annual 

### emission rate of0.05 lb/mmBtu. At Naughton. #1:

• SCR would

### reduce NO:< by 

### 81%.



### • SCR capital cost would be $102ikW. 

### This result is much more consistent with available literature (see Appendix C cost summaries) which suggests SCR c.osts ranging from $50

- $267/kW.



### • The**Avera~e** 

### Costwould be $1,073Iton. The cost ofadding SCR to LNB+OFA would be $1,735/tc'ln. At

### Naughton #'2:



### • SCRwould reduceNO;.: by 81 %. 

### .• SCR capital cost would be $92/kW. This result is m.uch more consistent with available literature (see Appendix C cost summaries) which suggest; SCR costs ranging from. $50 -·$267/kW.



### • The Average Costwould be $9821ton.

e. 

### The costofadding SCRto LNB+OFAwo'Uld be $1,

### ,676/ton. At.

### Naughton #3:



### • SCR would reduce

### NO:,< by 

### 86%.

• SCR capital cost would be $61/kW. 

### This result is· much more consistent with available litet:ature (see Appendix C cost summaries) which suggests**~CR** 

### costs ranging from $50

- $267/kW.



### • The cost ofadding SCR would be $860/ton

.

.As a 

### result of higher emission reductions5 

### and lower Total Annual Costs. OLlr

.

### costeffectiveness6 

### estimates are much lowerthan estimated

### by WY DEQ.

We based our a.nalysis on the annual limits proposed by WY DEQ whkh :lppear to represent 10Cl%, utili7.atiol1. GWe believe thar the comparison ofcosts and benefits for adding SCR to LNB+OFA is the most valid lest for incremental cost-effectiveness because these are the two most-likely candidates for BART.



### 5

AUG-04-2009 15:07 303 969 2822 98% P.2808/02/2009 20:50 303-959-2822 NPS-ARD PAGE 29/70

Even though 

### PacitiCorp and WY DEQ have overestimated the cost ofSCR; WY DEQ 

### determined that "the cost effectiveness and incremental cost**eff~ctivenes,5:** 

### ofthe four proposed BART technologies for NOx are aU reasonable." 

### NOxStep 5: VISIBILITY IMPROVEMENT DETERJ\1INATION 

### WY DEQ: Bridger Wilderness Area 

### (WA) and 

### Fitzpatrick WA in \Vyoming are the closest Class 1 areas to the PacifiCorp Naughton facility. Bridger WA is located 

### approximately 140 kilometers (km) northeast ofthe facility 

### and Fitzpatrick WA is located approximately 165 km northeast 

### ofthe facility. 

### Only those Class I areas 

### most likely to be impacted by the Naughton Power Plant sources were modeled, as detennined by 

### source/Class Tarea locations, distances to each Class 

### I area, 

### ,and professional judgment considering 

### meteorological and terrain 

### factors. It can be reasonably assumed 'that areas at 

### greater distances and in directions of

### less frequent plume 

### transport

### will experience lower 

### impacts than

### those predicted 

### forthe modeled 

### areas. 

### NPS: While we agree with 

### WY DEQ's assessment that the modeJing analysis has likely captured the greatest impacts, we are also interested in tbe cumulative impacts on all 

### Class I areas within 300 

### km. 

### Therefore, we typically request that 

### all Class I areas within 300 

### km ofthe source 

### be included 

### in the 

### modeling analysis. In this case, 

### in addition to 

### the 

### two Class I areas 

### noted by WY DEQ, we 

### recommej1d that impacts at Grand Teton National Park (NP), Yellowstone NP, Craters 

### of the Moon National Monument, 

### Washakie Wilderness Area 

### (WA), and Teton 

### WA be includedinthe 

### modeling analysis. WY

### DEQ: Wl1ile visibility 'impacts were addressed in a cum:ulativeanalysis ofall three pollutants, 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' 98th percentile values from 

### each other yield the incremental 98th percentile visibility 

### improvement from SCR. The cumulative 3-year 

### averaged 98th percentile, visibility 

### improvement from Post-Control Scenario A across both 

### Class I areas achieved with Post-Control Scenario B was 0.405 bdv from Unit 1 and 0.506 i1dv 

### fI'om Unit 2. Modeled 98th percentile visibility results 

### from Unit 

### 3 Post-Control 

### Scenario B are directly comparable to those fi'om Post-Control Scenario A, as the only difference is directly attributable 

### to the installation of SCR. The c1.UTIulative 3-year averaged 98th percentile 

### visibility improvement across the 

### two Class I 

### areas achieved 

### by installing SCR 

### on Unit 

### 3 

### was 1.023 lldv, approximately twice the 98th percentile visibility 

### improvements, 

### 00405 i1dv from Unit 1 and 0.506 

### 6.dv from Unit 2, using Post-Control Scenario B which included installing SCR. 

### NPS: 

### The WY DEQ approach 

### provides only the incremental improvement in visibility resulting from addition of SCR to the proposed/installed combustion controls. The total improvements resulting from combustion controls pl1.is SCR can be found by subtracting Post-'Control Scenario B 

### from the Baseline 

### casco The average 98th percentile visibility improvements from LNB/OFA+SCR are 2.1 bdV from Unit 1,2.4 bdV 

### trom Unit 2 apd 

### 1.8 6.dV 

### troTI:J, Unit 3.



### 6

AUG-04-2009 15:07 303 969 2822 98% P.2908/02/2009 20:50 303-959-2822 t,jPS-ARD PAGE 30/70



### BART CONCLUSIONS: 

### NPS: Paci±iCorp apparently considered. costldV a uSeful metric 

### when it made the following statements: Unit 1: "

... 

### the incremental cost effectiveness for Scenario I compared to the Baseline is reasonable at 

### $400,000 per day 

### and $11.1 million per dV to improve visibility at 

### the Bridger W A.'; Unit 2:"'

... the incremental cost-effectiveness for Scenario 1 compared 

### to the Baseline is $450,000 per

### day and $13.96 million per dV to 

### improve visibility at the 

### Bridger W

### A." Unit 

### 3: "

... the incremental cost-effect;veness for Scenario 

### 1, compared to the 

### Baseline, is reasonable at $70,000 per day and $4.08 million per dV to improve visibility at the Bridger 

### W A."


### WYDEQ: LNB with 

### advanced OFA 

### is determined to 

### be BART for**Ut1it~** land 2 

### for NOx 

### based. in 

### part. on the following conClusions: 

### 1. LNB with advanced 

### OFA on Units.l

### and 2 was cost effective with 

### a capital. cost of**$9~600,OOO** 

### and $9,1 00,000 per unit: respectively. The average cost effectiveness, over 

### a twenty year operational life, 

### is $426 per ton of

### NOxremoved 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 ofthe five statutory factors. especially the 

### C0stS of compliance and the existing 

### pollution control equipme·nt, a NOx control 

### level .of 0.26

. lb/mmBtu 

### on a 30-day rolling 

### average, above'EPA's established presumptive limit 

### of 

### 0.15 Ib/mmBtu for 

### tangential-fired boilers 

### burning sub-bituminous coal, though not applicable, isjustified. , 

### 4. Visibility 

### impacts were addressed in a compr.ehensive 

### visibility analysis covering all three visibility 

### impairing pollutants and 

### associated control options. The 

### cl.ffimlative 3- year 

### averaged 98th percentile 

### visibility improvement from the 

### baseline summed across 

### both Class I areas achieved with LNB with advanced OFA, wet FGD, and**(~xisting** ESP with FGC (Post-Control Scenario A) was 1.716 Adv from Unit 1 and 1.934 .6.dv from Unit 2.

.. 

### 5. Annual 

### NOx emission reductions from baseline 

### achieved by 

### applying LNB 

### with advanced OFA on 

### Units I 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 land 2 for 

### NOx based, "in part, on the following conclusions: 

### 1. The cost of compliance for installing SCR on each unit 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 

### costs for Unit 1 are $1,231,912 

### and $1,639,352 for 

### Unit 2. 

### NPS-WY DEQ 

### determined that "the cost effectiveness 

### and incremental cost effectiveness ofthe four proposed BART technologies for NOx**~lre** 

### all reasonable." 2. Additional non-air quality environmental mitigation 

### is required ror 

### theuse ofchemical reagents.



### 7

AUG-04-2009 15:07 303 969 2822 98% P.3008/02/2009 20:50 303-%9-2822**~~PS-ARD** PAGE 31/70



### 3. Operation of

### LNB with 

### advanced <DFA and SCR is parasitic and requires an estimated 

### 1.0MW 

### from Unit 1 and 1.3 MW 

### from Unit 2. 4. While visibility impacts were

### addr~:ssed in a 

### cumulative analysis of

### all three pollutants, 

### Post-Control Scenario B is directly comparable 

### to Post-Control. Scenario 

### A 

### as the 

### only difference 

### is directly 

### attributable TO**th~** 

### installation 

### ofSCR. Subtracting the 

### modeled 98th

.percentile values 

### from each other i

### yield the incremental 98th

### p~rcenti!e 

### visibility improvement from 

## seR. The cumqlative 3-ycar 

### averaged 98th percentile 

### visibility 

### improvement from 

### Post·Contro] Scen¥io 

### A

### across both Class I

### areas achieved with 

### PostControl Scenario 

### B was 0.405 Dodv 

### from Unit 1 

### and 0.506 lldv 

### from Unit 2. I I I 

### Tuning the existing LNB 

### with OFA 

### and installing 

### SCR is determined 

### to be BART 

### for Unit 3

### forNOx based, 

### in palt, 

### on 

### the f&llowing conclusions: 

### 1. The cost effectiveness 

### oftuning 

### tne existing LNB with 

### OFA and installing SCR 

### on Unit 3 

### was reasonable at 

### $2,830 per ton 

### of NOx removed. 

### The incremental 

### cost effectiveness when compared to 

### existlng 

### LNB with ROFAwas 

### $1,783 per ton ofNO,I( 

### and reasonable as well. 

### Both the costi effectiveness and 

### average cost 

### effectiveness were based on a

### twenty year operationallifelfor 

### the proposed controls,

. 

