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

Date:

To:

From:

Subject:

NATIONAL PARK S~ERVICE

AIR RESOURCES DIVISION

FACSIMILE COVER SHEE:T

August 4, 2009

David A. Finley

John Bunyak

Wyoming BARTLetter andEi1closures

Number ofPages: 69 - pr Fax and 68 2/ld Fax

(Including this cover sheet) .

Office Locatl'on: 7333 HI: Jeffenol'l, Room 450. Lakew()od. CO 80235

(Send Mail to: 12795 W. Alameda Parkway,.Lakewood, CO 80228)

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IN REPLY REFER TO,

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

August 4, 2009

N3615 (2350)

David A. Finley, Administrator

Division of Air Quality

Department of Environmental Quality

122 W. 25th Street

Cheyenne) Wyoming 82002

Dear Mr. 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) and particulate matter (PMIO). However, we believe that

additional reductions can be achieved under the 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 of our

comments.

NOx Step 1: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

Except for Basin Electric's analysis for Laramie River, all of the other (PacifiCorp)

analyses included a reasonable suite of options. Basin has omitted the most-effective NOx

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

NOx Step 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

ThIs step was handled appropriately. '

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-hoUrsl and 30-days.2 Furthermore, EPA's Clean Air Markets (CAM) data (Appendix

A) and vendor guarantees show that SCR can typically meet 0.05 lb/mmBtu (or lower) on

an annual average basis. PacifiCorp, Basin Electric, and WY DEQ have nc>t provided any

documentation or justification to support the higher values used in their analyses. Our

review of operating data (Appendix A) suggests that a NOx limit of 0.06 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 of SCR was consistently overestimated. EPA's BART Guidelines recommend

use of the 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 or bids, and PacifiCorp, Basin Electric and WY DEQ

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 calculated for combustion controls plus SCR. 1

As recommended by the BART Guidelines, we applied the 0 QPS Control Cost Man,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 overestimated by PacifiCorp) Basin Electtic, and. WY DEQ.

The' basis for equipment cost estimates should be docurnente1. either with data supplied

by an equipment vendor (i.e., budget estimates or bids) or by 4'referenc~d liource (such as

the OAQPS Control Cost Manual, Fifth Edition, February 1996, 453/B-96-001). In order

I Basin Electric-Dry Fork

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 of a particular BART teclulo10gy option.

EPA's belief that 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 8 to the North Dakota Department of Health:

The 802 and PM cost analyses were completed llSing the CUECost modeL 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

be revised to adhere to the Cost Manual 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 of Chapter 2.5.4.2, the manual.

discusses retrofit cost consideration including the practice of developing Gl retrofit factor

to account for unanticipated additional costs of installation not directly related to the

capital cost of the controls themselves. However, PacifiCorp did not present a retrofit

factor in their cost analyses." 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

information to determine ifand how it addressed. 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 bf visibility improvement in

a given Class I area as well as the cumulative effects of imptpving 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 of the source be included in the modeling arlalysis; WY DEQ addressed

visibility impacts in a partially-cumulative analysis of so~e multiple Class I arelils,

however it 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, Flat Tops WA, Rawah V·lA, and Eagles

Nes~ WA.

As illustrated in Table I, considering just the incremental benefits of SCR at Jim Bridger

Units 1 and 3, calculated for 3 Class:! areas, the deciview Cdv) improvement would be 0.6

dv. Comparing the benefits of SCR 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 of reducing 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 significantly impaired. Ifwe look at only the most-impacted Class I area; we

ignore that the other Class I areas are all suffering from impainnent to visibility caused or

contributed to by the BART source. It follows that, if emissions from the BART source

are reduced, the' benefits will be spread well beyond only the most-impact~:d Class I area,

and this 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 visibility resulting from addition of SCR

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 of control 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 tOl increase from 55.2 nblhr under Scenario A to 94.7

lb/hr under Scenario B. Although no: explanation is provided, we assume that the increase

in H2S04 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 of adding SCR, we are providing infonnation in the enclosed documents relating

to the estimation ofI-hS04 emissio~ and request that WY DEQ evaluate a:nd explain this

issue as it pertains to all ofthe Pacifi:Corp BA.RT analyses.

BART CONCLUSIONS FOR NOX: CONTROLS

WY DEQ's conclusions and rationales were dearly' stated, but sometimes lacked a basis

by which the reader could understand the 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 for just the three nearest Class I

areas and would be greater if benefits for the additional impacted Class I areas within 300

km of these facilities had been considered. Nonetheless, the benefits are well within the

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 documented below:

According to WY DEQ, "Several different metrics can be considered when evaluating

the cost-benefit relationships of different 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 of pollutant removed)

to evaluate different control technologies. Incremental cost effectiveness is also used

extensively by the Division when comparing eniission controls under the BACT process.

\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 of cost of applying 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 of anticipated visibility 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 of each proposed NOx emission control."

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 it used to determine if the average or incremental cost of a given

control option was ''reasonable.'' Furthennore, we believe that WY DEQ has not given

enough consideration to the core purpose of tIle BART program, which is to improve

visibility in our Class I areas. BART is not .necessarily the most cost-effective solution

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

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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 of pollution 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 of dollars per deciview were reasonable.

Compared to the typical control cost analysis in which estimates fall into the range of

$1,000 - $10,000 per ton of pollutant removed, spending millions of dollat·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 a maximum of

almost $50 million per dV proposed by Colorado at the Martin Drake lpower plant in

Colorado Springs.