### 2. The cumulative 3-year averaged 

### :98th percentile visibility improvement 

### from the baseline summed 

### across both 

### Class 

### Ii areas achieved by 

### tuning the existing 

### LNB with OF

### A, wet 

### FGD and installing 

### a new ftill-scale fabric filter, 

### Post-Control Scenario 

### A, was

. 0.826

### ~dv from Unit 3. Units 1 and:2 

### yielded notably 

### higher visibility improveInents



### from 

### baseline; 1.716 t.dv and 

### 1.934**~dv,** 

### respectively, 

### lli;ing Post-Control Scen.ario 

### A which included .oew 

### LNB with**advanc~d** OFA, 

### but not 

### SCR.

. ,. 3. Modeled 

### 98th percentile visibility 

### Iresults 

### ·from Unit 3 Post-Control 

### Scenario Bare directly comparable to 

### those from Post-Control Scenarit' A, 

### as the only difference 

### is directly attributable 

### to the

### installatio~ of SCR. The cumulative 

### 3-year 

### ave:raged 9&th percentile visibility improvement

### acro~s the two Class 

### Iareas achieved by ins'talling 

### SC.R on Unit 3 

### was 1.023 Lldv, approxjrnately 

### twice the 98th percentile visibility improvements, OA05 

### .6.dv from**U~it** 

## i and 

### 0.506 o.dv from Unit 

### 2, using Post-Control Scenario 

### B 

### whichincluded installing SCR. 

### 4. The cumulative 

### 3-year averaged 98th percentile visibility 

### improvement t)'om 

### the I 

### baseline 

### summed across 

### both Class 

### I

### iareas achieved by tuning 

### rhe. existing LNB· 

### with OF

### A, SCR, wet FOD, and installing 

### ainew full-scale fabric 

### tllter, 

### Post-Conrr(ll. Scenario 

### B, was 

### 1.849**~dv.** This visibility imprbvement is 

### less than 

### the improvement achieved 

### by Post-Control Scenario A 

### using new 

### LlNB and advanced OFA 

### on Unit 2, 1.934**~dv.** 

### but higherthan Post-Control Scenario A using new 

### LNB and advanced OFA on Unit 

### I, 1.716 

### t.dv. , 5. Annual NOx emission reductions 

### from baseline achieved by 

### tuning existing 

### LNB with OFA 

### and installing 

### SCR are 5,542 tqns as compared 

### to only 1,167 tons 

### firom tuning existing LNB with OFA. : 

### 6. After 

### careful consideration 

### of the five 

### statutory factors, especialJy 

### the 

### costs of compliance and the existing pollutioni conrrol equipment, a NOx control level of

### 0.37 Ib/mmBtu 

### on a 3D-day rolling averagejfor Unit 3, above EPA's eSlablished 

### presumptive limit of0.15 lb/mmBtu for 

### tangemia1-nred boilers burning sub-bituminous coal, though not 

### applicable, is 

### notjustitied. I



### 8

AUG-04-2009 15:07 303 969 2822 98% P.31B8/B2/28B9 2B:5B 383-959-2822**t~PS-ARD** PAGE 32/78

I The 

### Division considers 

### the installation and 

### operation of the

### .BART~detennined NOx control.s, new LNB with advanced OFA 011 Units 1 and 2 and tuning existing LNB with OfA and installing SCR on Unit 3

# tq meet corresponding emission limits on a 

### continu.ous basis, to meet the statutory requirements ofBART. 

### Unit-by-unitNOx

### BART

## detennjnat~ons: Naughton Unit I: Installing new LNB with advanced OFA and meeting 

### NOx emission limits 

### ofO.26Ib/mmBtu (30-day 

### rolllng average), 481 lb/hr**(30~day** rolling average), and 

### 2,I07 tpy as 

### BART 

### forNOx. : Naughton Unit 2: Installing new 

### LNB with advanced OFA and meeting NOx 

### emission limits of

### 0.26 Ib/mmBtu (30-day 

### rolpng average), 624 /hr (30-day rolling average)," a.nd 2)33 tpy as BART for NOx..

. Naughton Unit 3: Tuning existing LNB with 

### OFA and installing SCR meeting 

### NO>:: 

### emission limits 

### of 0.07 Ib/mmBtu (30-day rolling average), 259 

### lb/br (3D-day roIling average), and 1,134 tpy as BART 

### foriNOx.
NPS: Using the 

### Control Cost manuai as recommended 

### by EPA's BART Guidelines, we have estimated the average cost of!installing combustion controls plus SCR at less than $800/ton, 

### and the incremental!cost 

## ofadding SCR to the proposed combustinn controls 

### at less

### th~lO Sl,OOO/ton. Cohsidering that 

### WY DEQ found that 

### the much 

### bigher estimates proVided by 

### PacifiCorp w,ere 

### "'reasonable," we can' only 

### cOJ1cJude that our estimates indicate that addition of

### SCR is even more '"reasonable."


### In its BART 

### analyses, PacitiCorp stated that costs per deciview 

### of $4 

### million

- $14 million per deciview are**"reasonable~"** and it 

### is even reasonable to spend $31.7 

### million

. per dV to reduce NOx emissions at**~ts** Dave Johllston power plant. 

### Furthermore, these

PacifiCorp conclusions arc consisterit with those reached across the 

### country7 that the average cost per dV proposed 

### by! either a state or a BART source is $10

- $17 million, with a maximum of almost! 

### S50 million per dV proposed 

### by Colorado at the Martin Drake power: plant.

. 

### Combining the modeling results

## p~ovided by WY DEQ (which we believe 

### have underestimated SCR benefits) and 

### 6ur cost analyses based 

### upon EPA guidaJ.1ce, \

....e estimate that addition ofSCR at 

### each of

### the Naughton units 

### would improve: visibility at 

### a cost ofless than 

### 511 million per

## dV at the Bridger Wilderness Area. 

### alone and 

### for less than $9 million per dV across 

### the two Class I areas evaluated by WY DEQ, 

### Not only is addition ofSCR

### cost~effectiv~ by 

### these 

### criteria, it would be even more so 

### ifthe issues we have noted above are

### addre~sed.

, 7 http://www.wrapair.org/fol.ums/ssjf/bart.htm1

9

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### BART AnaJvsis for 

### PMJ/l PMIQ Step J: 

### IDENTIFY AVAILABLE RETROFIT 

### CONTROL

### TECHNOLOGIES Three PM control technologies**wer~** 

### analyzed for application on the three 

### Naughton units: 

### fabric filters orbaghouses, 

### ESPs, and flue gas conditioning (FGC).
PM1u Step 2: ELIMINATE TECHNICALLY INFEASIBLE 

### OPTIONS 

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

### the impact of installing FGC using the existing ESPs and installing apolishing fabric 

### filter downstream. ofthe existing ESPs on Naughton Units 

### 1 and.2. PacifiCorp artalyzed the impact ofinstalling a full-scale 

### fabric filter onUnit 3.

. 

### PM10 Step 3: EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES 

### WYDEQ: Naughton Units I and 2 have existing 

### ESPs and rather than evaluate costs of replacing· 

### them, PacifiCorp evaluatediadditional controls to improve the 

### PM IO removal

. I

. 

### efticiency. Rather than dem.olishing**t~e** 

### existing ESP and constructing an 

### e:atirely new PM control device, PacifiCorp recognized the cost 

### benefit ofkeeping the 

### existing ESP and augmenting 

### the control. 

### Installing FOC on Units 1 

### and 2 can improve the 

### PM removal efticiencies on the existing**~SPs** 

### down to 0.040 Ib/mmBtu. A polishing fabric filter can be 

### installed downstream of

### the existing 

### ESPs. PacifiCorp proposed. the 

### use of Compact 

### Hybrid Particulate Collector!(COHPAC). PacifiCorp estimates the application of 

### the COHPAC unit, in addition to I 

### using 

## Foe with the existing 

### ESPs, can reduce 

### emissions an additional 63% resultimg in a PM emission rate 

### of 0.015 lb/mmBtu. Demolishing the existing ESPs and installing a new full-scale fabric filter pn Units 1 and 2 is anticipated to control 

### emissiorui down to the same PM emission**le~vel,** 0.0 15 

### Ib/mmBtu as installing apolishing fabric 

### filter downstream ofthe existing ESP.

. I I Naughton 

### Unit 3 is currently 

### equipwed with an ESP and 

### FGC system. PacitiCorp analyzed the impact 

### ofupgrading the ':existing FGC and resulting impact of

### installing a 

### new fun-scale fabric filter.**PacifiCorp~s** 

### proposed emission rates for each technology as applied to Naughton Units 1-3 are sh0'1nin Table 4.

Table 4: PM)0 Emission Rates Per Boiler

I Resulting PMfll Emission Race (lb/mmBtu) Control Technology i Existing ESP i 0.056. 0.064, 0.094 (a) Existil1g ESP with FGC 0.04 ; Existing ESP and New Polishing Fabric Filter(b) 0.015 Full-scale Fabric Filter (c) , 0.015 , I (a) Currenr achievable PMwenmsions from Uriit 1,2, and 3, respectively. (b) Applied to Naughton Units 1 and 2.

. (c) Applied [0 Naughton Unit3.



### 10

AUG-04-2009 15:07 303 969 2822 98% P.33B8/B2/2BB9 2B:5B 3B3-%9-2822 riPS-ARD PAGE 3417B



### NPS: Considering 

### that 

### WY DEQ has issued at least three permits8 l(lI' 

### new BOUs with fabric filters 

### limited to 

### O.0121b/mmBtu. WY DEQ should explain why 

### the COHPAC and full-scale fabric tilter opti,ons caMot 

### achieve the same limit, or the 0.0 1

# aIb/mrnBtu limit permitted by EPA**~or** 

### the Desert Rock powerplant.


### PMu) 

### Step 4: EVALVATE IMPACTS AND DOCUMENT RESUL

### IS WYDEQ: The cost 

### effectiveness and incremental cost 

### effective'ness ofapplying a new 

### polishing fabric tilter to 

### Uni,ts 

### land 2 are not reasonable, The cost effectiveness and incremental 

### cost effectiveness 

### ofapplying 

### a new 

### full-scale fabric fllter to Unit 3 arc also not 

### reasonabl.e, However, the control was included in the final step in the' PM/PM I() 

### BART determinationprocess forNaughton Units 

### 1-3. NPS: 

### WY DEQ should re-evaluate the COHPAC option on tbe basis of its ability to achieve a lower 

### limit (e.g., 

### 0,010 lb/mmBtu) and compare its cost-effectiveness to 

### other baghouse installations to properly assess the "reasonableness" ofits 

### cost. 

### PM10 Step 5: VISIBILITY IMPROVEMENT DETEAAHNATION NPS: 

### None of the options 

### modeled by PacifiCorp or WY DEQ provide sufficient information to 

### evaluate the visibility improvement resulting from 

### the COHPAC 

### option.
BART CONCLUSIONS: Wy DEQ: 

### Existing ESP with FGC 

### is determined to be BART for Units 

### 1 Clnd 

### 2 for PM/PMlo based. in part. on

### the following conclusions: 

### L Recognizing the cost benefit associated with 

### using the existing 

### ESPs and 

### the minimal energy 

### impact

# ofinstalli.ng FOe, 

### the cost ofcompliance for the 

### control technology is' co:,t effective for each unit, over 

### a twenty year 

### ope'rational life, for reduc.ing 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 

## Foe. 3. Visibility impacts 

### were addressed in a comprehensive visibil

### ity analysis 

### covering all 

### three visibility impairing pollutants 

### and associated control options. 

### The cumulative**3~** year averaged 98th percentile visibility improvement from the baseline summed across both Class 

### I areas achieved 

### with LNB with advanced 

### OFA, wet FOD. and existing CSP with FGC (Post-Control Scenario, A) was 1.716 lJ.dv 

### from Unit 1**~lnd** 

### 1.934 ,6.dv 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 does not anticipate 

### the PM contribution 

### to be significant 

### when compared 

### to NOx and S02 contributions. 

### NPS: WY DEQ has presented 

### no factual basis 

### for this assertion.



### , WYDEQ: Existing ESP with FOC and a polishing fabric 

### filter was not determined to be

BARTfor Units 1and 2 for PM/PM]() based, in part, 

### on the 

### following conclusions: 1. 

### The cost ofcompliance 

### for apolishing fabric fijter on each unit is notrea<;ona1)lc, 

### over a twenty year operational life. 

### The cost**~ffectiveness** for installing a ne", polishing 

### f'\bric

g WyCEN2. WYGEN3, Basin Electric-Dry Fork



### 11

AUG-04-2009 15:07 303 969 2822 98% P.3408/02/2009 20:50 303-959-2822 I'JPS-ARD PAGE 35/78

filter on the existing ESP is $8,848 for Unit 1 and, $11,494 for Unit 2. Incremental cost effeeti.veness is $17,748 for Unit 1 and $16,431 for Unit 2. 

### NPS: WY DEQ should re-evaluate the COHPAC option on the basis of its ability to achieve a lower limit (e.g., 0.010 Ib/mrnBtu) and compare its cost-effectiveness to other baghouse installations to properly assess the "reasonableness" ofits COSt. 

### WDEQ: 2. The cumulative 3-year averaged 98th percentile visibility improvement from applying a polishing fabric filter can be calculated 

### by subtracting Post-Control Scenario 

### 2 results from Post-Control Scenario 1 results and summing across both Class I areas. The achieved 98th percentile visibility improvement was 0.266 6.dv from Unit 1 and 0.352 .6dv from Unit 2. 

### A new full-scale 

### fabric filter is detennined to be BART for Unit 

### 3 for PM/PMIO based; in part, on the following conclusions: 1. While the Division considers the cost of compliance for a full-scale fabric filter on Unit 3 not reasonable, PacifiCorp is committed to installing**~is** control device and has pennitted the installation ofa full-scale fabric filter on Un't 3·in a recently issued New Source,Review construction peImit. A full-scale fabric filter is the most stringent 

### PM/PM!() control technology and therefore the Division will accept it as 

### BAnT.
The Division considers the installation and operation ofthe**BART-deter:min~:d** PM/PM '0 controls, existing ESP with FGC on Units 1 and 2 and·a new full-scale fabric filter on Unit 3 to ·meet corresponding emission limits on a continuous basis, to meet the statutory requirements ofBART. Uni.t-by-unit PM/PM10 BART detenninations: Naughton Unit]: Installing 

### FOe on the existing ESP and meeting 

### PM/PM,o emission limilS of0.040 Ib/mmBtu, 741blhr, and 324 tpy as BART 

### foi

### PM/PMlo.

. Naughton Unit 2: Installing FGe on the existing ESP and meeting PM/PM 10 emission limits of0.040 Ib/mmBtu, 

### 96lb/hr, and 421 tpy as BART for PM/PM 1o• Naughton Unit 3: Installing a new full-scale fabric filter and meeting 

### PMJPM10 emission limits ofO.015Ib/mmBtu. 561b/hr, and 243 tpy as BART for

### PMIPMlo. 

### LONG-TERM STR..\TEGY

### FORREGIONAL HAZE WYDEQ: Based 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 ofmanaging multiple pollution control installations within the regtllatory time allotted 

### fOJ:' installation ofBART by the Regional Haze Rule, the Division is not requiring additional controls under the Long-Term Strategy of the Wyoming Regional Haze Stare Implementation Plan in this pennining action. Additional controls may be required in future actions related to the Long-Term Strategy of the Wyoming Regional Haze State Implementation Plan. 

### NPS: As noted above, not only have we shown that SCR can achieve a lower NOxlimit, it can be installed more-expeditiously than proposed by PacitiCorp.



### 12

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# Appendix A: SCR.Effectiveness on Eastern EGUs

AUG-04-2009 15:07 303 969 2822 98% P.36D m

C 

### "' G)**~0** I 

### "' IS) rableA.1. 21107 C1tdHiNd boll.". w SCR & NOx leu IhIAO.Oillb pammElu dUrll1g alOM season fo,J .l'>. NUM PRIMARY OP I ORISI'L_ 1<SSOC_S PRG_CODE SU\\ 01' .\lOlITh'S NOX NOX HiiAT FUEt SrAlUS I\.l STATE FACILlN_,'/A'Af. CODE UNIlID OPYEAA**IAC~S** _IUFO TIME RE.!'CA'lTED RAlE MASS II/PUT INFO UNIT TYPE INfO IlOXCOJIlROL IPIfO l/IFO LD IS) IS) HC**BcI~** ...."C,...-l<**~42** 1 1007 N8P,ARP ),55S 5 O.OJ**4~3 3~,842.308**  Caal C41l butnerboll", Low "·OK. Cell**BU~I** Ol/1l!1 Opl!'laling ti) OH Mu,klnglUTlRh'" 2812 5 2001 NBP,ARP ).015 5 0.1)5 31105 14,121,1I1i**Co~1** Cell bu"",rboiler Low /fOx C"II**Bum~t** Sele Op«aling fo,J 011 Cautina' UU 2 1001 NBP,ARP 2,890 5 O.OOS 32.0 tJ,!I4J.S6Z Cual Cell bUnlerbollel LaN110" Cell Bu,,",,, Sele- Ojle",Ung

....... 011 ,ifolml FortGOO210lh19 St41ioD U)2 7 200T N8p,ARP 3,45' Ii 0.05 357**13,55~,.(O7** Cod Cell bu,narboll•• (Entlel! 0'1 I lo'H 'lOx Cell Bwn., s..1e- Op

.....llng 

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## .. OH Car,l"nol 262a 3 200] NBP,ARP**~.5n** 5 002 223 19.67'.000 Co.1 01'1 bo&.Jmwall-sred 00 lei Lr'" P<OJ( ItJrn., r"dln"n..J:Opelafnll IS) VA ChaSapl!8heEnerg,.Cl!n!ol :l800 3 2007 NHP,ARP 3.545 !> 0.03 68 MI6J.J61 Coal bet'.olilwaU-!ll1ld toler Low reo.. &Jm" Tedlndll9:0PilJafng -oJ IN Gibson 6113 1 200] CSIlOO3 NBP.AFlP :I,Wi) S 0.G3 J.52 21,005,175 Coal baltomwaU.fi11ld b<iler LI7I/reo

.. &Jim, rec.»nGlO!l**Opata\n~** KY**Mi~CreEk** 13<;( 4 2W] NBP,ARP :1,007 5**O.o~** 2;4 14.95!l.778 Coal cry l>olIomwall.n'Ed b",l

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.... al-fi'.dboile' l..:twNO): BLni.eJ 1 ed\I1uloO'0P4tatir..g I IlA Bc"'(.a' Print 1619 :I 2007 ARP.NBP M7() 5 0.04 2B3 11.611.691 Coal 'Cry oonom\val·ftr-erfbQile:f LONNOr. BL"01":', i**e(t:'flDI~:** Operating LD Vtl JoMEAmO<l 3935 