While it is appropriate to consider incremental costs in addition to average costs, we have

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 rej ecting 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 of pollution control is an exponential function with an increasing slope as higher

control efficiencies are approached. Thus,' the in,cremental cost of movi: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. If WY

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,

4 E. How do I select the "best" alternar:ive, using the results of Steps I through 5?

1. Summary of the Impacts Analysis

From the alternatives you evaluated in Step 3, we recommend you develop a chart (or charts) 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 other cost 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 per day 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

consider them in situations where an option shows]...slightly greater emission 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 SCR under its BACT program at very low limits. We suggest that the I::ombination of

combustion controls plus SCR should instead be viewed as a package of complementary

parts, and that WY DEQ should detennine if addition of SCR is unusually expensive at a

specific BART source compared to other installations. Our analysis shows that both the

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 c9st per deciview proposed and/or

accepted BART by the sources and/or states 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 of incremental cost effectiveness will always result in the choice ofthe

cheapest option if carried to this extent. According to the NSR Workshop manual, "As a

precaution, the difference in incremental costs among dominant alternatives cannot be

used by itselfto argue one dominant alternative is preferred to another." Instead, it should

be used to compare closely perfonning 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.

Additional reasons given by WY DEQ for r~jeeting SCR include:

WY DEQ: Additional non-air quality environmental mitigation is required for the use of

chemical reagents.

NPS: We are aware of at least three pennitsID issued by WY DEQ requiring application

. of SCR to new sources and wonder why this issue is raised in these particul.ar cases.

WY DEQ: Operation of LNB with separated OFA and SCR is parasitic and requires...

power from each unit.

NPS: the cost ofthis demand has been correctly included i:h the cost analyses and should

not be double-counted unless that parasitic demand would result in a poweI' shortage.

PacijiCorp and WYDEQ 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· present evidence that this is actually true,

,and quantify the economic impact.

• potentially create a visible stack plume sometimes referred to as a blue plume, if

the ammonia injection rate is not well controlled. NPS--Wel assume that

PacifiCorp has the capability to control the ammonia injection rate 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 for NO", Naughton #1 - #3 for NOx, Wyodak for NOx,

WYGEN 2 & 3 and Basin Electric Dry Fork.

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8

properly addressed by the operating company. We also note that "WY DEQ has

required installation and operation of SCR at other facilities.

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 explain why so much extra time 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 limit pennitted by EPA fOf the Desert Rock po,;iveT plant.

Our concern is further illustrated by WY DEQ's decision that, 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 of compliance for a full-scale fabri,c filter (In Unit 3

not reasonable, PacifiCorp is comm.itted to installing this control device and has

permitted the installation of a full-scale fabric filter on Unit 3 in a recently issued New

Source Review 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 PMJPM10 mission

limits of 0.015 lb/nunBtu, 561blhr, and 243 tpy as BART for P.M.t1'M lO•

We believe that it is highly 'Lmlikely that PacifiCoIp would propose a BART strategy

, unless it finds the strategy to be reasonable or is otherwise compelled to do so. WY DEQ

should either accept that 'addition of fabric 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 illustrated in 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 of the 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, Basin Electric-Dry Fork

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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 of concem 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 under the plan " ...must be shown to provide

for greater reasonable 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 sulfur dioxide sources.

We are enclosing our technical support documents that provide 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) if you have any questions or comments.

Sinoerely,

Ju&-~ John Bunyak

Chief, Policy, Planning and Permit Review Branch

Enclosures

cc:

Callie Videtich

Air Technical Assistance Unit

8P-AR

U.S. EPA Region V-III

999 18th St., Suite 300

Denver, Colorado 80202-2466

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Wyoming Department ofEnvironmental Quality

Chizen Business

~~PS-ARD PAGE 11/70

Page 1 of 1

OFFICE ADDRESS TE/..EPHONEIFAX

Cheyenne r~lephona

Hsrschler Building 307·777·7391

122 W. 2SIIl 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

Privacy Polic)· ContaC[ Us Copyright

DEQ Wcbmnstcr

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AUG-04-2009 15:07 303 969 2822 98% P.ll
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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.

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Technical Support Documents

for

Wyoming EGU BART

I·

PAGE 13/70

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Nation~.l Park Service (NPS) Comments on the

Wyoming Department ofEnvjronmental Quality's proposed

Best Available Retrofit Technolqgy (BART) Determination for

Jim Bridger Power Plant

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 of nitrogen 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 effect in 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 of SOFA, in.stall a flue gas conditioning (FOe) system which injects SOj

gas into the flue gas to improve the efficiency of the ESPs on Units 1-4, and upgrade the

existing FGD systems on all tour units to achieve greater than 90% S02 removal.

Permit MD-I 552 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 of the 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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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 of pollution 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

BART presumptive NOx limit of 0.15 Ib per mmBtu for sub-bituminous coal.

BART Analysis for NOx

NOx Step 1: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOLOGIES

WY DEQ: 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 of options.

NOx Step 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

None of the four control technologies proposed was deemed technically infeasible by

PacifiCorp.