# , 2lJUl C&U2**"'DP.~.IlP** 3.3-2:2 5 0.05 4&7 20.100.3:([ Coal Dry I;ollo>.

..wal-firedb.i1.r lo"NOx Bum.,.. 'ec./ll1<llag:o.perating (J1 Vtl**F1eqsonl~** fuM' Sta'.'on 6004 2 2<llTt I;BP,**~.RP** 3.m 5 0.05 J67 15..4lt4.ii12 COOl Ory I:OIIOIRVial·firedbeiler taA'NOx Burne<Tedm"n;\,Operating LD I K'\' MilOrea' 1364 J 2(107 IIBP,MlP J,5<I\J ,5 0.05 '337 14.245.770 Ory 1:011001 wall·firedbillieI LaKN')x Burner hchnol:la'4lS1aUng fo,J VI'I Joh.E,>.tnos 3005 2 2()07 =12**N8P,~.RP** 3A4a 5 0.05 5;)6 21,140.5)2 CoO<! Dry bollcm ,Yo<Jl-nr;v.! bolle' lCi
....NOx Burner rechr-,..,,-'osI:Opefaling m OH Miald Fon**G~nan;.~nll** SlatillO 2aJ:l 8 2007 Ij8P,ARP 3,4:;9 5 0.05 419 15.742'.714 Coa Orf**~ollom** Viell-fir;l$ boiiel Selediv",Cata::ytic R"dl<L./io Cp.!sali.'!1 fo,J IL Hli'lMa 89' 9 :2<107 118P,ARP 3.01J ,5 0.00 19-4**14.0J4,5-4~ Co~**  01)' bollc<n\Wll-lV<d lHli\o( (Elie,**Oy~rfir"** I\rSeIoct>'

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... SWIEn S7n 5 2007 NOP,ARP J.554 5 0.05 :<24 9,9tJ.$,6Tl C.el**T~ng.nllally.jlred** lo

... NO. BwnOJ Tacllnol. Op.,...linll ti) Al Widowli Creek 50 - 8 2001 HBP,ARP 3,474 5 0.05 315 1",513,071 Co.oI T

..genlially

....red low f'..lDIC BIlIt1e" Te£nncf( Opll1f.tH119 1/( Klngslon 3407 5 20<l7 CSKIfS !lBP.ARP 3,198 5 0.05 14'**&,U~,lo;~** Co.oI Tan-ae"'i11l1y-4lred Low NOx BumHTcl;hnc[( OpudHng I\.l TN Klngslon :407 1 2007 CSIlIIS**~BP,ARP** 30612 5 0.05 114**4,SS~.3&1** Ct>.ll TlngcnlJ.olly-lired 5<o100ll.e Ca/oIYli" Ro!duel Op

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....ling I\.l TN KjngslOA 34B7 3 1007 eSKI16 IIBP.ARP 3,385 5 0_05 IDS .4,199,858 CNI TlngenJlally-fired Selective CatalyHc**Recfu~1** OptJrating TN Klng"o. 3407 4 2001 CSKII5 IIBP, AAP 3,612 5 1),05 114 ",537,5a C""I TortllenJlaII)'·nred**Seleeliv~** CaUIy\ic R.Hlucl**\hJ"~ling** Z LJ TN Kingston**~~7** 6 2001 CSKfBl1 IIBP,ARP**3,~1l1** 5 0.05**t~5** S,750.031 C<>al Tallgenllally·/ired l<1\Y 1\.'0" BumarTeclu10lc Ope,

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### "'**~l**08/02/2009 20:50 303-959-2822 

### NPS-ARD PAGE 38178



# Appendix A: SCR Effectiveness on



# Eastern Tangentially-Fired 

# EGIJs

AUG-04-2009 15:07 303 969 2822 98% P.3808/02/2009 20:50 303-969-2822**~,jPS-ARD** PAGE 39/70

Appendix 

### A: SCR on Eastern Tangentially-Fired 

### EeUs



### Ifwe look at real-world 

### hourly CAM emission 

### data for eastern EGUs retrofitted with 

### SCR and operated 

### during the summer ozone season-- 

### ["Appendix 

### A. 2006 Tangentially-fired 

### boiler LowNOx**charts.xl.~l'l]**


### we see a 

### consistent pattern of 

### reductions 

### from 0.3

- 0.6 Ib/rnmBtu down to 

### 0.05 Ib/mmBtu 

### when the 

### SCR is 

### operating on these tangentially-fired EGUs. 

### Here is a 

### closer look at

### the period 

### when the 

### SCRwas actually operating:



### ["Appendix A. Summary 

### 0[2006 Ozone Season data

### for Tangen.tially-firedEGUs.xls"]
The summary table indicates that 

### there is 

### littlevariation in 

### average 

### emissions depending 

### upon averaging time. 

### For example, the average 

### ozone-season average NOx 

### emission rate 

### was 0.05 

### Ib/mmBtu, the average 

### 30-day average wac; 

### 0,052 Ib/mmBtu, and 

### the average 24-hour average 

### was 

### 0.051 Ib/mmBtu.**~ecause** 

### most cost-effectivcntss calculations 

### should 

### be based 

### upon annual averages, it 

### seems apprOprial"e 

### to**a~."ume** an 

### annual average 

### emission rate of

### 0.05 Ib/mmBtu for that 

### task.


### The median values 

### showed a little more variation 

### thanthe average values,**a~ld** lower

### than the average 

### values, indicating 

### that the d.istribution 

### is skewed 

### s1ightly by some of 

### thehigheJ; emission rates. '
Because the 

### BART

### Guidelines recommend a ma:xjrnum 30-day rolling average, we also, have 

### data for this 

### parameter and it indicates

### much more variation, 

### as one mightexpect for this 

### extreme value.
We 

### suggest that 

### the bottom 

### section ofthe 

### table 

### is most important in that it attempts 

### to relate 

### the ozone-season average 

### emission used in the 

### cost calculations 

### the 30-day 

### average emission typically used in 

### establishing permit limits. At first glance, this 

### data 

### appears to 

### support a30-day

### limit ofO.081b/mmBtu, 

### but take alook atthis: ["Appendix A. 

### Widows Creek 8, 2006 ozone season.xls"] 

### Ifone had only the 

### Ib/mmBtu data, it 

### would seem that 

### there is a 

### lot ofvariation in the 

### 30- day average 

### emissionrates at Widow's Creek#8, and the maximum 30-day average 

### is 2.6 times 

### the average 

### ozone-season average 

### However, ifone inspects the chart 

### for the 

### mass emission rates, 

### it appears that 

### these variation.s 

### and 

### differences are not so large:. 

### In fact, the 

### tabulated values for the 

### ratio ofmaximum 

### 3D-day average 

### NOx mass (203 lb/hr) is only 1.2 times the 

### ozone-season average (169 lb/hr) at 

### Widow's Creek #8. We suspect that, 

### because these EGUs 

### are only required to 

### meet mass emission limits--lb/hr instead of 

### Ib/lnmBtu, that is how the SCRs are tuned. So, as load drops, there is 

### no reason 

### to maintain 

### the SCR efficiency (and 

### the Ib/mmBtu rises),

# as long as the [b/hr 

### limit 

### is met. If that is the case, 

### then it is probably more 

### useful to 

### look a the ratios ofthe 

### mass emission

AUG-04-2009 15:07 303 969 2822 98% P.3908/02/2009 20:50 303-959-2822 NP5-ARD PAGE 40/70



### rates to determine the true ratio ofmax,imum 30-day average to annual average emissions if the SCR were always operated to maximize its effectiveness; the tabulated results 

### indicatethat this ratio 

### is 1.1: 1 for these 

### EGGs.
So what'? 

### Ifwe can assume 

### that a modern 

### SCR retrofit can 

### achieve 0.05 llb/mmBtu on 

### an annual 

### average; and 

### that an 

### SCR that is operated' to achieve its

.maximum effectiveness would typically result in maximum 

### 30-day average 

### emissions no more than 1.1 times the annual average, then we could assume that a30-day 

### rolling average 

### limit of0.06 

### Ib/mmBtu would provide more than an adequate margin 

### ofsafety for 

### theEGU to operate.

AUG-04-2009 15:07 303 969 2822 98% P.40«allo 01 .1U- NUX.10 uay NUX 24 Hour Itv.ltio u/ :.II). NUX 30 Day 03 seaSDn 0llyl03 RollillgAvg RaHD 0124· Avg 03SI!BSOn daylO3 RollingAvg Raliool24 NOx 24 Houl Facility Unil NOX_RATE seae;on (lblmmBlul hr/30-dav (1IJJmmBlu) NOX MASS Se.lson (Ibrnr) hrl30-ilay Avg (lh1hr) Cllesapea\(e EnerQV Cenler 4 Avg 0.040 1.1 0.045 1.0 0.044 61 0.9 58 1.0 58 Chesoortield Powar Station 4 Avg 0.052 1.1 0.055 1.0 0.055 64 0.4 23 0.1l 19 Cflffs1de SAvg 0.058 1.0 0.058 1.0 0.059 2.53

. 1.0 249 1.0 247 Ghent 1 AVQ 0.054 0.9 0.051 1.1 0.055 224 0.9 206 1.1 2\9 Kingston 2Avq 0.052 1.0 0.052 1.0 0.052 64 1.0 62 1.0 62 Kinoslon 3 Avo 0.05? 1.0 0.052 1.0 0.052 65 .1.0 66 1.0 65 Kingston 5 Avg ... 8a 0.052 1.0 0.053 1.0 0.052 89 1.0 86 1.0 Kingston 6 Avo 0.045 \.0 0.045 1.0 0.045 75 1.0 74 10 74 King$lon 7 Avo 0.044 1.0 0044 1.0 0.044 76 1.0 76 1.0 75 Kinllston 9 Avu 0.045 1.0 0.046 1.0 0.046 75 1.0 73 1.0 74 Wldows Creek 8 Avg 0.053 1.3 0.0&7 0.9 0.002 169 0.9 159 1.0 157 Avelages 0.050 1.0 0.052 1.0 O.Otil 0.9 1.0 Chesapeake EnenlV Genter 4 Median 0.024 104 0.035 0.7 O.02{\ 47 1.1 53 1.0 50 Cheslerliald P<Yr"" Sialion 4 Median 0.042 1.0 0.043 1.0 0.043 58 0.3 16 0.0 0 Cliffside 5 Mediall 0.055 1.0 0.OS6 1.0 0.055 276 0.9 153 1.0 250 Ghenl I Median 0.034 1.5 0.050 0.7 0.035 165 1.2 200 0.6 16& Ki'n'lM()1\ 2 I,!"dian 0.049 1.1 0.052 0.9 0.0<19 60 1.0 62 1.0 01 Kingston 3 l.Ie{lian 0.049 1.0 0.051 1.0 0.049 62 1.0 65 1.0 63 Kingston 5 Median 0.048 1.1 0.052 0.9 0.049 84 1.0 85 1.0 85 Kingston 6 Median. 0.043 1.0 0044 1.0 0.043 74 1.0 75 1.0 74 Kingsilin 7 Median 0.043 1-0 0.044 1.0 0.043 77 1.0 77 1 0 76**Kin~slon** 9 Median 0.043 1.1 0_0415 0.9 0.043 74 1.0 73 1.0 73 Widows Creel<. 8 Median 0.030 1.8 0.055 0.6 0.032 127 1.3 159 0.6 129 Ave/ages 0.042 1.2 0_046 0.9 0.042 1.0 O.B Chesapealte Enel!lv Center 4 Max 0.094 2.7 0.22./l 77 3.9 301 Clleslerlield Power 51al1on 4 Max 0.158 2.2 0.3% 61 3.7 224 Clflfs-ide -5 Max 0.070 3.0 0.211 265 1-9 491 Ghent 1 Max 0.080 3.3 0.261 270 3.2 876 Kingston 2 Max OJJ56 2.2 0.131 74 2.3 170 KinoslDn :3 Max 0.058 2.2 0.131 75 2.J 171 Kingston sMa>< 0.059 2.3 0.135 103 2.2 229 Kin()slon 7 Max 0.046 1.5 0.067 76 1.6 122 Kinoslon 9 Max 0.1l5:! 4.8 0.26& 78 1.6 \25 IJ\\.dOWE- Creek 8 Max**OX~6** 3.2. 0.4:!2 203 4.0 815 Avelil\)es 0.090 2.7 0.22\ 2.7 Chesalleal<e EnergV Genler 4 MaxlAvg 0.040 2.1 0.OB4 61 1.3 77 Ch&Ster1iefd Power Srllt«ln 4 MaxlA'lg 0.052 3.0 0.156 (i4 1.0 61 Cliffside 5 MayJAvg 0.058 1.2 0.070 253 1.0 265 Ghent 1 MaxlAvo 0.054 1.5 9·080 224 1.2 270 Kingston 2 MaxlMIl 0.052 1.1 0.058 64 1.2 74 Kingston 3 MaxlAvo 0.052 1.1 0.058 65 1.2 75 Kingston :; MaX/AVQ 0.052 1.1 0.0511 B9 1.2 103 Kill!lstOfl . 6 MaxlAvg 0.045 1.1 0.048 75 1.1 80 Kingston 7 Mal(/AViI 0.044 1.0 0.046 76 1.0 76 Kingston 9 Max/Avo 0.045 1.2 0.053 15 1.0 76 Wd<YlI$ Creek e Max/Av!) 0.05-3 2.6 0.136 159 1.2 203 Averages**O.~** 16 0.076 1.1 <SJ l'-

......

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### x ill (J)



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II 

## . ,
'.' ........

0.2 0.3 -l III 0.5

III C o 'Vi II) 

### 'E 0.25 UJ >< 

### o z Kingston ·06 NOx Speciffc 

### Emissions

.. NOx 24 Hour-Avg (lb/mmBtu)

• NOx 30 Day Rolling Avg (lbfmmBtu) ,..( 

# '.< , ..**;.~.:~-.:-,**

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- c::l u: <r I UJ (L Z w (9 <r (L

(J) (S) (S) (\J I '\f (S) I 

## g a: ['- (S)

. If) ..-l 9000 8000 7000 6000 5000 Hours 4000 3000 I I - i j I Mitsu.,.! 2000 1000 

### o 

## a 0.1 

# • 

# ... 

# . 0.05 .l-.

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### 41 

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### tWa**.~~------------'** 0.15

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### NP5-ARD PAGE 47/70

.. or. .;



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### -+---- NOx Emissions (lb/mmBtu)
0 p 0 0 0 0 0 p


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### w 0 

## t; 0 

### en 0 0 C'I 01 N c.n C:.:> C'I A 

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AUG-04-2009 15:07 303 969 2822 98% P.4708/02/2009 20:50 303-959-2822 

### NPS-ARD PAGE 48/70

:::';; ::J. '(0



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::J (n ci c;J) Z 

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AUG-04-2009 15:07 303 969 2822 98% P.4808/02/2009 20:50 303-959-2822 NPS-ARD PAGE 49/70

o

...... 

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. _._



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, 1 .6..!.

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# • 

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.... • • -,Ii • •• •• • EI _.. ... .6A >Ill!II'

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.. 

## ! 

## o Appendix A. Widows Creek 8 '06 Ozone Season NOx Specific Emissions

# -:.--~+-~-

# ..-.-_..**~~~~:~ ~;~rR:~~n~b~~;~~~~mBtu)** **.~~-.-**

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.

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Ci) lD Ci) C-l N N m N I en lD en I (T) Ci) (T)

en Ci) Ci) N 

### "' N Ci) 

### "' m Ci) l::::"l n::: <[ I (f) lL Z W lD <[ lL

### Appendix A. Widows Creek 8 106 

### Ozone**S~ason** 

### NOx Mass Emissions

OJ en M If) 0..**~"-~--** 700 

# :::**J·.~·-~".-.'.:7~·~;~·:~-:7 ,:,,:'~~:~~';~I~;~:~1f)**  I';

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## __.. --'---' -----_. .._---_._--_...

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### -c A n::: <[ I '-' (J) 1/1 500 IL C z
.2 1/1 .!!! E 400 w >< 0 Z 300 

# • • 

# • 

# • ----._-_.....

### _----_.- ..



# •

• (\J (\J OJ (\J en UJ en M lSI M

["- lSI If) ....-l
en lSI lSI (\J I '<t lSI I ::l ([ 3000 2500 2000 1500 Hours 1000 500 0-1

# O'-~'**~.~. ~~=:**  • i • 

### , 

# ,. i 200

# 1

. .... '" .;

••• . • pJrn

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•
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en <Xl <Xl N 

### "' N <Xl 

### "' m <Xl N N m N I en lD en I (T) <Xl (T)

### t?S·d %86 cc8c 696 m£:

"Appendix B: Minnesota Power's 

### Boswell 3 

### Environmental Improvement Plan submitted October

### 27,2006 to the Minnesota Public 

### Utilities Commission Docket No. 

### E015/M-06-1501
presents the planned schedule for implementation"activities:
Activity Timeline Phase 1 - Conceptual Engineering

Target ProcmementActivities

- Environmental Equipment Apr2006

- Oct 2006 Target Procurement Activities Turbine/Generator Oct 2006

- May 2007 Phase 2 -lFinal Design & Procurement

Fabricate/Deliver

- SCR (incl. major steel and truss work) lun 2007

- 

### May 2008 Fabricate/Deliver

- Fabric Filter Apr 2008

- May 2008 Fabricate/Deliver

- FGD System Dec 2007

- lun 2008 Fabricate/Delivet

- Turbine/Generator lun 2007 • Dec 2008 Phase 3 - Construction Site Preparation Apr

### 2007

- lun 2007 Construction

- Fabric Filter Jun. 2007

- May 2009 Construction

- SCR lun 2007

- Jun 2009 Construction

- FGD Jun 2007

- lun 2009 Construction

- Chimney/Monitoring Equipment Apr2009

- lun 2009 ConsInlction

- Turbine/Generator Jan 2009

- Nov 2009 

### Phase 4- S!tart-Up Checkout & Commission for Tuning Dec 2008

- Jun 2009 Final Plant Start-Up and Tuning 

### Apr2009 -Sep 2009



### Gd\;;l-SdN (;(;8(;-595-EGESS'd %86



# Appendix C: SCR Costs

Gel\;;l-SdN 

### ZZSZ-595-E0Em I'-- ""- LO lD
W 'D <I CL

Q Go: <I I (fJ CL Z

C'l C'l OJ C'l I en LO en I (T) m (T)

m lD m C'l

en m m C'l ""- C'l m ""- OJ m Appendix 

### C. SCR Cost Survey Re.suIts Discussion 

### ofOAQPS 'Cost

### Manual Method 

### for AQCS Estimation submitted to the

### N1vI Environment Department by Public Service ofNM regarding 

### BARTfor the 

### San Juan Generating Station hup:llwww.nmenv.state.Dm.us/aqb/reghazldocuments/03292008DiscussionofOAQPSCostManualMethodRev080329.pdf


### 8CR Capital Cost Survey 

### Results from Table 7-1. of

### CURRENT CAPITAL COST

### AND COST-EFFECTIVENESS OF 

### POVlERPLANT EMISSION CONTROL Prepared 

### by

### J. Edward Cichanowiczfor Utility 

### AirRegulatory Group, June. 2007 Average and Low-High Cost Observations Reference Capital, MW ($IkW, Cost Basis 2006 Basis) Observed 

### ($/kW) Hoskins, ]28 (400 MW) 80-160 2002. 15 of20 reported unit costs 

### exceeded $1 

### OO/kW. 

### Weak

2003 relationship ofunit cost and scale. Cichanowicz, 84 (600-899 MW) 