NOx Step 3: EVALUATE EFFECTIVENESS OF REMAINING CONTROL

TECHNOLOGIES

WY DEQ: 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 nevi LNB 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 of the

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 of 24-hoursl 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 represent only a

73% SCR control efficiency as oppo.sed to the generally-accepted 90% for a· welldesigned system. Our review of operating data (included in the tangential boilers porti<m

of Appendix A) suggests that a NOx limit of 0.06 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 provided justificati,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 Bridger that 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 of those EGUs.

and charts showing. those emissions are included in the tangential boilers portion of Appendix A. We

believ~ that inspection of the 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/rnm Btu (or lower) '011 a

3D-day rolling average basis during the eastem ozone season. '

J Minnesota Power has stated in its Taconite Harbor BART analysis that "The use of an 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:

• SCR would reduce NO;.: by 73% and result-in an annual emission rate of 0.07

1b/mmBtu.

• SCR capital cost would be $314/kW. This result is much higher than 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 of LNB/OFA+SCR would be $2,258/ton.

• The Incremental Cost of SCR 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 would reduce NOx by

81 % (from 0.26 Ib/mroBtu) and result in an annual emission rate of 0.05 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 lower than the 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."

NOx Step 5: VISIBILITY IMPROVEMENT DETERMINATJfON

WY DEQ: 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 than those 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 of the 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 of costs and benefits for adding SCR to 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, .

Flat Tops WA, Rawah WA, and Eagles Nest WA be included in the 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 (H2S04)

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 H2SOJ

is due to the oxidation ofS02 by SCR to 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 Bridger with'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 of adding SCR is to reduce that

potential S02 by 63 lb/hr while increasing 804 by 10 Ib/hr. If one 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, that would otherwise escape, i.nto

a fonn that can be captured in the air preheater and emission control system.

WY DEQ: While 'visibllity impacts were addressed in a ctlmulative analysis of all 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 unit from 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 of SCR 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.

WY DEQ 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, in part, 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 of chemical reagents (Le., ammonia or urea)

and there is a minimal 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 NOx reductions 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, on the following conclusions:

1. The cost of compliance 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 of LNB \vith SOFA and SCR is parasitic and requires an estimated 3.22

MW to 3.36 MW of po\ver from each unit.

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 of SCR. SUbtracti.ng

the modeled values ftom each other yield the incl:emental visibility improvement

trom SCR. The cumulative 3-year averaged visibility improvement from Post6

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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 of 0.26 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 req uirements'ofBART.

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 of adding 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/SOFA option were '4reasonable,~' we

conclude that our estimates indicate that addition ofSCR 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 of almost $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 of SCR at each of the 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.

R http://www.wrapair.org/fol.1Jms/ssjf/bart.htm I

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 of keeping 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 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 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 Resu Itin!? PM I0 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 Bridger Units 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 power plant.'

PMIO Step 4: EVALUATE IMPACTS AND DOCUMENT RESULTS

Wy DEQ: The cost-effectiveness and incremental cost-effectiveness of applying 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·

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BART CONCLUSIONS

WY DEQ: Existing, ESP with FGC is determined to be BART for Units 1-4 for PM/PM10

based, in part, on the following conclusions: '

1. Recognizing the cost benefit associated with using the existing ESPs and the minimal

energy impact ofinstalling FGe.the cost of compliance for the control technology is cost

effective for each unit, over a twenty year operational life, for reducing PM emissions.

The cost effectiveness for existing ESP with FGC is $ 1,544 tor Unit 1, $526 for Unit 2,

$857 for Unit 3. Unit 4 did not 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 of FGC on existing ESPs can't be directly determined

from the visibility modeling, the Division does not anticipate the PM cOl1:tribution to

be significa.nt when compa.red to NOx and S02 contributions.

NPS: WY DEQ has presented no factual basis for this assertion.

WY DEQ: Existing ESP with a polishing fabric filter was not determined to be BART for

, Units 1.:.4 for PMIPMlo based~ in part, on the following conclusions:

1. The cost of compliance 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, and 4, respectively.

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/mmBtu) and compare its cost-eff~ctiveness to other

baghouse installations to properly assess the "reasonableness" of its 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 Unit 4.

NPS: None of the opti.ons modeled by PacifiCorp or WY DEQ provide sufticient

infonnation to evaluate the visibility improvement resulting from the COHPAC option.

WY DEQ: 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 of BART.

NPS: WY DEQ has not conducted a proper BART analysis because it underestimated the

effectiveness ofCOHPAC and did not eval uate. its visibility improvements.

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LONG-TEAAI STRATEGY FOR REGIONAl. HAZE:

WY DEQ: 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 of managing multiple pollution control installatjon.s within the

regulatory time allotted for installation of BART by the Regional Haze Rule, the Division.

is requiring the installation of SCR on Bridger Unit 3 in 2015 and on Bridger Unit 4 in

2016 for the Long-Tenn Strategy of the 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

of compliance; (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 of each 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 year on 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 Haze rule. ' .

10

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National Park Sen'ice (NPS) Comments on the

Wyoming Department of Environmental Quality's proposed

Best Available 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 A LSTOM.

The unit uses GCP to control NOx emissions. It was originally constructed with a United

Conveyor mechanical dust collector to 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

of the 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.

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Table 1 N h : llUl!1 ton U' OIts I 3 P - roposed Emission 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-hr rolling) Iblhr (b) 340 tpy (b)

Ib/hr (12-month rolling) 833 lb/hr (3-hr block)

New LNB with 0.75 lb/mm Btu (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-month rolling) 1,080 Ib/hr (3-hr block) ·(b)

,

0.75 lb/mmBtu (3-hr 0,5 lb/mmBtL! (2-houJ' 0.015 Ib!mmBtu (24-

Unit 3 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 hr block) (24-hour block) 243 tpy lb/hr (ll-month rolling)

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

(\IJ A vr:raging period b I hour as determined by 40 CFR 60.46 and 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 offOC on Units 1 and 2 was or ginally proposed to occur in

2008, however since the authorization to install the controls s depend.ent on the issuance

of the 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~ of p.: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

WY DEQ: 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 of options.