### to 128 56-185 2003. 

### Forfour categories ofgenerating capacity, the least cost 2004 (100-399 

### MW) units were among the first instaUed. Marano, 118 (>900) to 167 «300 

### Mostcosts reponed to 2005. 

### "Units with acapacity of600 to 900

### MW appear 

### to be more

2006 MW) 

### be within 100-200 difficult to retrofit than those in other size ranges."



### Estimation ofCosts and ImpactlJ 

### ofNOxControl TechnolDgies 

### Applied to thePGEBoardman Plant http://www.deq.slate.or.lIs/aq/haze/docslergMemo.pdf Average and Low-High 

### Cost Observations Reference Capital, MW ($lkW, CostBasis 2006 Basis) Observed 

### ($/kW) ERG 2008 227 207

- 267 2007 1JJ If) CL

ill m

(\J (\J ill (\J m 1JJ m M Q M

['- Q If) ,..-I
m Q Q (\J I <;t Q I :::J a:%85



# Appendix C: SCR Costs 

# for Wyoming EGUs Subject to BART

8ULf; 39\;j'd 0080-595-E8E 8f;:80 5880/08/888S"d %86 

## cc8c 696 [E![



# Bridger SCR Cost Estimates

• 

# uSIng 

# (OAQPS Control CostManual I

0L/8S 39\;;id Ge:!\;;i-SdN 6686-595-E0E GS:G6 5006/60/80(S) I"- "- en LD
w (9 <I: (L Jim Bridger #1 .(J\ If) (L

GivenlAssumptions

(J\ (S) (S) N I "'\t (S) I ::J <I ['- (S) If) -rl N N (lJ N (J\ IJJ (J\ M (S) M (lJ (J\

$ 3.000 1m3 from Company report $ 3.Gfi\1 im3 from Company report $ 50 IMWh from Comapnyreport $ 400 ton from Company report 6,000 mmBtuIhr from WY DEQ report 52,560,000 mmBlu/yr from WY DEQ report OAQPS Control CosI Manual NPS estimate WY DEQ report NPS**e~timale** Company report

alculated alculated NPSestimate

alculated WY DEQ report WY DEQ report WY DEQ report WY DEQ report NPS estimate OAQPS Control Cosl Manual OAQPS Control Cost Manual Company repor! Company report OAQPS Control Cost Manual OAQPS Conlrol Cost Manual OAQPS Control Cos! Manual OAQPS Control Cost Manual OAQPS Control Cdst Manual OAQPS Control Cost Manual OAQPS Conlrol Cost Manual OAQPS Conlrol Cost Manual OAOPS Control Cos! Manual OAQPS Conlro] Cos! Manual OAQPS Conlrol Cost Manual OAQPS Control Cos! Manual OAQPS Control Cos! Manual CEPCI 2007/CEPCI 1998 calculaled from ca!cuiRted from cab:lated from calculated from OAQPS Control Cost Manual New or Retrofit? Retrofil Extra retrofit cost factor 1.0 Generation capacity (MW) 530 SCR bypass included? No Fuel HiQh Heating Value (Btufib) 9,660 Maximum Fuel Consumption Rate (Ibnlr) 6.2E+05 I Average Annual Fuel Consumption (Ib) 5.44E+09 I Number of SCR**Operatin~** Days 365 I Plant Capacity Factor 100% I Uncontrolled NOx Concentration (lb/mmBtu) 0.41 LNB + OFATalal Capital Cost $ 11,300,000 LNB + OFATalal Annual Cost $ 1,144,969 LNB oUllet = SCR inlet NOx Concentration (lb/mmBlu) 0.26 Required Controlled NOx Concentration (lblmmBlu) 0.05 Acceptable Ammonia Slip (ppm) 2.0 Fuel Volume Flow Rate (ft3IminfmmBtu/hr) 516 Fuel Sulfur Canlent 0.58% Fuel Ash Conlenl 10.3% Number of SCR reactor chambers 1 ASR 1.05 Stored Ammonia Concentration 29% Reagent MolecularWeight (Q/mole) 17.03 Reaqent Density (Ib!ft3 @ 60F) 56.0 Reagent SpecificVolume (ga11ft3) 7-481 NOx Molecular Weight (g/mole) 46.01 Number of Days ofStorage for Ammonia 14 Pressure Drop for SCR Ductwork H2O") 3 Pressure Drop for each Catalyst Layer (H2O") 1 Temperature at SCR Inlel**(de~rees** F) 650 Equipment Life (years) 20 Annual Interest Rate 7% Innation Since 1998 1.35 Calalyst Cost. Initial (SIft3) $ 85 Calalvsl Cost. Replacemenl(SIff3) $ 85 E1eclrical Power Cost ($JkWh) $ 0.05 29% Ammonia Solution Cost ($flb) $ 0.06 Operating life of Catalyst (hours) 24,000 N N OJ NI en lD en I (T) (S) (T)

en (S) (SJ N "- N (S) "- OJ (S) (S) LD



### .. (S) N c:l Dc: <I: I (f) (L z(S)**r~** 

### "' (S) LD
W <.9 <I (L LNB Control Efficiency

## =(Inlet Cone

- Outlet Conc)llnlet cone { 0.41
Boller Calculations 0.26 )/ 0.41 = 36% IS) OJ) (L

2.7 CFPlanl = ac·tuaI tnf'iJ•

### .tmaximllln tnfu.] CFPlant

### = 5.44E+09 Jb/yrI 8760 hr/yrI CFPlanl

## = 100% QS= Os= 2.3 

### QB 

### =HVrn-dolfuel g6BO Brutlb • 6000 Blu/hr 621iiB.Oi Ib/hr

621118.01 Ib/hr x ['- (f\

2.12 qIJUefllS = q(u<,QE\(460+T)/(460+700of)fisCR qfluegas = 516 ft3/minf(mmBlu/hr)"" 6000 mmBtulhr'( qfluegas:: 2,962,552 acfm 2.8 CFSCR

### =tsCI/365 days CFSCR

## = 365 daysl CFSCR = 100% c:l 0:: <I I (J) (L z CFTotal.= CFTotal= CFTotal = CFPIDnl X CFSCR 100% • 100% 365 days

100%

460 + 650 )/( 460 + 700)1 1 (\J (\J m (\J en ill en 

## 8 f'l

2.9 'lNox

### =(NOxrn

- NOxoJll) I NOXin llNOx:: ( 0.26 Ib/mmBlu

- J'}NOx = 81% C'l C'l OJ C'l I en LD en I (l) (S) (l) Uncontrolled NOx emissions (tpy) 10643 0.05 Ib/mmBtu)/ 0.26 Ib/mmBlu

Overall Control Efficiency = (Inlet Cone

- Outlet Conc)/Inlet cone ( 0.41 (S) m (S) C'l

en (S) (S) C'l 

### "' C'l (S) 

### "' OJ (S) NOx removed

# =
Controlled NOx emissions (tpy) 

### = 93291py
1314 tpy 0.05 )/ 0.41 = 88% ['- IS) If) ..-l
en IS) IS) (\J I 

## '" IS) I :J a:SCR Resctor CalculMlan. 2.11)**Vol~",~** 2.81 x Qn x T\>dj:>l Slipolj" NO>C",rj l( S"lj xT,:lj'N,,:Jl. '1ole""""".l 2.81 • 6000 = 16!lOO 2.2 l}oIj 0.2869 + (1.058 J( TI) Ijauj = 0.2869 t( 1.G58 • 0.81 ) lJadj 1.1<11 2.22 SlipWj l.2835

- (0.0567x Slip) SfiI1adj= 1.2835 -( 0..Q.51 ;] } Slil'''dj

. 1.170 2.21 NOXalj = 0.8S24 + (0.3208 )( l\'Ox",)**NOlt~j** = 0.8524 f ( 0.321 • 0.211 ) NOlta:lj "- 0 936 2.23 S..tj O.%3ti +(0.0455 xS) Sad! = 0.9636

.. ( 0.0<16 • 0.58) SarJj= 0.990 2.24 T ulj= 15.16

- (0.03937 xT) >(2.74 x 10.5 X**1~)** Tadj= 15.16· ( 0.039 • 650 ) -I 2.74E-O:i· Tadj = 1.146 Volcalalvsl

### = 23.906 03 (S)**r~** "- .--I UJ
W r.!l <I: (L

l=l a:: <I: I U1

..

CD I en UJ en I (T) (S) (T) 2.25 A""dl'" = Qnu'vd'(j6 fusee x60 sec:/min) AtillatJ'i1 = 2962:152 I( 16 • Acala)/st = 3086 "2
2.26 A'CA = I.15 x "\""'1)"' ASCR

### = 1.15 ' 306-6 ASCR =**35~9** /12

It1 2.27 ) = w A",:l'< I=w= 59.6 It

2.28 nul'" = Vol"'>Il",'(h''''l''' XA""tlYL) nfa'l"" = 23906 I( 3.1 •**~a,..er=** 1.0
2.7.9**h'll~1 =IVolu>l)'/(~"**  X '\o"a)"!)] + 1 t\\a'l"" = 239U6 I{ J • hlaye, = 3.6 ..-l IJ) (L

-. ':""-.':""

;,-,.; en (J'l**4~~50G**

(\J 60 >.
(\J en (\J (J'l '.0 (J'l M CSl M

J01l6 )

J08li )-;-

(S) LD (S)**C'~** en (S) (S)
"- (S) "- CD (S) 1.3 Jl,ct;d --. nh.)'t, +**J~).** nlo1Jl" 2 + nfolol = J
2.31 hSCA = 1\"",(CI ' h'n.,r) + .,. t'_<;CR = 3 • ( hSCR = 41 R 7 + 3.6) + 9 ['- CSl If) ..-l
(J'l CSl CSl (\J I '<j' CSl I eJ =:l ([(S)**r~** ""'- C'l LO
W '-!J <I: (L Reagent Calculations N

- ---_.._-_._--- IjJ (L



### 2.32**m-dotreag~n'** 

### =NOxinQBASRJ1NoxMr"",S",,!MNox m-dotreagenl

# = 0.25

.. 6000 " 1.05 

### * m-dotreagent :=: 490 fbfhr a1%

.. 17.03 I 46.01



### 2.33 m-dorsal 

### =**m-dOl:rc~gcnrlC.oJ** m-dotsoJ = 490 I m-dotsol 

## = 1689 Ib/hr 0.29 roo

N 

### Sj 0J 00 IjJ 00 l"1 lSI l"1 56



### 24 14 ;0 7.481 I

226

.. 75,794 gal 

### 2.34 CIs,,] 

### = (m-dotyolpsol)V:W1 qsol = 1689 ,. qsol

# = 226 gph


### 2.35 Tank

### Volume = 

### gsa,t Tank Volume

## = Tank Volume

## = 0:: <[ I (J) (L z

C'l C'l OJ C'l I en LO en I (T) (S)

r- (T)

lSI



## .. If) .---l (S) lD

00 

## ..

lSI (S)

lSI C'l

N I -.q en

lSI (S)

I (S) C'l

::J ""'-

<I**C'~** (S) ""'- OJ (S)Ci) I'- "- (T) LD
w (D <r a... [Y) ill a...

Direct Capital Cost

CD m . 6000 (( $ 3.380 + [(hsm) = {[$612fCfl-mmBlufhr)]hsc.R}

- $IR7.91(nunBluJhr) 6.12 • 41

- 188 $ 61 ImmBtulhT 2.]7 f(hSCR) = f(hSCR) = DC= 2.36 DC

### =Qo[($33110IMMBlll/hr) 

### +f(hscJ +f(NHJrate) 

### +f(new) 

### + f(bypass)](3500/QB)'IJS 

### +f(VO!C'lnIJ'Yo)

f(NHJrate) 

### = [($411JlbJhr)(m-dolmgt .n

/Qn)]

- $473/(mmBtufhr) 4\\ • ## J 6000

- 47.3 S (14) Imm81ulhr f(new) = $OJ(mmBIuJIu-) for retrofit

$ [(bypass) = $O/(nunBllllhr) for no bypass $ - Imm8tu/hr f(VO!("..ral)"'l) = Volca,.ly.,CCinitia! 23908 85 $ 2,032,521 2.38 f(NH3rale) = f(NH3r<lte) 

### = 2.39 [(new)

### = 2.4\ f(bypass) :::: 2.43 f(Volcatalysl) = f(Volcalalysl) = Q 0::: <r I ill a... z

DC= DC= $ 6000 ( 19,063,005 $3,3BO + $ 61 +' $ {14} + $ - + $

- )"( 3500 I 6000)" 0.35 + $2,032,521 (\j (\j CD (\j m .J) m [Y) (S) [Y)

C\l C\l OJ C\l I (Jl LD (Jl I (T) Ci) (T) Inflation Adjustment

## = DC= $ 25,735,056 1,35

Ci) U1 Ci) C\l ['- (S) If) ..--l

(Jl Ci) Ci) C\l "- C\l Ci) "- OJ Ci) m (S) (S) (\j I "<j (S) I eJ ::::J a:(S) I"- ""- "'<t" 1!J
W '-9 <J: Q... Indirect Capita' Costs 'S o.D Q...

0.058 JIb· Retrofit factor

## = Retrofit faclor

## =

CosUkW= 0.05 A 0.10 A 0.05 A 0.20 A

## = 0.15 (A+B)

## =

(\J (\J CD (\J en '.0 en (Y) Q M X CD en 25,735,056 $1,286,753 $2,573,506 51,286,753 $5,147,011 $4,632,310 $35,514,378 $0 $0 $710,288

$32,907 $36,257,572 $68 $47,557,572 $90 $

0.20 A

## = 0.15 (A+B) = A+B+C 

### o 

## o 0.02 (D+E)
24 hr/day • 14 days = +D+E+F+G+H+I CosllkW = 1.0 1.0

1689 Iblr·

Total Capital Investment Tel including LNB + OFA = Total Direct Capital Costs, A Indirect Installation Costs General Facilities Engineering and Home Office Fees Process Coniingencies Total Indirect Installation Costs, B Project Contingency, C ::: Total Plant Cost 0 == Allowance for Funds During Construction, E

## = Royalty Allowance, F

## = Preproduction Cost, G == Inventory Capital, H = Initial Catalyst and Chemicals, I

## = Total Capital InvestmentTCI 

## =D+-G+H A Q <J: I (J) Q... Z

C'l**C'~** CD C'l I DO 1!J DO I (T) (S) (T)

(S) l:"- ID Q I (S) If) C'l ..-l

DO en (S) lSl (S) lSl C'l (\J
""- I C'l 'S (S) lSl
""- I <Xl (S) ::::J a:Annual Costs**.~!!!!~!fW;iiilii~** D:\C = Annu

..! Mail1hmsnce C",1-1- AmiUAlll.esgecl Cas' ;- Arutu:J1 mcclriQity C

....t .!- AMu

..! Wole' Co.1 + AJ1nunl CRtalyst 0,.1 2-46 AnoWlllI.l"inlenanceCO<II =0.015 TCI Annual MainlenallCe CD,l = 0.0\5" $36,257.572 Annual**Mailllen~l1Ce** Cool = S 5/13.664 2.47 AnnU31 Rca]!.",,!**Co~l** =lb-_Cos"-'II=I,. 2-41a I"p = CF,,,,,,1t76Ilhr/y. lOp = 1CO% • 8760 lOp = 8760 Anfli

.. "ll**R'"~\1",'i** CDSl= IBail • 1l7&! • [lO58 Anllllal'Reagent Cosl = S 657.939 2-49 Annua!**m~"'ril:-jly** COdI = P"Wtf(Cosldmjlfll 2.48 I'owe. -: 0.I05QilINOrI,.TJNOx + 0.S(6P..." +l\.".luP""Loy.Jl Po,ver

### = 0.105 • EiOCO "( 0.26" 611&. 0.5 • ( :J + J' 1)} Power'" :UYY.! kW Annoal Bec1!icty OJsI = W22 • 57&> • 0.05 AOllual EJeclllcty OJ!>1 '" $ &YJ,767 2.51 :'tUlIla! Calalysl RepiBc"nTc:n1 Cos, =(Cah,lysl rteplpcem<nl Co«l)I'WF

2.S Calalysl Rcploclffilcnl Cool =**n",:~V"I/r.;o},,,C('....-lu/Rlrf'1** Catalysl Replacemenl Cosl = 1 ' Zl!iOa' 85.01561511 I 1. C81alysl Rep'ccemenl Cosl = II 1.016,260 2.52 FWF =i{I/((I+-1)Y-I)} 1.5J Y = hc.,IIA.", y = 24000 f(**42~J,** • 8760 ) y= 6 FWF= O.W '( I I( 1 1 0.07 )' 6 • 1 ) fWF= [114 Annual**CalBl~",1** Cost = S '42.0B9 DAC = S 2.42l1.6:W. I'-

...... II1 ill
w f.!) <I 0...

Q a;: <I I (f) 0... Z

2.S5 CRF = i(Hi)"fl(l+i)"-I) CRF= 0.07 '( CRF = 0.0044 1 + 0.07 )' 20/«( 1 1 0.07)' 20

- t) If) UJ 0...

m (fI

(\j (\j m (\j (fI UJ (fI M lSl M

256 Tol,,1 lllUlUal Co-"' = Direcl!\nnUBI Cost + IndiiWl Annual Co., io!"jAnnuilICoeI = S 2,4211,6:Y3' 3.422,456**TolaIAll~uaICos1=** S 5,1l52.097 + S 1.H4.969 = 56.997.006
2.5'1 NO;>; RClOm',d = NOx;"ltl.'<hQpl", NOxReJ11Gl,'i!d= 11.26" al%' NOx Remo·

.....d = 5519

258 Cm( c.lleclil'CI1C5S

# =,.**ACjNO~** removed SCR Cool elfeclr;"r.ess= S t.06O T 01;01 Cosl effeclr;"n"ss = S 7S> ('.l ('.l (l) ('.l I en ill en I (T) (T)

II1

('.l

en

('.l

...... ('.l

...... (l) Indirecl Annual Cnsl = ern IndirfCl Anll'JillCost Indirecl AnrfJalCost= S

Tol:aJ NOx Removed

### = , Tel 009.4' $36.257,572 3.422.458

9329 eooo' Br€OI 2()()') ['-- lSl If) ,-I
(fI lSl lSl (\j I 

# "" lSl I ::::J ([(S) i"- ""- LO LO
w C!) <[ (L Jim Bridger #2 til til (L

Given/Assumptions

['- Q If)



### .....
(J) Q ISl (\J I 

# "" ISl I l'J ::J ([ (\J (\J OJ (\J (J) til (J) M Q M 

### x OJ (J)

$ 3,000 1m3 from Company report $ 3,000 1m3 from Company report $ 50 /MWh from Comapny report $ 400 ton from Company laporl 6,000 mmBlu/hrfrom WY DEQ report 52,560,000 mmBlufyrfrom WY DEQ report -JPS asUnlateCompany report calculated calculated NPS estimate calculated WY DEQ report WY DEQ report WY DEQ report WY DEQ report NPS estimate OAQPS Control Cost Manual OAQPS Control Cost Manual Company report Company report OAQPS Control Cosl Manual OAQPS Control Cost Manual OAQPS Control Cost Manual OAQPS Control Cost Manual OAQPS Conlrol Cost Manual OAQPS Control Cosl Manual OAQPS Control Cost Manual OAQPS Control Cost Manual OAQPS Control Cost Manual OAQPS Control Cost Manual OAQPS Control Cost Manual OAQPS Control Cost Manual OAQPS Control Cost Manual CEPCI20D7/CEPCI1998 calculated from calculated from calculated from calculate-d from OAQPS Control Cost Manual OAQPS Control Cost Manual NPS estimate WY DEQ report N&wor Retrofit? Retrofit Extra retrofit cost factor 1.0 Generation capacity (MW) 530 SCR bvoass Include.!!? f\Jo I I Fuel HiQh Heating Value (Btullb) 9,660 Maximum Fuel Consumption Rate (Ib/hr) 6.2E+05 Averaf:je Annual Fuel Consumption (Ib) 5.44E+09 Numberof SCR Operating Days 365 Plant Capacity Factor 100% Uncontrolled NOx Concentration (lb/mmBtu) 0.41 LNB -l- OFA Total Capital Cost $0 LNB -l- OFA Total Annual Cost $0 LNB outlet