2

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NOx Step 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

None ofthe four control technologies proposed were deemed technically infeasible.

NOx Step 3: EVALUATE EFFECTIVENESS OF REMAINING CONTROL

TECHNOLOGIES

WY DEQ: 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 NOx ernission 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 of 0.02 Jb/mmBtu to total 0.26 Ib/mmBtu.

Naughton Unit 3 is equipped with LNB and has demonstrated compliance with a 0.40

Ib/mmBtu NOx emission rate. PacitiCorp reviewed the option of tuning the existing LNB

to further reduce NOx emissions 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 of the

Naughton units. A high-dust- SCR configuration, where the catalyst is, located

downstream from the boiler economizer before the air heater and any particulate control

equipment, was used in the analysis. 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 of 0.07 Jb/mmBtu. The potential NOx control options,

and their emissions are shown in Table 3.

Table 3: NOx Emission Rates Per Boiler

Unit 1 Resulting NOx Unit 2 Resulting NO>; Unit 3 R.esulting: NCh:

Control Technology Em ission 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 Permit 3-2·121.

NPS: PadfiCorp and WY ,DEQ have underestimated the ability of SCR 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

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EGUs requiring that they meet 0.05 lb/mmBtu over averagin¥ periods of 24-hoursI 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 or justification 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 of operating data (included in the

tangential boilers portion of Appendix 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 a 24-hour limit and for modeling purposes, bLlt·a lower rate (e.g., 0.05

Ib/mmBtu or lower) should be used for annual average and annual cost estimates.

NOxStep4: EVALUATE IMPACTS AND DOCUMENT RESULTS

NPS: PacifiCorp and WY DEQ have overestimated the costs of SeRe Neither

Pac.itiCorp nor WY DEQ provided justification 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 higher than 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

extraordinarily high costs.

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

• The Incremental Cost would be $8,089Iton.

At Naughton #2:

• SCR would reduce NO" by 73% and result in an annual emission rate of 0.07

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 leasr 20 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 of those

EGUs, and charts showing those errrissions are included in the tangential boilers pOliion of Appendix A.

We beli~ve that inspection of the 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 Power has 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.

At Naughton #3:

• SCR would reduce NO:< by 84% and result in 0.11 anmJal emission rate of O. 07

Ib/mmBtu.

• SCR capital cost would be $415IkW;This result is much higher than 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 Cost would be $1,783/ton.

As recommended by the 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 of 0.05 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 Cost would be $1,073Iton.

The cost of adding SCR to LNB+OFA would be $1,735/tc'ln.

At Naughton #'2:

• SCR would reduce NO;.: 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 Cost would be $9821ton.

e. The cost of adding SCR to LNB+OFA wo'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 of adding SCR would be $860/ton.

. As a result of higher emission reductions5 and lower Total Annual Costs. OLlr .costeffectiveness6 estimates are much lower than estimated by WY DEQ.

We based our a.nalysis on the annual limits proposed by WY DEQ wh kh :lppear to represent 10Cl%,

utili7.atiol1.

G We believe thar the comparison of costs and benefits for adding SCR to LN B+OFA is the most valid lest

for incremental cost-effectiveness because these are the two most-likely candidates for BART.

5

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Even though PacitiCorp and WY DEQ have overestimated the cost of SCR; WY DEQ

determined that "the cost effectiveness and incremental cost eff~ctivenes,5: of the 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 of the facility and Fitzpatrick WA is located

approximately 165 km northeast of the 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 ofless frequent plume transport will experience lower

impacts than those predicted for the 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 of the 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 included in the modeling analysis.

WY DEQ: Wl1ile visibility 'impacts were addressed in a cum:ulativeanalysis of all 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

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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 WA.';

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 WA."

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 WA."

WY DEQ: 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 NOx removed for Unit 1 and $357 per ton

for Unit 2. .

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

environmental mitigation for the use of chemical reagents (i.e., ammonia or urea) and

there is a minimal energy impact. '

3. After careful consideration of the five statutory factors. especially the 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, is justified. ,

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 of the four proposed BART technologies for NOx ~lre

all reasonable."

2. Additional non-air quality environmental mitigation is required ror the use of chemical

reagents.

7

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3. Operation of LNB with advanced <DFA and SCR is parasitic and requires an estimated

1.0 MW 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 of SCR. Subtracting the modeled 98th

.percentile values from each other iyield 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 for NOx based, in palt, on the f&llowing conclusions:

1. The cost effectiveness of tuning 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 of NO,I(

and reasonable as well. Both the costi effectiveness and average cost effectiveness were

based on a twenty year operationallifel for 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

OFA, 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 I areas 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 which included installing SCR.

4. The cumulative 3-year averaged 98th percentile visibility improvement t)'om the I

baseline summed across both Class Iiareas achieved by tuning rhe. existing LNB· with

OFA, SCR, wet FOD, and installing ai new 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

higher than 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 of 0.15 lb/mmBtu for tangemia1-nred boilers burning sub-bituminous coal, though

not applicable, is notjustitied. I

8

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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-unit NOx 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 for NOx. :

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 of adding 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 of SCR at each of the Naughton units would improve: visibility at

a cost of less 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 of SCR cost~effectiv~ by these criteria, it would be even more so if the

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 or baghouses, 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 a polishing fabric filter downstream. of the existing ESPs on

Naughton Units 1 and.2. PacifiCorp artalyzed the impact of installing a full-scale fabric

filter on Unit 3. .

PM10 Step 3: EVALUATE EFFECTIVENESS OF REMAINING CONTROL

TECHNOLOGIES

WY DEQ: Naughton Units I and 2 have existing ESPs and rather than evaluate costs of

replacing· them, PacifiCorp evaluated iadditional controls to improve the PMIO 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 of keeping 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 a polishing fabric filter downstream of the existing ESP. . I

I

Naughton Unit 3 is currently equipwed with an ESP and FGC system. PacitiCorp

analyzed the impact of upgrading 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 sh0'1n in Table 4.

Table 4: PM) 0 Emission Rates Per Boiler

I

Control Technology i Resulting PMfll Emission Race (lb/mmBtu)

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 PM wenmsions from Uriit 1,2, and 3, respectively.

(b) Applied to Naughton Units 1 and 2. .

(c) Applied [0 Naughton Unit 3.

10

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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 1aIb/mrnBtu limit

permitted by EPA ~or the Desert Rock power plant.

PMu) Step 4: EVALVATE IMPACTS AND DOCUMENT RESULIS

WY DEQ: The cost effectiveness and incremental cost effective'ness of applying a new

polishing fabric tilter to Uni,ts land 2 are not reasonable, The cost effectiveness and

incremental cost effectiveness of applying 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 determination process for Naughton 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" of its 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 of compliance 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.

, WY DEQ: Existing ESP with FOC and a polishing fabric filter was not determined to be

BART for Units 1 and 2 for PM/PM]() based, in part, on the following conclusions:

1. The cost of compliance for a polishing 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

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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.

W DEQ: 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 of a 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 of the 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 of BART. Uni.t-by-unit PM/PM10 BART detenninations:

Naughton Unit]: Installing FOe on the existing ESP and meeting PM/PM,o emission

limilS of 0.040 Ib/mmBtu, 741blhr, and 324 tpy as BART foi PM/PMlo. .

Naughton Unit 2: Installing FGe on the existing ESP and meeting PM/PM10 emission

limits of 0.040 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 FOR REGIONAL HAZE

WY DEQ: 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 of managing multiple pollution control installations

within the regtllatory time allotted fOJ:' installation of BART 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 NOx limit,

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.36
D

C m

"' G)

~0 I

"' IS) rableA.1. 21107 C1tdHiNd boll.". w SCR & NOx leu IhIAO.Oillb pammElu dUrll1g alOM season

fo,J .l'>. NUM PRIMARY I OP ORISI'L_ 1<SSOC_S PRG_CODE SU\\ 01' .\lOlITh'S NOX NOX HiiAT FUEt I\.l SrAlUS STATE FACILlN_,'/A'Af. CODE UNIlID OPYEAA IAC~S _IUFO TIME RE.!'CA'lTED RAlE MASS II/PUT INFO UNIT TYPE INfO IlOX COJIlROL IPIfO l/IFO LD IS)

ti)

IS) HC BcI~...."C,...-l< ~42 1 1007 N8P,ARP ),55S 5 O.OJ 4~3 3~,842.308 Caal C41l butner boll", Low "·OK. Cell BU~I Ol/1l!1 Opl!'laling OH Mu,klnglUTl Rh'" 2812 5 2001 NBP,ARP ).015 5 0.1)5 31105 14,121,1I1i Co~1 Cell bu"",r boiler Low /fOx C"II Bum~t Sele Op«aling 011 Cautina' UU 2 1001 NBP,ARP 2,890 5 O.OOS fo,J 32.0 tJ,!I4J.S6Z Cual Cell bUnlerbollel LaN 110" Cell Bu,,",,, Sele- Ojle",Ung ....... 011 ,ifolml Fort GOO210lh19 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 .. Ul

.. I.VI Plaasanll'ral;e 6170 1 2001 A.'olP 3.6'9 !> 0.C6 ~9 22,120,021 Coal 0Jy bD'::~m turboo-fire(J b:J~1 Solecliv" Caraybc Rerlldio (}perall1g UI

IS) OH Car,l"nol 262a 3 200] NBP,ARP ~.5n 5 002 223 19.67'.000 Co.1 01'1 bo&.Jm wall-sred 00 lei Lr'" P<OJ( ItJrn., r"dln"n..J:Opelafnll

-oJ VA ChaSapl!8he Energ,. 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 IN Gibson 6113 1 200] CSIlOO3 NBP.AFlP :I,Wi) S 0.G3 J.52 21,005,175 Coal baltom waU.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... to", reo..!lUm<, Teoonolog' Ope<ao11t-) At Cclnan 47 5 2001 NBI'.ARP :I,5'9~ 5 004 269 H.'42U6 Coal ['<y bclfO10wdll-ti,ed betl... Salaoli,,,, Calalyll:; R..uucllo 01''''''11>;1 W KY Ghenl 13~ ZWl CSOO2 NHP.ARP :1.589 !; 004 230 13.G021,741 Coal Dry bollomw"U.fired boiler lo\Y~IOx f.lOO")gt T~hnolo-'l' 0PefCltfrg VN Mounlilinecr (1:101) 6264 1 2007 NBP,ARP 3.662 5 004 B6S 45,410.&15 Coal C<y t<J1lom ....al-fi'.d boile' l..:twNO): BLni.eJ 1 ed\I1uloO' 0P4tatir..g W

IlA Bc"'(.a' Print 1619 :I 2007 ARP.NBP M7() I

Vtl JoMEAmO<l 3935 , 5 0.04 2B3 11.611.691 Coal 'Cry oonom\val·ftr-erfbQile:f LON NOr. BL"01":', i e(t:'flDI~: Operating LD 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:OIIOIR Vial·firedbeiler taA' NOx Burne< Tedm"n;\, Operating LD K'\' MilOrea' 1364 I J 2(107 IIBP,MlP J,5<I\J ,5 0.05 '337 14.245.770 Ory 1:011001 wall·fired billie I LaKN')x Burner hchnol:la'4lS1aUng VI'I Joh.E,>.tnos 3005 2 2()07 =12 N8P,~.RP fo,J 3A4a 5 0.05 5;)6 21,140.5)2 CoO<! Dry bollcm ,Yo<Jl-nr;v.! bolle' OH Miald Fon G~nan;.~nll SlatillO 2aJ:l 8 2007 Ij8P,ARP 3,4:;9 5 0.05 419 15.742'.714 lCi.... NOx Burner rechr-,..,,-'osI: Opefaling m 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>'..e Calelyl4>er.aI,,'l fo,J 11\ 'Nallel SOOIl Jr. Energy ~.I.r 100l 4 2()07 ,\RP 3,119 ,5 o.~ '311-l19,IJ8.Ul Coal 01', boll"," W<ll-fnd ""i\eo-(5J,!~ La" I\.'O~ Burner redru~CpeFaln!l (51.11«10112712001) VA Cheslenl.la Pvwa, 51!1i0A 3791 6 7(107 IIBP,ARP 3,62.\ 5 0.03 337 21,0&1,310 Coal nngllflll.Uy·l1.ed low reOlt Dumarr.eMol. OperallA!I J)( WApMish 3470 WAP1 2Il07 ARP 3.672 .s 0.(1.1 357 20.4$6.060 Coel ran9cnllally-lt,ed Serull\'11 Catalytic ~educl OperaliRO £AI

IS) VA CIla9apNlke En«gy C.nle, 3603 4 1001 NOP,ARP 3);00 5 O.lI4 119 7,t09,3tlfl CD,I hng.nUally-llJed 5.le<:1l\", CoIla.lylle Red""l Op".llng

£AI MA Brayton Polnl 1519 1 lOOT ARP,NDP 3,657 5 O.~ 14& 8,IIZ2,928 Coar Jangenti611y·firod Low /lOX Burner Tethn.11 Optlrnllnn TX VI Ap~r1.h 3470 WAPU 2001 ARP 3,632 Ii 0.04 ~7& 11,I(}J,6054 Coal hnyenUally.J1red SEloeli'". Calalytic R.<I~1 ojWteting ti). PI'. Kevalone 31:16 Z 1001 /lRP.NBP 3.446 S 0.05 U8 24;,109,153 C".1 Jangenllal/y-<ice<l Low tl'?x Burner TU:hn~.( Opeli!ling (J'l VA Chesrertleld ,..."... 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

I\.l 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

rn 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.....ling I\.l 11'1 KlngS./o. J.407 Z 2001 CSKIIS I!BP,ARP 3.&12 5 1l.05 113 4,545,096 Coos I nnsenU.lly-l1re<l seleellve Ca/alyllc RJ!<!ucl Ojl....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 To rtllenJla II)'·nred Seleeliv~ CaUIy\ic R.Hlucl \hJ"~ling Z TN Kingston ~~7 6 2001 CSKfBl1 IIBP,ARP 3,~1l1 5 0.05 t~5 S,750.031 C<>al Tallgenllally·/ired LJ l<1\Y 1\.'0" Bumar Teclu10lc Ope,...,lng TN Klngs'''n 3401 7 2001 CSKI69 HBP,ARP (f) ',644 5 0.05 150 6,011,466 C<>tol T~ng~nIf4I1y,lirod Lew "'-'"(h: BurnEr Te-cIUlCll£ Operolting GA I lII&l1sJey (5062J O()S"Z Z 2001 I\RP 3.654 S 0.05 176 30,038,&9'9 Coal TangenJlally.n,ed Low HOlt BumGr Te:d\t'I01( OpereJinl D TN King5(on J.407 8 21)()7 CSKI59 IlDP,ARP .3,672 5 0.06 IS6 &.10),5!n Coal TangenUally·fi•• d Luw 110" Burn..TeclU10lc Ope...Un" AI 11'1 Kingsron 3-401 9 21Kll CSKI59 IIBP.ARP J,6()7 5 0.05 1511 6.205.040 Coa.l T•.l1\1e<lUally-lired S.l<oc;tive ealolly1le Rdducl Ope... ling t::J GA VloU\<Joy (5M~) S(]S2 1 2G07 ARP 3,611 6 0.05 757 28,1114,34.9 Coal Tan!lellll"lIy.lired Low 'lOx Bu,ner TEtllnol, Operel/ng WoI Moun. stonn PCwef Slation )95-4 2 2001 CSO /IBP, AftI' 3,~e 6 0,05 414 '60,489,5l14 Coal T' ngffillaUy.6,ed lo'" /lOx Bur""r TEChnoll Opetalil>!1 IX Vl'APafiSl'l 3410 W....P5 200] ARP J,5:38 5 U04 4t>J 24.2:10.599 C"",,, Wei boll...ll .....~"-rr.dboi:.r ('S1-"1 Selecti<e CaWroc Re>.1ucijJ O~....ljOJ IX WAPa,1Sh 3470 \'h\P6 2007 ARp J,670 Ii no~ 448 22..911,791 C1lil/ Welbollom'MilI-!,e<l b:if""(staJ Salecliv. C,r.'y1ic Reducllo 0"E<a.li1>;l

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08/02/2009 20:50 303-959-2822 NPS-ARD PAGE 38178

Appendix A: SCR Effectiveness on

Eastern Tangentially-Fired EGIJs

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Appendix A: SCR on Eastern Tangentially-Fired EeUs

If we 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 Low NOx 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 SCR was actually operating:

["Appendix A. Summary 0[2006 Ozone Season data for Tangen.tially-fired EGUs.xls"]

The summary table indicates that there is little variation 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 than the 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 indicatesmuch more variation, as one might expect for

this extreme value.

We suggest that the bottom section of the 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 a 30-day limit ofO.081b/mmBtu, but take a look at this:

["Appendix A. Widows Creek 8, 2006 ozone season.xls"]

If one had only the Ib/mmBtu data, it would seem that there is a lot of variation in the 30-

day average emission rates at Widow's Creek #8, and the maximum 30-day average is 2.6

times the average ozone-season average However, if one 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 of maximum 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 of the mass emission

AUG-04-2009 15:07 303 969 2822 98% P.39
08/02/2009 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

indicate that this ratio is 1.1:1 for these EGGs.

So what'? If we 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 a 30-day rolling average

limit of 0.06 Ib/mmBtu would provide more than an adequate margin of safety for

the EGU 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-d

av (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 ...

0.052 1.0 0.053 1.0 0.052 89 1.0 86 1.0 8a

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

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AUG-04-2009 15:07 303 969 2822 97% P.42
08/02/2009 20:50 303-959-2822 ~~P5-ARD PAGE 43/70

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AUG-04-2009 15:07 303 969 2822 98Y. P.43
08/02/2009 20:50 303-959-2822 t-PS-ARD PAGE 44/70

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08/02/2009 20:50 303-969-2822 NP5-ARD PAGE 47/70

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08/02/2009 20:50 303-959-2822 NPS-ARD PAGE 48/70

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08/02/2009 20:50 303-959-2822 NPS-ARD PAGE 49/70

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AUG-04-2009 15:07 303 969 2822 98% P.49
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"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 Procmement Activities - Environmental Equipment Apr 2006 - 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 Apr 2009 - 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 Apr 2009 -Sep 2009

Gd\;;l-SdN (;(;8(;-595-EGE
SS'd %86

Appendix C: SCR Costs

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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 BART for the San Juan Generating Station

hup:llwww.nmenv.state.Dm.us/aqb/reghazldocuments/03292008DiscussionofOAQPSCostManualMethodRev080329.pdf

8CR Capital Cost Survey Results

from Table 7-1. ofCURRENT CAPITAL COST AND COST-EFFECTIVENESS OF POVlER PLANT EMISSION CONTROL

Prepared by J. Edward Cichanowicz for Utility Air Regulatory 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 of unit cost and scale.

Cichanowicz, 84 (600-899 MW) to 128

56-185

2003. For four categories ofgenerating capacity, the least cost

2004 (100-399 MW) units were among the first instaUed.

Marano, 118 (>900) to 167 «300 Most costs reponed to 2005. "Units with a capacity of600 to 900 MW appear to be more

2006 MW) be within 100-200 difficult to retrofit than those in other size ranges."

Estimation of Costs and ImpactlJ of NOx Control TechnolDgies Applied to the PGE Boardman Plant

http://www.deq.slate.or.lIs/aq/haze/docslergMemo.pdf

Average and Low-High Cost Observations

Reference Capital, MW ($lkW, Cost Basis

2006 Basis) Observed ($/kW)

ERG 2008 227 207 - 267 2007

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Appendix C: SCR Costs

for

Wyoming EGUs

Subject to

BART

8ULf; 39\;j'd 0080-595-E8E 8f;:80 5880/08/88
8S"d %86 cc8c 696 [E![

Bridger SCR Cost Estimates • uSIng

(OAQPS Control Cost Manual

I

0L/8S 39\;;id Ge:!\;;i-SdN 6686-595-E0E GS:G6 5006/60/80
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$ 3.000 1m3 from Company report $ 3.Gfi\1 im3 from Company report $ 50 IMWh from Comapny report $ 400 ton from Company report

6,000 mmBtuIhr from WY DEQ report

52,560,000 mmBlu/yr from WY DEQ report

OAQPS Control Cos

I 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+09I

Number of SCR Operatin~ Days 365

I

Plant Capacity Factor 100%

I

Uncontrolled NOx Concentration (lb/mmBtu) 0.41

LNB

+ OFA Talal Capital Cost$ 11,300,000

LNB+ OFA Talal 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 Molecular Weight (Q/mole) 17.03

Reaqent Density (Ib!ft3@ 60F) 56.0

Reagent Specific Volume (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

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621iiB.Oi Ib/hr

621118.01 Ib/hr

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qfluegas:: 2,962,552 acfm

2.8 CFSCR=tsCI/365 days

CFSCR= 365 daysl

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2.11) Vol~",~ 2.81x Qnx 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+ (0.0455x S)

Sad!= 0.9636 ..( 0.0<16• 0.58)

SarJj= 0.990

2.24Tulj= 15.16- (0.03937 xT) >(2.74x 10.

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Tadj= 15.16·( 0.039• 650) -I 2.74E-O:i·

Tadj= 1.146

Volcalalvsl= 23.906 03

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AtillatJ'i1= 2962:152 I( 16•

Acala)/st= 3086 "2

2.26 A'CA=I.15x "\""'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'''X A""tlYL)

nfa'l""= 23906 I( 3.1•

~a,..er= 1.0

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a1% .. 17.03

I 46.01

2.33 m-dorsal= m-dOl:rc~gcnrlC.oJ

m-dotsoJ= 490I

m-dotsol= 1689 Ib/hr

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qsol= 226 gph

2.35 Tank Volume= gsa,t

Tank Volume= Tank Volume =

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[(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) =

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19,063,005

$3,3BO + $ 61 +' $ {14} + $ - + $ - )"( 3500 I 6000)" 0.35 + $2,032,521

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Retrofit factor= Retrofit faclor =

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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

$

0.20A= 0.15 (A+B)

=

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=

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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 Cost0 ==

Allowance for Funds During Construction,E= Royalty Allowance, F = Preproduction Cost, G ==

Inventory Capital, H =

Initial Catalyst and Chemicals,I= Total Capital Investment TCI =D+-G+H

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.~!!!!~!fW;iiilii~ D:\C= Annu..! Mail1hmsnce C",1-1- AmiUAlll.esgecl Cas' ;- Arutu:J1 mcclriQityC....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' 85.01561511I 1.

C81alysl Rep'ccemenl Cosl= II 1.016,260

2.52 FWF =i{I/((I+-1)Y-I)}

1.5JY= hc.,IIA.",

y= 24000 f( 42~J,• 8760)

y=6

FWF= O.W '(I I(11 0.07 )'6• 1 )

fWF= [114

Annual CalBl~",1 Cost=S '42.0B9

DAC=S 2.42l1.6:W.

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CRF= 0.07 '(

CRF= 0.0044

1+ 0.07 )' 20/«(11 0.07)' 20- t)

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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.'<hQ

pl",

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

T01;01 Cosl effeclr;"n"ss=S 7S>

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IndirfCl Anll'Jill Cost

Indirecl AnrfJal Cost=S

Tol:aJ NOx Removed=

, Tel

009.4' $36.257,572

3.422.458

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$ 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/hr from WY DEQ report

52,560,000 mmBlufyr from 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&w or Retrofit? Retrofit

Extra retrofit cost factor 1.0

Generation capacity (MW) 530

SCR bvoass Include.!!? f\Jo

II

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

Number of 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 Molecular Weight (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 of Storage tor Ammonia 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

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. LNB Control Efficiency::: {Inlet Cone- Outlet Conc}/lnlet conc ( 0.41 0.26 )1 0.41 '" 36%

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Boiler Calculations

2.7 CFplbot= actual mfuel/maximum mfvd

CFPlanl= 5A4E+09 Ib/yrI 8760 hr/yr/

CFPlant::: 100%

OS=

OS=

2.3 On

= HVrn-dotruel

9660 Slullb

6000 Blu/hr

621118.01 Ib/hr

621118.01 Iblhr

rnm

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 11

N

ox=(NOXU1- N0Xou,)/ NOxin

llNOx = ( 0.26 IblmmBtu-

llNOx::: 81%

Uncontrolled NOx emissions (tpy)

2.8 CFSCR=tsCR/365 days

CFSCR= 365 daysl

CFSCR

= 100%

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365 days

100%

10643

CFTotal= CFPlaDIX CFSCR

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100%

CFTotal=

CFTolal

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NOx removed=

Controlled NOx emissions (tpy)=

9329lpy

1314lpy

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= 88%

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SCR React<JI Calculation.

2.19 Vol",,~l'''= 1.81x OnXTJuljx Slipo.<jx 1'\Ox,q;xXT.l/N"'....

Volcalalysl= 2.81' 6<JOO= /I1i1Hl

2.2 'lulj= 0.2869+ (1.058x II)

I]adj= 0.2969 ..( 1.1• 0.111)

1]1lU,= 1.141

2.22 SJil\..1·=1.28J5- (0.0567x Slip)

Slipm:lj= 12835 .( 01• :>)

Slipadf= 1.171)

2..11 NOx,y= 0.&524+ (0.320&x NOxio)

N:Jxauj= 0.852.01 + ( 0.3• 0.76l

NOxadj" 0.936

1.23 SaIj= 0.%36t (0.0455X S)

'Slldj= 0.963$ + ( 0 • O.M)

Sadj= 0.990

1.24 '["Ij= 15.16- (0.039]7X T)+ (2.74X 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,ccX60 seclmin)

Aca/al/sl= 2962552 f( 16• 60)

Acalal»sl=. :!lM6 if2

1.26ASCR= 1.15X A~

ASCR= 1.15• 11##

ASCR= :!6~9 "2

111 2.27 1= IV = A'e!<

I"w= 59.6tl

422500

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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)

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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

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Reagent Calculations

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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-dot50J :::: m-do~getiC50r

m-dotsoJ= 490I

m-dotsol= 1689 Iblhr

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2.35 Tank Volume= Cloolt

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2.34 ~l :::: (m-dot"XltlPsol)Vso1

qsol::; 1689"

qsol ::; 226 gph

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2.37

f(hSCR) = f(hSCR) =

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0....

Direct Capital 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

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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) for no 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) =

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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

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