## =SCR inlet NOx Concentration (Ib/mmBtu) 0.26 Required Controlled NOx Concentration (lb/mmBtu) 0.05 Acceptable Ammonia SUP (ppm) 2.0 Fuel Volume Flow Rate (f13/min/mmBtu/hr) 516 Fuel Sulfur Content 0.6% Fuel Ash Content 10.3% Number of SCR reactor chambers 1 ASR 1.05 Stored Ammonia Concentration 29% Reagent MolecularWeight (g/mole) 17.03 ReaQent Density (lblft3 C6:! 60F) 56.0 Reagent Specific Volume (gaJlft3) 7.481 NOx Molecular Weight (g/mole) 46.01 Number of Days ofStorage torAmmonia 14 Pressure Drop for SCR DuctworK H2O") 3 Pressure Drop for each Catalyst Layer (H2O") 1 Temperature at SCR- Inlet (deQrees F) 650 EQuipmenl Life (vears) 20 Annual Intere-st Rate 7% Innation Since 1998 1.35 Catalyst Cost, Initial ($/ft3) $ 85 Catalyst Cost, Replacement ($/ft3) $ 85 Electrical Power Cost ($IkWh) $ 0.05 29% Ammonia Solution Cost ($/Ib) $ 0.06 Operating Life of Catalyst (hours) 24,000 (S) to (S) C'l

(Jl (S) (S) N ""- N (S) ""- ill (S) N N ill NI (Jl LO (Jl I (T) (S) (T) Q a::: <[ I UJ (L ZCD**r~**

""-rlD
w C..'J <r Q... . LNB Control Efficiency::: {Inlet Cone

- OutletConc}/lnlet conc ( 0.41 0.26 )1 0.41 '" 36% r-- ill Q...

BoilerCalculations

2.7 CFplbot= actual mfuel/maximum mfvd CFPlanl

## = 5A4E+09 Ib/yr I 8760 hr/yr/ CFPlant::: 100% OS= OS= 2.3 

### On = HVrn-dotruel 9660 Slullb 6000 Blu/hr 621118.01 Ib/hr

621118.01 Iblhr rn m

2.12 qOuega, = qruelQB(460+T)/(460+700°F)nsCR qfluegas = 516 ft3/minf(mmSlu/hr)* 6000 mmBtufhr*( qlluegas 

### = 2,962,552 acfm
2.9 11No x

### =(NOXU1 - N0Xou,) /NOxin llNOx = ( 0.26 IblmmBtu

- llNOx::: 81%
Uncontrolled NOx emissions (tpy) 2.8 CFSCR

### =t sCR/365 days CFSCR 

### = 365 daysl CFSCR = 100%

(\J (\J rn (\J m ill m 1'1 lSl 1'1 460 + 700)1 1 650 )/( 460 +

0.05 Ib/mmBtu)1 0.26 Ib/mmBtu 365 days

100%

10643 CFTotal

### = CFPlaDI X CFSCR 100% • 100% CFTotal = CFTolal =**('~** (l) I 01 lD 01 I (T) CD (T) Q 0:: <r I In Q... z

Overall Control Efficiency

## =(Inlet Cone

- Outlet Conc)/lnletcone ( . OAl CD to CD

01 CD CD
""- CD ""- (l) CD NOx removed 

### = Controlled NOx emissions (tpy)

## = 9329lpy 1314lpy 0.05 )1 0.41 

## = 88% r-- lSl If) T"'I
m lSl lSl (\J I 

## "'" (S) I ::J a:CiJ I'- "'- OJ LD
W '-9 <::I: Q

Q

I Ul Q Z SCR React<JI Calculation.
2.19**Vol",,~l'''** = 1.81 xOn XTJulj x Slipo.<j x 1'\Ox,q;x XT.l/N"'

.... Volcalalysl= 2.81 ' 6<JOO = /I1i1Hl 2.2 'lulj = 0.2869 + (1.058 x II) I]adj = 0.2969

..( 1.1 • 0.111 ) 1]1lU,= 1.141 2.22 SJil\..1·= 1.28J5

- (0.0567 xSlip) Slipm:lj= 12835 .( 01 • :> ) Slipadf = 1.171) 2..11 NOx,y= 0.&524 + (0.320& x NOxio ) N:Jxauj = 0.852.01 + ( 0.3 • 0.76 l NOxadj" 0.936 1.23 SaIj = 0.%36 t (0.0455 XS) 'Slldj = 0.963$ + ( 0 • O.M ) Sadj= 0.990 1.24 '["Ij = 15.16

- (0.039]7 XT) +(2.74 X 10.5**xT~** TadJ= 15.16-[ 0' 6:>0)+ 2.74E.Q5' Tadj= 1.146 VO:calaCysl " 23,51OB fi3
2.25**'~"oJ'"** = ql\»'lI'i(J6 fV,cc X60 seclmin) Aca/al/sl = 2962552 f( 16 • 60 ) Acalal»sl = . :!lM6 if2
1.26 ASCR = 1.15 X**A~** ASCR = 1.15 • 11## ASCR =**:!6~9** "2

111 2.27 1= IV = A'e!< I"w= 59.6tl 422500 m \.0 Q

m en

(\J (\J m (\J en \.0 en 1'1 (SJ 1'1

C'l ('l OJ C'l I en LD (J1 I (TJ CiJ (TJ 2.2& "'->'" =**VOI'''dY''(h'I')~1** )( Aad)"l) "llIlf'" = 239011/1 3.1 • nlayoer-'= 2.0
2.29 h,1\-.J = l'/ol""">,,I(nl&)"'. x**"\"'d~J** + I hlaY"r = 23909 II 3 • hlayoer" 3.6 3066 )

3086)

..

CiJ 1D CiJ C'l

(J1 CiJ CiJ C'l "'- C'l CiJ "'- OJ CiJ 2.3 l\«oJ =

## "'ll'" + l\",-'j'Y nlotal'" :1

.. nlolal = 3 2.3\ h.C11 =l\"",(CI +**~.r)** + Cz hSCR= 3' [ IlSCR= 41 tl 7+ 3.6 )

.. 9 ['- (SJ l{)

....... en (SJ (SJ (\J I ';t (SJ 

## t1 :::J a:c;;:) l'- "- en LD
W I.!) <[ CL Reagent Calculations en ill CL



### 2.32 l11-dotn:agent = 

### NOXinQllASRllXOxMreagent/MNOx m-dotreagenl = 0.26

.. 6000

.. 1.05

... m-dotreagent = 490 lbJhr 81%

.. 17.03 I 46.01



### 2.33 m-dot

### 50J ::::**m-do~getiC50r** m-dotsoJ 

## = 490 I m-dotsol 

## = 1689 Iblhr 0.29 CD en

C\I C\I OJ C\I en oj) en l'1 Gl l'1 24 56

14

.. 7.481 I



### 226

.. 75,794 gal 

### 2.35 Tank Volume 

### = Cloolt Tank Volume = Tank Volume = 2.34**~l** :::: 

### (m-dot"XltlPsol)Vso1 qsol::; 1689 " qsol ::; 226 gph A 0::: <[ I l.f) CL Z

C'l C'l CD C'l I en LD en

('- I

Gl (T) c;;:)

If) (T)

...-l
en Gl c;;:)

Gl LD

C\I I c;;:)

""\t C'l

Gl I en c;;:)

a: c;;:) C'l "- C'l c;;:) "- CD c;;:)2.37 f(hSCR) 

### = f(hSCR) = I"-- 

### "' I"--
w (!J <I: 0....

DirectCapital Cost
2.36 DC= O.3i DC =**<1.~l($3380fMMBtuJbr)** + f(hsci) +f(l\'lI)rate) + [(new)

### + f(bypass)](3500/Qa)

. +f(VOlcotDly-,l) 6000 (( $3,360 + f(hscJJ = U$612/(ft-lIlIllBtulhr)]h:scR}

- $187.9/(lUmBtl,1/hr) 6.12" 41

- 18B $ 61 ImmBlulhr (S) ['- 0....

m en f(NH3fate) 

### = [($411flblhr)(m-dot,'''l\ro/QB))

- $473/(mmBtulhr) 411 • ## I 6000

- 47.3 $ (14) ImmBlu/hr Qnew) 

### =$O/(mmBt\llhr) for retrofit $ f(bypass) = $O/(mmBtuJhr) forno bypass $ - ImmBtulhr**f(Vo~.l)"I)** = VOI.:a-.al)'31CCinitiaI 23908 • 85 $ 2,032,521 2.38 f(NH3rale) = f(NH3rare) 

### = 2.39 [(new) = 2.41 f(bypass) = 2.43 f(Volcalalyst} = f(Volcatalyst)

## = Q D::: <I: I (f) 0.... Z

N N CD N I iJ1 lD iJ1 I (T) (T)

to

N

iJ1

N ""- N
""- CD DC= DC= $
Inflation Adjustment '" DC= $ 6000 • ( 19,083,005

25,735,056 1.35 $3,380 + $ 61 + $ (14) + $ - + $- )*( 3500 I 6000 

### V' 0.35 + $2,032,521 (\J .(\J m (\J en OJ) en M (S) M

['- (S) lJ) ..-l
en (S) (S) (\J I (S) I ::::J a: