## North Dakota State Implementation Plan for Regional Haze Supplement No.1

A Plan for Implementing the Regional Haze Program Requirements of Section 308 of40 CFRPart 51, Subpart P - Protection ofVisibility

North Dakota Department ofHealth Adopted:**r~l-ICJ**

Division ofAir Quality Air Pollution Control Program North Dakota Department ofHealth 918 East Divide Avenue Bismarck, North Dakota 58501-1947 Telephone 701-328-5188 Terry Dwelle, M.D., M.P.H.T.M. State Health Officer Terry O'Clair, P.E. Director

## APPROVAL PAGE North Dakota State Implementation Plan for Regional Haze Supplement No.1

North Dakota Department of Health, Environmental Health Section, Division of Air Quality. Approval by 

### the following North Dakota Department of Health Management Personnel:

Terry L. 0' lair, P.E., Director Date Division ofAir Quality



### ,P

.., Environmental He_-..."... Datk 

# I

Adopted for the North Dakota Department ofHealth

7 

### Terry L. 

### ,.D.,M.P.H.T.M. Date State ealth Officer North Dakota Department ofHealthTable ofContents Supplement No.1 to North Dakota State Implementation Plan for Regional Haze Supplementary Cost Information Montana Dakota Utilities Cost Estimates North Dakota Department ofHealth CUECOST Model Spreadsheets (verification only) Appendix A.2.4

- Permit to Construct Appendix F.I

- Public Participation Record F.I.l

- Public Notice F.1.2 Affidavit ofPublication F.1.3

- Invoice ofPublication F.1.4 Response to Public Comments Appendix J.l.S

- National Park Service Consultation Comments on Supplement No. 1 and Department's Response Appendix J.3.3

- U.S. Environmental Protection Agency Comments on Supplement No.1 and Department's ResponseSupplement No. 1
to North Dakota State Implementation Plan For Regional Haze

August 2010

North Dakota Department ofHealth Division ofAir Quality Air Pollution Control Program 918 E Divide Avenue Bismarck, North Dakota 58501-1947

### R.M. Heskett Station Unit 2 The Department has finalized a Regional Haze SIP revision. During preparation of that SIP revision, there was a disagreement as to whether RM. Heskett Station Unit 2 was subject to the Best Available Retrofit Technology (BART) requirements. On November 25, 2009, Montana Dakota Utilities Co. (MDU), the operator ofthe station, supplied the NDDH a revised BART modeling protocol as necessary to complete a refined visibility impact analysis for Unit 2. The NDDH and EPA Region 8 reviewed and approved the modeling protocol in early December 2009. MDU subsequently supplied the Department a report titled "Updated BART CALPUFF Visibility Modeling Analysis for Montana-Dakota Utilities Heskett Station Unit 2," dated December 17, 2009, which set forth the refined visibility modeling analysis for RM. Heskett Station Unit 2. The modeling report concluded that the facility will contribute less than 0.5 deciviews ofvisibility degradation in any Federal Class I area. The Department and EPA Region 8 reviewed the modeling and subsequently determined that R.M. Heskett Station Unit 2 is not subject to BART requirements. Because ofthe additional modeling and review, the NDDH was unable to timely address Unit 2 under the Reasonable Progress portion of the original SIP revision. Since the question ofBART applicability has now been resolved, this SIP supplement provides an analysis ofR.M. Heskett Station Unit 2 under the Reasonable Progress requirements of40 CFR 51.308(d)( 1). RM. Heskett Station Unit 2 consists ofan atmospheric bubbling fluidized bed boiler that has a rated heat input of 916.5 x 106 

### Btulhr. The boiler serves a single turbine/generator that can produce approximately 78 megawatts ofelectricity. The facility primarily burns North Dakota lignite from Westmoreland Coal Company's South Beulah Mine near Beulah, North Dakota. The unit occasionally burns subbituminous coal and tire derived fuel. The plant had initial startup in 1963 and was converted from a spread stoker combustion unit to a bubbling fluidized bed unit in 1987. Currently, the bed material in the combustion unit is made up ofsand. Table 9.S Sources Evaluated for Additional Control Source Owner Unit Type 

## I Capacity Heskett Station MDU 2 EGU 

## I 78MWe

Table 9.6 Remainin Sources Existing Conditions Current Current Control Emission Rate Control Eff. Source Pollutant Equipment (lb/106 

### Btu)* 

### (%) Heskett 2 S02 None 0.91 N/A NOx 

### None 0.36 N/A *Based on 2007-2008 data.Table 9.7 Control Options Evaluated Estimated Control Control Eff. Source Pollutant Considered 

### (%) Heskett 2 S02 WS+LJ. 96

i WS CDS+L.I. 95 95 SD+L.I. i 94

CDS 92 Spray Dryer 90
i Limestone Injection 60 NOx LDSCR 70-90 TESCR 70-90 SNCR 30-50 Staged Combustion 20

WS 

## =Wet Scrubber LI 

### = Limestone Injection CDS 

### =Circulating Dry Scrubber SD = Spray Dryer LDSCR

## =Low Dust Selective Catalytic Reduction TESCR Tailend Selective Catalytic Reduction SNCR Selective Non-Catalytic Reduction Staged combustion combined with SNCR is not technically feasible for the Unit 2 AFBC due to staged combustion decreasing the temperature ofthe flue gas in the upper portion ofthe boiler. Also, there would be space constraints with the addition of overfire air ports and adding, and appropriately spacing, the urea injection for the SNCR system.------- --- ------ Unit Pollutant Source 2 Heskett SOz

NO" Control Technology

WS+L.I. WS CDSlBag+L.L SDlBag+L.L

CDSlBag SDlBag

L.L LDSCR TESCR SNCR Staged Combustion Total Annualized Cost 

## (st 13,35],000 12,302,000 1l,945,000b 10,864,000 10,985,000b 9,815,000 1,050,000 5,216,000 6,049,000c 1,424,000 366,000 Control Efficiency (%) 96 95 95 94 92 90 60 80 80 33 20 Emission Rate (lb/lO' Btu) 0.036 0.046 0.046 0.055 0.073 0.091 0.364 0.072 0.072 0.241 0.288 Emissions Reductions (tpy) 2,582 2,556 2,556 2,539 2,475 2,421 1,614 858 858 354 215 Table 9.8 Control Options Cost

aCosts provided by MDU unless otherwise noted. The MDU costs were in 2006 dollars which the Department adjusted to 2009 dollars. b Department estimate based on Leland Olds Unit 1. "-peQartment estimate based on cost estimate for M.R.**Youn~** Station. Cost Effectiveness ($Iton) 5,171 4,813 4,673 4,296 4,402 4,054

651 6,079 7,050 4,023 1,702Table 9.9 Visibility Improvement and Cost Effectiveness

Source Pollutant Control Technology Emissions (TPY) Visibility Improvement (dv)* Visibility Improvement elo) Cost Effectiveness ($/dv) Heskett 2 S02 NOx NOx L.I. SNCR Staged Combustion 1,076 719 858 < 0.009 < 0.009 < 0.009 <0.05% <0.05% < 0.05% > 116,667,000 > 158,222,000 > 40,667,000
*The Department modeled one scenario for this source - 95% S02 control plus 40% NOx control. This scenario produced a 0.009 deciview improvement at TRNP and a 0.003 deciview improvement at LW A for the most impaired days. Time Necessary for Compliance The Department believes up to 6.5 years would be necessary for some ofthe control options (Le. scrubbers and selective catalytic reduction). Other options such as SNCR and limestone injection into the boilers could be accomplished within 2-3 years depending on outage schedules. The Department recognizes that limestone injection in the Unit 2 AFBC may potentially cause an increase in other pollutants for which a separate Permit to Construct, including a PSD permit, may be necessitated. If a related Permit to Construct is required, that permitting schedule may impact the timing ofthe contemplated S02 emissions reductions required by this Supplement. Energy and Non-Air Impacts All ofthe technologies will consume energy. However, the energy impacts would not preclude the selection ofany ofthe technologies evaluated. Remaining Useful Life Table 9.10 Remaining Useful Life

Source Unit Startup Date Estimated Remaining Useful Life (yrs) Heskett 2 1963 20-40 The remaining useful life ofthe source would not preclude the selection of any ofthe control options.Reasonable Progress Goals - Required Controls for Point Sources The costs to install a wet scrubber, circulating dry scrubber or a spray dryer, with or without limestone injection into the boiler, is considered excessive both on a dollar per ton basis and a dollar per deciview basis. The cost oflimestone injection on a dollar per ton basis is reasonable; however, it provides virtually no visibility improvement (estimated at less than 0.009 deciviews) and the dollar per deciview cost effectiveness is excessive. The Department is not aware ofSCR ever being installed on a fluidized bed boiler. A HDSCR is considered technically infeasible. The cost effectiveness of LDSCR, TESCR and SNCR is considered excessive both on a dollar per ton and dollar per deciview basis. The cost effectiveness ofstaged combustion, on a dollar per deciview basis is considered excessive. The Department concludes that the addition of emission controls at Heskett Unit 2 is not reasonable at this time. However, this source, as well as all other point sources, will be reevaluated during future planning periods. The estimated amount of improvement from operating limestone injection and staged combustion at Heskett Station Unit 2 is 0.006 deciviews improvement at TRNP and 0.002 deciviews at LWA at a capital cost of 5.8 million dollars and an annualized cost of 1.4 million dollars. Combining these controls with the controls considered for the other Reasonable Progress sources, the combined capital cost is 249 million dollars with an annualized cost of69 million dollars. The combined cost effectiveness is over 616 million dollars per deciview at LWA and over 1.92 billion dollars per deciview at TRNP. For all sources evaluated individually and cumulatively, the cost ($/dv) is considered excessive. Therefore, no additional controls are proposed for the non-BART sources during this planning period.10.6.1.3 R.M. Heskett Station Unit 2 

### In Section 9.5.1, it was concluded that requiring additional air pollution controls at R.M. Heskett Station Unit 2 was not reasonable. However, the Department and Montana-Dakota Utilities has reached an agreement whereby limestone injection into the boiler will commence within five years after EPA approves the Permit to Construct for Heskett Unit 2 as part of this Regional Haze SIP. A Permit to Construct will be issued and is included in Appendix A.2.4. The Permit to Construct requires at least 70% control ofthe potential S02 (coal-to-stack) or no more than 0.60 Ibll06 Btu (12-month rolling average) emission rate. This will be a 34% reduction from the 2007-2008 baseline emission rate or a 573 ton reduction from the 2000-2004 average emission rate. Although MDU and the Department have agreed to a reduction of S02 emissions at Heskett Station Unit 2, this source will be reevaluated for additional air pollution controls during future planning periods.Supplementary Cost InformationCost Estimates

In order to estimate the cost ofvarious control options for R.M. Heskett Unit 2, the Department used data provided by Montana Dakota Utilities (MDU), CUECOST Model output, calculations using EPA's Air Pollution Control Cost Manual, and data from other in-state BART analyses. MDU had drafted a BART analysis for this facility and provided cost excerpts for several technologies (copy attached). The costs were estimated using 2006 dollars, so the Department adjusted those costs to 2009 dollars using the Marshall and Swift Equipment cost index for the electric power industry. The Marshall and Swift Equipment cost index has increased approximately 13% from first quarter 2006 to fourth quarter 2009 (1219.2 to 1377.3). To verify the costs, the CUECOST model was run. The CUECOST model provides costs in 1998 dollars so adjustment had to be made to have an apples-to-apples comparison. To adjust the CUECOST capital cost results, the Department reviewed available data from several cost indexes to arrive at an average value.

Index 1998 Index Date of Available Data Recent Index Percent Increase I Engineering News

- Record I Construction C.l. 5920 1110 8660 46%

Chemical Engineering Plant C.I. 390 2/09 532 36% Marshall and Swift Equipment

. Cost C.l. 1062 11109 1377 30%

Consumer Price Index 162.2 10109 216.2 33% Avg. 36% Due to limited data on the increase ofoperation and maintenance costs, a 36% increase was also applied to O&M costs. For the circulating dry scrubber (CDS), data from the Leland Olds Unit 1 BART analysis was used. This data suggested a 12% higher annualized cost for a CDSlbaghouse than a spray dryerlbaghouse. For the various technologies, the estimated annualized costs from the various sources in 2009 dollars were: 

# lTechnology MDU CUECOST Control Cost Manual I Wet Scrubber $12,302,000 $11,154,000

SDlBaghouse $9,815,000 $12,212,000 SNCR $1,424,000 $603,000 $645,000 The MDU cost estimate for a wet scrubber is approximately 10% higher than the CUECOST model estimate and the spray dryer cost is approximately 20% less than the CUECOST model.

### Since these values are within the range of accuracy of the CUECOST model and EPA's Air Pollution Control Cost Manual of±30%, the MOU costs were used. For SNCR, the MOU cost is 2.4 times the CUECOST model. The Oepartment reviewed BART cost estimates from other small power plants to determine which estimate was appropriate. Based on the results below, the MOU estimate ofannualized cost appears to be reasonable.

Source 

### Heskett 2 Stanton 1 North Shore #2 J.E. Corette Taconite Harbor #3 Avera e For low dust SCR, MDU used a capital cost factor of $250Ikw. This falls in the mid range of SCR costs as ERG reported for a high dust SCR at the PGE Boardman Plant. Estimates for Leland Olds 2 and Minnkota 1 and 2 range from approximately $335

- $700/kw 

### for a low dust SCR. ERG, in their analysis for the Boardman plant also indicated that SCR costs have rapidly escalated since 2004. ERG also notes that they believe the CUECOST model does not accurately predict installed costs for major construction projects such as SCR. The Department also believes EPA's Air Pollution Control Cost Manual does not accurately estimate SCR costs. Therefore, MOU's cost estimate was used in this analysis although the estimate appears to be low based on the other estimates and ERG's analysis.Montana Dakota Utilities Cost Estimates

# "MONTANA-DAKOTA • UTILITIES

# ca ADMsIon dIIDIJR/I$QUICeSGroup, Inc. 400NodhFowfISI1eet Bismarck. ND.58501 {701 J

222·79tXJ February 3, 20

### to Mr. Tom Bachman North Dakota Department ofHealth Division of AirQuality 918 East Divide Avenue, 2nd Floor Bismarck, ND 58501-1947 

### Re: Montana-Dakota Utilities Co. - R.M. Heskett Station Unit 2 Best Available Retrofit Technology (BART) Emissions Control Summary DeQJ'Mr. Bachman: In response to yourrecent request for additional information related to regional haze impacts for Heskett Station's Unit 2, please find enclosed a summary ofrelevant materials related to S02 and NOx BARTcontrols that were historically evaluated for Unit 2. 

### In anticipation ofpotential regional haze regulatory impacts to Unit 2, Montana-DakotaUtilities Co

.. (Montana-Dakota) conducted a BART control eValuation in late 2005 and early 2006 that remained in draft form. The complete draft evaluation is rather lengthy. Recognizing your familiarity with the various control technology descriptions and impacts from reviewing BART analyses for North Dakota utilities, Montana-Dakota has excerpted information directly relevant to the**S~** and NOx emissions control evaluation at Unit 2 and has provided this information in Attachment A. Minorcorrections and updates have been made to the excerpted 2006 draftreport;

.however, the cost datahave not been updated. Additional detail related to the background ofthe evaluation and conclusions may be provided upon request. We-understand thatthe North Dakota Department ofHealth may use this information in partto assess Unit 2underthe reasonable progress goals in its Regional Haze SIP. In doing so, please appreciate thatthe 2006 analysis may not reflect current regional haze policies. Nevertheless, itprovides auseful site-specifictechnical evaluation. Also recognizing that the control cost information may have changed since the evaluation was completed in first quarter 2006, Montana-Dakota has provided for reference a cost index table for the electrical power industry. The values shown below are from the Marshallimd Swift Equipment Cost Index and compare the cost between first quarter 2006 and fourth quarter 2009. The Vatavuk Air Pollution Control Cost Indexes (VAPCCI) was discontinued by EPA a few years ago. In lieu ofa site-specific cost update for the technicaJly feasible emission controls, the Marshall and Swiftindex provides a reasonable general estimate ofthe change in cost of equipmentMr. Bachman February 3, 2010 Page 2 

### MCJITANA-DAKOTA UTUJTlESCO.

Marshall and 

### Swift Equipment Cost Index';" Electrical Power Industry 

### Year Quarter 

### Index 2006 QI 1219.2 2009 

### Q4 1377.3 Ifyou have anyquestions about this submittal orrequire additional information to complete your analysis, please contactme at 701-222-7844.

Sincerely. 

# f /}/

..**~** 

# 4**$~**

Ms. Abbie Krebsbach Environmental Manager

- Power Production Ene.
cc: Alan**W~lte,** Generation Manager Tony 

### stroh, R. M. HeskettStatism Manager Joel Trinkle, Barr Engineering Company

### MaVTANA.lJAKGrA lJ77LI71ESCO.



### AtlilchmentA 

### Excerpts from 2006BART

### EvaiUlltlon at

### R.M. 

### HeskettStation Unit2

### ExcerptedR.M.Heskett StationUnit2,(Main Boiler)DraftBARTAnalysis from May2006 Prepared for Montana-Dakota Utilities Co. by Sargent & 

### Lundy and BarrEngineering Company
1.0 " BARTANALYSIS FORMAIN BOILERSULFURDIOXIDE (S02)

. Sulfuremissions from coal combustion consistprim81jly of**S~,** with a much lowerquantity ofS03 and

gaseous sulfates. These compounds fonn as the organic and pyretic sulfur in the coal is oxidized' during the combustion**proc~ss.** For .pennitting and**d~sign** purposes, it is assumed that 100% ofthe fuel sulfur wiIlconvert to S02 duringthe combustion process, and that 1 % ofthe uncontrolled S02 will oxidize to S03within.the fluidized combustion bed.
The generation ofS02 is directly related to the sulfur content and .heating value ofthe fuel burned. The sulfur content and heating value ofcoal can vary dramatically depending on the source ofthe coal. Heskett Unit 2uses North Dakota lignite or a blend oflignite and PowerRiver Basin (PRB) coal as its fuel source. Tabl,e 1-1 provides a summary oftbe lignite used at HeskettUnit 2, includingtbe heating value and sulfurcontent. Table 1-1

. FuelCharacteristics

1.1 Step 1: IdentifyAvailable RetrofitS02 Control OPtions ' Several techniques can be used to reduce S02 emissions from coal combustion sources.**S~** control techniques can be divided into pre-combustion strategies, combustion techniques, and post-combustion controls.**S~** control options identified for potential application with atHeskettUnit 2 are listed inTable 

### 1-2.

# --


# --

--

-- ExceIpted R.M Heskett Station's Unit 2 

### Draft BARTAnalysis
Table 1-2**S~** Control OptionswithPotentialApplicationto a 

### LigniteIPRB Fired

### AFBC 

### Boner Pre-CombustionControls Fuel Switching Fuel Washing and Benefication Combustion Controls Atmospheric FluidizedBed Combustion (AFBC) Technology 

### with Limestone Injection**Post-Co~bustion S~**  ControlTeelmologies WetFlue Gas Desulfurization Wet Lime Flue Gas Desulfurization Wet LimestoneFlue Gas Desulfurization Dry Flue Gas Desulfurization Ash Reinjection Systems Spray Dryer Absorber Circulating Dry Scrubber , Dry Sorbent Injection
1.2 Step 2: Eliminate TecbnleaUyInfeasibleRetrofitOptioDS Results ofStep 2 of.the S02 BARTAnalysis (technical feasibility analysis ofpotential S02control technologies) are summarized in Table 1-3; Table 1-3 TechnicalFeasibility ofPotential SOz ControlTechnologies ApprOLSOl**~** ,- ConcJnUation:iil,

# :'''_~ :":'r.SftviCe,on AllliE . " .',**'>'fHh~C~~bu.stlon** Flue Gas TeclmlcallyFeasiblefor ControlTechnology**,'t~'::~:~liJt;'** 

## ",:"','**$p~f** ' (ppmvd @VA 02l**H~,tt** Vnit21 No. Fuel switching would AFBCs have been Fuel Switching 

## - require significant boiler variety offuels. designed to burn a modifications and would not significantly reduce controlled S<h emissions from Heskett Unit 2. Washing has not No. Washed coal has notbeen Coal Washing X used in AFBC boilers. and will burned inAFBCs. been used on coal not significantlyreduce controlled**S~** emissions from Heskett Unit 2. Processed coal has No. Processed coal has not been Coal Processing X
,been demonstrated demonstrated on a long-term in PCboilers. basis in AFBC boilers. and is not commercially available as a retrofit technology.

2Excerpted R.M Heskett Station's Unit 2 DraftBART Analysis

.**'C9I1."l-T~olo2Y** Appl'GL 80:1 ConeentraUon in Flue Gas (ppawd @3% (h) InService on Emting ADC·BoUers

Yes No .. InSentCC'.QD.'.· '.**Othe:rcoin~oa': $o~1:**  . .;.'.:
.., .. . ·.TtdmteallyFeasible for 

### "'ttUait2? AFBC Boilerwith Limestone Addition (1.5 to 2.0

## cats ratio) approx. 180

. X



# . Yes. HeskettUnit2 CUITeIltly

. uses sand to sustainthe combustion bed. The bOiler and associatedmaterial handling systems could be modified to utilize limestone. AFBC +WetFGD approx.50 X Wet FGD has been used on coal

..fired PC boilers. Yes, however, no commercial experience oroperatinghistory, and question aboutcommercial availability. AFBC + DryFGD (Spray DryAbsorber) approx.60 X Yes, howeverlimited commercial experience.
AFBC + DrySorbent Injection >60 X No. nottechnicallypractic8.J on a AFBC boilerbecause ofthe unreacted lime concentration alreadyin the flue gas. AFBC +Circulating :DrySCJUbbei approx.60 X CDS control systems are in use on alimited number ofcoal-firedunits. Yes. howeverlimited commercial experience.

1.3 Step3: Evaluate ControlEffectiveness ofTechnically FeasibleTechnologies The control effectiveness ofeach technically feasible retrofittechnology was discussed in Step 2. The

. effectiveness ofeach retrofit technology identified as beingtechnically feasible for**S~** control are presented in Table 1-4 in descending order ofcontrol efficiency_ Table 1-4 SummaryofTechnicallyFeasible MainBonerS02 ControlTechnologies 

# ' .**·".~_tlM** CoDfro}Teelmology**S~EmJssij)D:'** Rate' '; :': nIL :'
..:. .' " .frtoiD·

.....

### um

'

.. ...,**::-~.~(t)** AFBC with Limestone Addition plus WetFGD 0.10 95% AFBC withLimestone Additionplus

.D1yFGD (SDA orCDS) 0.12 94% AFBC with**Lim~stone** Addition 0.35 83.3% AFBC with Sand 0.862 60% Potential Uncontrolled S02 (baseline) 2.10 (1)Overall reduction efficiency takes into account**S~** reduction in the AFBC and the post-combustion control system, and is 

### based on an average uncontrolled S02 emission rate of2.10lblMMBtu.

3Excerpted R.MHeskettStation's Unit 2DraftBARTAnalysis
1.4 Step4: Evaluate Impacts andDocumenttheResults Step 4 ofthe BART determination requires an evaluation ofthe economic, energy, and non..;air-quality environmental impacts ofeach technically feasible retrofittechnology. This evaluation should take into considerationthe remaining useful life ofthe unit. Table 

### 1-5 presents the capital costs and annual operating costs associated with building and operating each control system. A summary ofthe Step 4 economic and environmental BART impact analysis is provided in Table 1-6. Table 1-5 S02Emission ControlSystem

. CostSummary

AFBe $11,815,600 $5,333,000 $6,482,600 Addition plus Wet FGD(l) $9,614,800 $46,017,600 $588 $4,334,000 $5,270,800
$929·,000 $3,780,000 $48 $356,800 $572,200 (I)Wet FGD capital costs include the cost ofmajorcomponents and indirect installation costs such as foundations, mechanical erection, electrical, piping, and insulation for the FGDabsorbertower, recycle pumps, induced draft fans, significant modifications to the existing stack, limestone receiving, limestone addition to the boiler, and FGDsludge handling systems. (2) Dry FGDcapital costs include the cost ofmajorcomponents and indirect installation costs such as foundations, mechanical erection, electrical, piping, and insulation for the reaction vessel, induced draftfans, reactant injection system, stack modifications, lime handling system and solid waste handling system. Dry FGD capital costs also include costs associated with a tabrie filterbagbouse because particulate control is needed after the dry FGD and it would be impractical to fit the dry FGD system between the boilerand existing ESP control system.

4ExcerptedR.M Heskett Station's Unit2 DraftBARTAnalysis
Table 1-6 SummaryofBARTImpactAnalysis

. , .­ T-otal Average mcremental



### ....0


### . A.D.irUai

, '.: Cost 

### Cest 'Connl Ttdmol9IY EmJsslolli (g,y)

..**~~. '~7-)**  .,' .' ',Coals'



### .,.cJI¥.ear) Effectiveness (Slton) EffectiVeness ($/tonl**E.mro.~.tItI:_Wlets·,,;** AFBCwith 341 2,600 $11,815,600 $4,540 $12,760 Increased PM emissions Lirilestone and increased acid gas Injection plus Wet emissions, including FGD sulfuric acid mist Increased waterme and wastewatertreabnentJ discharge. AFBCwith Limestone 409 2,532 $9,614,800 $3,800 $11,060 Increased water use, and increased PM emissions ,lqjectionplus Dry frOm handling lime FGD reagent AFBCwith Limestone 1,194 1,747 $929,000 $530 

# - Potential increase in PM emissions from limestone Injection handling. potential impacts to fly ash resistivity and effectiveness ofthe ESP control system, and potential impacts to the existing solid waste management/disposal system. AFBC with Sand' 2,941 

## -­ 

# -­ -­ -­ Baseline

. (baseline)

Potential 7,165 

## -­ 

# -­ -­ 

## . 

# -­ Uncontrolled S(h

5ExcerptedR.M Heskett Station's Unit2DraftBARTAnalysis

2.0 BART ANALYSIS FORNITROGENOXIDES (NOS> The formation ofNOx is determined by the interaction ofchemical and physical processes occurring primarily withinthe**combusti~n** zone ofthe**~i1ers.** There are two principal forms ofNOxdesignated as "thermal"NO. and "fuel"NOx •ThermalNO. formation is the result ofoxidation ofatmospheric nitrogen contained in the inlet gas in the high-temperature, post-flame region ofthe combustion"zOne. The major factors influencing thermal NO. formation are temperature, the concentration ofcombustion gases (primarily nitrogen and oxygen) in the inlet air, and residence

## time within the combustion zone. fuel NO. is formed by the oxidation ofnitrogen in the fuel.
2.1 Step 1: IdentifyAvallable RetrofitNOxControlOptions PotentialNOxretrofit control options were identified based on a review ofavailable technical " information. Retrofit control options with potential application to Heskett Unit 2 are listed in Table 2-1. Table2-1 ListofPotentianyAvaDable RetrofitNOxControl Options

## :CtJ~~R~l~" .. ' .•:**~** Combustion Controls Fluidized Bed Combustion (existing) Staged Combustion LowNO. Burners Flue Gas Recirculation (FGR) Burner Tempering (WaterInjection) Post-Combustion Controls Selective Non-catalytic Reduction (SNCR) SNCR with Staged Combustion Selective Catalytic Reduction (SCR) High-Dust SCR LoW';.Dust SCR " Innovative Control Technologies Rotating Over-fire Air (ROFA) BoostedOver-fife Air(BOFA) ROFA + SNCR (RotamixTM) NOxStarTM Exxon Thermal DeNOxTM Pahlman Process Wet NO. Scrubbing LOTOxTM

2.2 Step2: EliminateTechnieaJlyInfeasibleRetrofitOptions RetrofitNO. control technologies can be divided into two general categories: (1) combustion controls, and (2) post-combustion controls. Combustion controls reduce the amount ofNO. that is generated in the boiler, while post-combustion controls remove NO. from the boiler exhaust gas. Retrofit control
6ExcerptedR.M Heskett Station's Umt 2DraftBARTAnalysis technologies identified in Step 1were evaluated for technical feasibility, including availability and applicability, for Heskett Unit 2. The results ofStep 2ofthe NOx BART detennination (technical feasibility analysis ofpotential NOx retrofitcontrol technologies) are summarized inTable 2-2. Table2-1

. TeclmiealFeasibilityofPotentialNOx RetrofitControlTechnologies

, " Atmospheric FluidizedBed (AFBC) Combustion AFBCwith Additional Staged Combustion LowNOx Burners

.Flue Gas Recirculation BurilerTempering
AFBC+ SNCR AFBC with Staged Combustion + SNCR
AFBC + High Dust SCR

AFBC+LowDust SCR Boosted

### Overfire Air (BOFA) and Rotating OverfJre Air(ROFA) , BOFAlROFAplus SNCR NOxStar1'M Exxon Thermal DeNOxTN PahIman Process**ApproLN()~** ControDedNOx

, Emission Rate

,**(J)pmvd@3~~2)'** 225 -235 (0.326 IbIMMBtu)
180-190 (0.26 IbIMMBtu)

150-160 (0.22IblMMBtu)

50-60 (0.08 IblMMBtu) In Serviceon , Emtblg AFBCBoUers

Yes**N~** 

### x

x



## x x

x 

## x 

## x

x

x

x

x 

## x x x na

na

Not applicable to

AFBC boilers Not applicable to

AFBC boilers Not applicable to

AFBC boilers yes

yes

No, combustion takes place within the fluidized bed in an AFBC. Ineffective because ofthe low combustion temperature in an AFBCboiler. No, low combustion temperatures within fluidized bed. yes May be applicable Nottechnically feasible for Heskett to PC units Unit 2. Temperature window needed for SNCR is not available withinboiler. SCRcontrol systems have been installed on PC boilers SCRcontrol systems have been installed on PC boilers Demonstrated on coal-fired PC units Demonstrated on coal-fired PC unitS Demonstrated on coal-fued PCunits.
Demonstrated on coal-fired PC units. No. Technical limitations including rapid catalyst deactivation. Not demonstrated in practice on an AFBC.

,Yes, butnotdemonstrated in practice. Requires flue gasre-heat. May not becommercially available. Included in the evaluation ofother staged combustion systems. Included inthe evaluation ofother SNCRcontrol sYstems. Not available as BART retrofit technology f()J' AFBC unit Included in the evaluation ofother SNCRcontrol systems. Not available as BART retrofit technology for AFBC unit.

7Excerpted RMHeskett Station'sUnit 2 Draft BART Analysis
InSemceon 

### ·:EiDJ$Sioil·.Rate

. ;t£u1idWv.

# _%**~** AFBCBollen Yes InSemceon ControUedNOx

.

APPrOLNOx Other Combustion Existing TeclmieiUy

## I'asude

. No 

### 'tQr.Besltett::,.**.~'** '.:, i

.. Sonrees? Not available as BARTretrofit industrial boilers. Demonstrated on 

## x technolo

. for AFBC unit. 2.3 Step3: Evaluate ControlEffectiveness ofTechnically FeasibleTechnologies The control effectiveness ofeach technically feasible retrofit technology was discussed in Step 2. The effectiveness ofeachretrofittechnology identified as being technically feasible and commercially available for NOx control at HeskettUnit 2 are presented in Table 2-3 indescending order ofcontrol efficiency

.. Table 2-3 SummaryofTechnicallyFeaslbJe Main BoUerNOx ControlTechnologies

.. ·r

. 0.08 AFBC +Low Dust SCR 75% 82% 33% AFBC+ SNCR 52% 0.22

.AFBC +Staged Combustion 20% 0.26 44% AFBC Combustion 0.326 3.5% BaselineNOx Emission Rate 0.463

2.4 Step4:**E~luate** Impacts andDocumenttheResults Step 4ofthe BART determination requires an evaluation ofthe economic, energy, and non-air-quaiity environmental impacts ofeach technically feasible retrofit technology. This evaluation shouldtake into consideration the remaining useful life ofthe unit. Table 2-4 presents the capital costs and annual operatmg costs associated with building and operating each control system. A summary ofthe Step 4 economic and environmental impact evaluations is provided in**T~ble** 2-5. Table 2-4 NOs Emission Control System CostSummary

ControlTechnolOlY Tot8ICapital Investment' ($) TotalCapital Investment.

. ($lkW-net) AnnualCapital Reeovery Cost ($/year) AnnualOperatiBg Costs ($/year)

. 

### ·roid·Auual 

### Costs**·~r)** AFBC +Low Dust SCR $19,544,200 $250 , .$1,844,800 $2,770,700 $4,615,500 AFBC+SNCR $3,590,000

. $46 $338,900 $921400 $1,260,300 AFBC + Staged Combustion $1,313,000 $17 $144,200 $179,800 $324,000 AFBC Combustion NA NA NA NA NA
8ExcerptedRMHeskettStation's Unit 2DraftBARTAnalysis

Table 2-5 SummaryofBART ImpactEvaluations


### lITom.-·.·-:·:-- 

### .-. ·..,in Average**.,~"** 

### .'AIi.ac

. To'-I 

### .Ai:m.UaI Cost 

### 'Base";:

.. L**.~_** 

### .. Control Elfedlveness 

### Costs**'(lDYl:',~:**

### .-.**~,: .:.:~**  

### . 

# ($Iy..->

. ($Iton) AFBC+Low**TeclmO~** 1,307 809 $4,615,300 $5,750 Increased CO and VOC DustSCR emissions associatedWith reheating the flue gas. Increased S(hto S03 oxidation across the SCR, and increased

.condensible PM emissions including H 2S04• Ammonia emissions associated with ammonia slip may bea precursorto the formation of visibility impairing particles such as ammonium sulfate and ammonium nitrate. AFBC+SNCR 751 829 361 $1,260,300 $3,491 Ainmonia emissions associated with ammonia slip may be a precursor to the formation of visibility impairing particles such as ammonium sulfate and ammonium nitrate, AFBC + Staged 887 $1,440 Potential changes to flue gas Combustion 693 225 $324,000 characteristics may impactthe unit's ability to capture mercury emissions.

. AFBC 468

. 1,112 Boilermodified to AFBC Combustion NA 

### NA configuration in 1987. (Baseline) 1,580 NA 

### NA

9MOnlllJUl-Dakola Ulilities Heskett Unit 2 - BART Delerminalion May 30,2006 DRAFT
BART Economic Evaluation

- NOx Staged Combustion Details

Co.t CAPtTAI. COSltl ($1 aaslt DiAle! Caplttl Cotla t.:1"tII 8aHd SNCR Cosb Duct

..'Oft 11/14 OiImpt,., 5360,000 Of

A !'on. $150.000 I'un:ed lJrah F."Modir",,,llon. 590,000 1n>lI'Ul1lCIlIS IJId ('.AlIlIfOb 5120,000 Mille. Oftr Dir«1 capital ('.I)!.b S75,000

TUIlII Oll1lC1 (OSI 5795.000 lndiAlctCaphll COIla 01 TOC. ealE:**ePAl~s:/I8-C2.oo1.** sllCllOli 4.2, 8tICI CUEOosI dellulc .lIIues 101**En~.eMQ** $119,000 1&.010 SNCfl. _.aseCIlrom 10% 10 15% 10**_11OI"lfOI~ ~**  (J/ TOC. 8aslo:**EPAl4~.(lOI.** Socllon**~..2.** 8tICI CueOosl dell\lll ••luflIOO Cons1rUCbon 81'\11 Field**E~I!$** S80.00c IO.O'lI, SNCfl. 1nC,.....s lrom 5\, 10**1~** 10 _I lor .toItoll!

__. ConIlae1or**Fee$IPennllltt\g.'Mode~nll** SSO.OOC 10.0'lI, '"TOC. 

## -= TYPC:1I101 pellul

....co""o< $y\I1ems. Slal'l-\JllfTestWlQ S40,ooo 5.0% d TOC. BuI:l: Typc:81 SlIIIUIIccslS to< Of'/I $y\I_ d Toe. eMl$< T)'PICal ptllOlmlnceIHIingcosl101 OF/I ,syslemf (_ 2<1 Penom>lIIICe T es1lflO
. 54o.OQ( 5.0% ClayS). (J/ TOC. 

## -= ePAl4S219-G2.(lOi. St<:tIOt>**~.2,** 1/1(1 ClJECosI <leIaull._t:JI2O'Ioo ConIirlgenc:ie& $159.D!X 20.0'lI, 1101 SHCRI. CcinIIlsIel!I

...111cOIIllrllIIflC1lO' 'eirdI!llRlIecl.

Totllllnditeel C6P/Ij/Com $SI8.D!X TOlal Capllal Cos

.. T 0111 CapllIll fnvlSlmen, (TCI) S1,313,OQ( TOIII Capilli InvHlme"l 1$.lkW·nel) 51 Capl

..1RecoIIery Fact

... ,,/11+1'1'III +It. I 0.1098 15**I~e** 01 equlpmenl (y.ars) Annuaillecl Capital COlli leaphll Recover F.CIO'

_TOI.I C.pllalln"ealmelll)**SI44~OO** 7% ptela.marginal 'ele 01 ,elum onpnvale investmll1lf OPERATING CUli'li Bas s OPlr.llng

.. Malnlenance Costs (besed on 90% capRclty laclor)

Vallible O&M Coala

.Urea RHoem COSI SO S NA WalerCost $0 $ NA Boilet Ellioer,cy Penah, 56,800 cosl

.. S0-8OlmmBtu Aulliliaty Power Cosl $28,500 $ 4S Beud on auxiliary power requl«!ment 01 0.1'" (gtos&) al'\ll S45/MW".

T 01111 Valiableo.s: M Cost $35.30( Fixed O&M COlli Assumed SlIgII1 increllse i" Ope'81O' nou" 10 accounllor inspecllo,>! 01

Additional OpelllOlI pet shill O.12! tne 01''''control ayslerro. 3 'MIs/day. 365 daylllyev " $46/hou. IUIlII)<

..benefits) """d\ 1$ equal Operaling labOt 5$2,60( 10 an .nnueiOPeratOi COSI 01 $100,00Q/y1lll" SupeMSOI) Labor 57,90(**1~.0'!10** olope,al"'IlIllDO', OAOPS Chapler 2. page 2·29. EPAf45.2!S

..()?.QOI,.1'\II used !tie Mal'IlIInance Oelaun FaCIO! to, SHeA Meinlen_Materials SI9,7OC 1.5'1<0 (1.5'10 of Tolal CapllallrWUtmem) SediOtl4

. .2. Mainlenance LabOr $l1,8OC 60.0-.. 01 maintenance matehals cost (S&L 0&'-1 'lI1im&18).

TOIIII F,.fIII O&MCo6t $92.000 II'\I!iAIct Oper.llnv COlt Properly Ta_ Sl3,IOC I"" otlOlQ/ cap)la! "'vestment. OAOPSChapter 2, page 2·32. InSUtance St3,IOC 1% 0110\81 capilal inveslment. OAOPSChapte, 2, page 2·.32. Mministr8lion S2S.:3OC**~'I<o** 01 100eI capilal investment. OAOPS Chaplet 2, page 2·32.

Total/tI6IeI:t (.}pfttariflg Co6t $$2,5(x; T OIal Annual Opelltlrnl Call $119800 TOTAl. ANNVAL COST Annualized Caplllli Cost $144,200 Annual OperatingCOS! 5119.800

TOI.I Annual Cost 5324,000

Page B

..6Montana-Dakota UliHlies Heskeu Unit 2 - BART.Determination May 30.::!006 DRAFT
BART Economic EvaJuafion

- NO" SNCR DetaiJs

CAPITAL COSTS Dtrecl Caplll'COlli Urea BIRd5.'iCR COl'" lim Stanpl Handlin: UIC« Il\I«tloaCOIIII'OIsiMb«IraAir He:lter ModirlCl••

T0IIII OlftCl Coil, (l'lX'1 COllI IS) . au"

....dtln u.s.""

...••**Cv_~010 lII1d~cote_~red**  $392.000 bySAL lOr

..... 1'"'1«:11. InCIudH liltcote 0I

..........c:cmpan_1ndIncl_ $771PXJ Ins

.... cos..SUChu 1MCIhInIcIl_1IaII. ---.llIping._ $308.000 _lot

... eNCR

__ SJSlIIb.

_ syaIeIft.

....ON**~** .$703.000 NlAllltIIIaIiorI.1'Id conwll12.175.000 1nd1rectCIp

....COllI EngkIterInIl ConllfVCllcn II'1d FM!1d**E.~** ConIfador F

..JPermft.in{llMoOelltlQ SlIlII-UplTeJung Performaoce T esling ConlingenCleS

T OIBIkraitecf Gap.tSlCos. rIroc. Bull,El'l\I4S2/1H)Z.oD•• &et:IcI>4.2.

_ C1A!CoII

........_. $326.00: 16.0% lnCT_eoIrOl'll 10"11. Ie**1~** Ie _OUnllllf IIIldft lnQineemo. IIIroc. "$/.I: &'PN4521B-OfoQ01. Section • .2.III1dC1A!COSICMI

............ $218.00: 10.0'lI0

.......d • .­ 5'" 10**1~** 10 _ounllllf..uo&_. $218,00: 10.0% III TOC. Bal'"Typical 101 poIIuIiGn c","""I)'*'_. SI09.00c 5.0% III foc. B6s1s: TJpiC/il SlOIIu\l COSI$IO. SNCI'\ Sl09,OOC 5.0'lI0

..TOC. BaSIS:**T~aI ~~orma""'Ie$\l'Ig** **~ote** lOr SNCR 1_20 dtIyI). 01 TOC. Basis: EPAi45Wo()I1·00I. Section U •....,CUECos; ""...,1

......CI 2O'l.. 543$.000 20.0'10 CorII

..I.nt ";\1\conlingency let ••llOm_1. $1.415.00<l TOIl' CapitalCOSII T(II8I CapitalltWestmerllcrCi:,) TOIa' meslmenl (SIkW

.....) Capilal Recovery Factor: 1('+ rt I I' +tf- , Annu.Uud Capita' Colla (C.."I'" Reco_Factbt xTolal Caplllll'nllUlmentJ $3,590,\10( 54! 0.0944 20 lIIe oIllQlJlpmen. (years) $838,9OIl 7% PlelaX marllina',ata ciI re'um on pllval. illve$uneftl OPEFtAT'NG CO$'fS aasls Operallng , Maintenance Cosu (IM'eeI on 90% capacityfadar)

Vlltleble 0&11Cot" Ulea Consumption 11tIIIv) U.ea RelQlfd'Cosl Wale,Cos. Boile, Efficiency Penally 25 Based on maltlmum hGa' hpUl. NOx removal rale**(~).** NH31N2 molal S5,8,101: $ 550 .allO IPPI'oxlmalely 2.0 (N$R). fII>(I S5SOIIon lor urea SClUlIOn.

$1:301: S 1 Bas6d on urea feed ,a.e and$,n000lIal. 58.201: 0.'5% balkI, efflc:lency penafty, equivalent fuel cost G $O.IlImmBlu Auxiliary P_Cotl &42.700 $ 45 Based

### on awrlliary powet requiremenl a! 0.15'" Igron,anCI S451MWh

TOfBIVallatJle 0&11 Cos, 5570.300 Fixed OaM Cotla

AddI.1OI\1II ()pera\Ol1 per Shih 0.250 Base<I on S&l O&M e$lVnale 'or SNCR conIroi**s~em.** 3 sttllslday. 365 aayslyear III: S48Ihour (Ulery + benellts)MlIcIt**~** tq\lIIl Operating l8llOl $105.11)( 10 an annual operalCl' COS. 01 SlOO.OOO/yeIll. Supel'llfSOry UIbor $ 15.eO( ,!;.O'!O 01 operating labor. OAOPS Chapler 2. page 2·29. EPA/4S2I8-Q2-00I. Maintenance OefalJl FaCIOI' lor&NCR !'.S'IIo 01 T oIaI Main.enance lrAeIerlais 553.90( 1.5% CapIIa'.nvestrnenl) Section**~.2.** Man.enal1C4t Laboi $32.301: 60.0% 01 maintenance materialS COS. (Sal 0&

... 81Ima'e,.

TotalFilled O&MCost S207.10I: IndlrKl OJllf'lllntCOIIt PropenyT_ S3e.OOC ''110 oC 1oIe1.caplal i'N8s1rntnt. OAQPS ChIIpIer 2. P8\1112-32. Insurance $36.1lOO t'l' oIldel

### C8jlII., Inveslml\nt. OAOPS Chapter 2, P8\1112-32. AdmInillrallon S72.00c 2'l(. 01 101111 capilallnves\me(lt. OAQPS Chfi,t., 2, pagt2·32.

TOII/lIInd/reI;f0petII1rngCosI 5144,OOQ Total Annual Oper,lInoCost $921400 TOTAL ANNUAL COST AnnUIIUled Caplllll COG! $338,900 Annua' Ope,.IInG Cosl $1121400

Tcrt., Ann.-'Cost 51,2110,300

PageB-7____ Monlana·Dakota Utilities Heskell Unit 2 - BART Determination May 30.2006 DRAFT BART Economic Evaluation

- NO" Low-Dust SCR Details

CAPITAL COSTS Direct Cap OSIS 

# ­

R_IOf HOllIn" Mel IMlaUa

..OD A..,1IlOIIIa HMdhn.1IIId Inject/OIl FI"" a.... HalldllnS:I>uc_tami Fam 

### e_...**u.s.EPA"c-_·_~COSI"""~** Ak Pn:halctModifleatl""" DrS&l,IOI-prcjtoetS. ..- .. <:osIGlIlIIjOfCOll1j)Ol'lQt1l.

__**~coRolIIGII** ..**~ ~IIIII"'I(.""**  I;!;,c. OIlIer DirecI (Apical

## co...

EquipmetI C'ip\IIJ C.,.q SubtCIIA' InkIIUCnfq

.. I0I04111 sell**_~.""""** hIrIIIttlfIlYI*II,

....QIIIo 

# _ano...... lntI_

..**_~.** 1_1eI1'"" CQlltl'ol., T_ Fre I TfIUII/)(roJ CMICTOCJ indirectCaphal CHIlI OITOC. 1IaSII.: EPA

..._. -. 4.f.anoCVECosI

__ 

# I

__ 10'!00 102O'I\.104IO<:_Ior_**SCR.~ItIO'''''''** E"",,"rin!l 15.0'li0_._.

. oITOC, 1I1sts:**EPN4~·DO'.** _4.2.II'ICc.JfCosI

__. eon.ltuC.on an<! Field EIipgn&_ 5.0'l0,_"'_5'I<.IOI0'!001O

__ ""

__ 

# I

ConlfllClOt F_ 10.0'% OIroc. 1I_:TrIlicIIlorpollullOn_.-. Slart.Up 1.0% olTDC. a":TypcfII-.._IOtSCR 

# I Petfotmanco TeslinlOl t.o'Ao 01TOe. B_:TrIlicIIpel!OIlN1nCellS*'ll «111101 SCII 1_01,I!O 1IIyI). 01 roc. BUill: EPN4S2111.o2-OO1. Section 4,2•..., C\IEC<ltI 001

..........0120'11. ?O.O'\:. COIlIIaltl'llwlD\' tormrolilprejeet. 

# I

lotalCapital COils T 0Ia! ClplteiItllte$ImenI 101a! C8p!IaIJ_ (Slt.W-nel1 CIpItei FIIClO"**~1+** I)': (1 +If'. I**fOlI'OI~~1** no ..--...,... 1111"""""",

___ Anmallucl Caplllll CoalS 

# I

OPERATIH OpereUnll ,**M.I~_nCOl** COila (DIlled on 90% capaCIty tectotl 

# I

Vari.bIe elM COSI. 8....,an ......mum .....input.NO><

__ ....**_~_NHUf2** .lIII001

__**~1.02.** AllVllorQ 11Ij_Rate \Iblhrl 

# i
400 SUed

.........__.CIIPICiIl'

___, _ S<IOMon 'IIIQIIflCllll1. Atnmt:InII Rul!l"lCos! 6upp1emenlalyHut(f.oheilitue gas) e e ..

,., an

### "".'1n!M \0

....gao ..·hM"" """I

....COOl fiI581"",,11111 lor

..."'

..vu. a_ aneihaust gIIS _ , ...._ .......k1g ali!>llQlyll<lClly 01 !.liDO IIIIt lOt • C"IV_(lI31 !>,eoo-SCR. CateiyaI ReplactmentCO$I 250

__ 011 cOS! 01**~13"'"** ClIOIySIIle 01 4,.11<\. 

# I

B_CWllr

........**tlrop_.1no8al.O.0IIS_~_** 

## i 4S

....._ ann45/MW1l t 

### f 

# t Fl.'"OIM Co

...**ACId~** Ope.alon; .,.., IIIHI**_Gtl.L06M_IOt$Cfl_III'~' ~1IIIII'lIII1.-~.** **S3UOoItourI~'** _I -.lItqo/11lO

.... 

# I ,

_ ..**_IIIItyGl~.** f**I&.O'JI,"~IIIIIW. ~ClWtllWI.IIIIII""**  1.s'11.**CU£CoII~'~'_.ICRI'''''''IIII1IIIItGCOS1l.** IQ,O'JI,**0I~** ___ 1S&l06Y

.._),

1%**III"'~** ___• OAaPSClWtllWI,1IIIII241!. 

# I r It. 111_-" OAQP&ChIpIIr 1.1IIIII1I4Il. 2%**O!_CfIIhI~ 0A0PS~1I.**  

### '.S!.

TOIII Annual COSI t TOTAL ANNUAL COST Amuall:Md Capltll COli Coli

Page B·8Montana·Dakota Ulilitie.!. Hcskell Unit 2 - BART DClerminalion May 30, 2006 DRAFT BART Economic E,'siuation

- SOl Limestone with Dry FGD Control System
Coal CAPfTAL COSTS lSI aaaia Direct C.pl1lll Coala Llme$lOll.**Intect~** 10CFB $2.800.000 RtllilO"' fff<! S.)'l<Itm S5.986.ooo**SO~R"""""'S,....,..** $1.725.00< Beaac go U.s.EPA

.. CueeOSI WOIb/IeelS &ftd equlpmtnl**COJI.~** pntpartCI

SpruyDr)or.. $7.738.00< by**S&~** Ie< _., J!IOIICI$. Inc_!heCO:" 01

### "'*' CO/IIpanen!S and

..... _ Po

.... ''''''**H:mlirl~** $)

....... $2,155.00< onsllll1allon co&Il

........s 10UIlllaIkWIs. mechank:al

## _Uon. eleCllleal. gipIng. Ina

IOF_ 5827.00< insoIMIon.1ct 1M 6w._lion_lSI.nICYCIe

_ '-4nlh fIN

......**W_/B~""I** H.tndIlJlf S,....", $1.664,00< '*fIMnO. limeba/1cIIII9. IndaailOs MndIinO 5\1_ SuJ'Pt"' Eq.dj!mCnI SU·8.1lOC ('h""".Y M,"'il\"",;'

... 53.994.0()( II1!CIU<ied '!2

... ICIW CIIQiIIIl cosl"" Ihe IIIbnt !lIe. beC

...se !he dty FGO c_ 1Yt-

_ Dol'-" bypatlil!Ui1l1econlrot. andnIS 1101**~1I!y** poss.IIJIIt 10 1ocIIt. IN: dty FOD comroi a",

....._1IIItbciIerIII1dIM e..1inp ESP Fobnt FiIIilf.R.It"'

.... S4.948.6OC 101lJ1 PlJfChasetJ£qtHpmenl Cosl (PEe) $34.085.6OC Indirect Capital COtIta Engineering $3.409.0OC 10,0% QlPEC Sootte:OAOPSM.!nuaICnap,erS. TallIt U.PIlQfl.27

. Conslructlon andF'oeId**E~** S3.409.00c**10,~** 01 PEe. $ou",.:OAOPS MaIIu.lChapte! 5. r_l.3. pagw 1·21. Contractot**Fe~** S3A09.00c 10,0% 01 PEC. so.m:.: OAOPS. MI\

...11Cnapler5. Table U.PIlQf 1·27. Sian-Up $34I.00c 1.0% '" PEC. Sou",.:OAOPS Manuel Ch8Qltt. 5. T_ 1.3, PIll't 1-27. PertOlt1'\llllC(llesl$ $34I.00c 1.0% 01 PEC. Swu, OAQPS MlllUfI/ChopiOf**~;** T_ 1.3.

_ 1-21 S $1.023.00c 3.0% 01 PEe. Sou",«OAOPS

## Ma_ ChapIe> 5. T_ 1.3, PIlOt 1·27. 101MIndirect Ct/pI(/1Co.;sIS (IC) Sl',932,OOC TOlal Capital Coals lCllal Capilallnvestment $46,017,600 TOIa! Caphallnvestmenl (Si1<W""etl SS8Il**CapHaiRecovetVFadOt~~I+I)'·Jll.i)".'** 0.0944 20 Y"'''. Annualized Capital Coala prelU ma1gin&f rele or retvrn .:)n pfNBIf in¥esunenl. InteteS' rill! uHd in OAOPS fCapltel Recover Factor. TOI8' Cepltalin_tment, 54,344,OOC 7", Ma.-(Cho,..o,2_**2·1~~**

. OPERATING COSTS BasiS ()penollng &Malntenarice Coetll!b

..aed on 90'11. caPllClly 'Aclor) Variable O&M COII5 6••..,or. "'

........, .0" """,I. 802 "",,OVal rat. (1bIh.,. '.06 .'OicIliomolry,!IO'!oo

Lime Reagent Cost SOO.IOC S 75 CaO. and reoctenl (OIl 01 $75110n lor ,,,". Wilier Cos! $28.5OC $ I Bea..,OIl 0.15 jll:lnllMWlI""'", $111000 gal 6a$ec1

.......xim

....hea, input. S02rem<>rIlI/8le (lb/II,).

_**SSIlO~** """Ie 1:0$1. OispoHIcoat inc_lime

..,___**~I** ...by. FOO WlI$te Disposal Cost $48.90( $ 5 ptOQIcII, !lUI "'" "",,uoe II)< ash. Autdllary Power Cost S313.3OC S 45 Bea..,en .....1181'): -..**~menl** 011 10'lir (nell and 'fSIMW.

TOUII Vatfab.le 0&1.4 COS/$ $450.6OC
Fixed O&M Coale

ACKlitlonal QperatOl$ pel Sh't 0.75 6est(! 01\ 5&L O&M Hllmaillordry FGO. 3 .hiUS/dey, 36S caysJye., e $33.!iOIhou1 (Hlel')' + oene/'Il\_h 11 equa; 10.' Operaling Labor $220.100

........_0101 181<1ty 01 570.OOOIrea', SUpeNi&Ot Labat $33.00c 1$,0% 01 cperaling labOr. OAOPS Chapter2. pagw HlI. Mainlenance Materials. S 1.704.3011 6.0% CUECosIMoitl_eDefault Fec\or lorItr>e

# $_ Orwet. Malmenance LabOf 51.022.600 00.0% 01

## m""'_m

__ COSI (SAL O&M esu"'lII&). T 0UIi FIXed0&1,1 Cost S2.980.00c Indf,.ct Operating Cost Property Tu. S400.00c 1% '" Io1aI cellilall'

....t"'

....t OAOPS CtlaIl\lll2,

_ 2·3:. tnsUlllllC8 $480,000 1% 0110l1li cepIIaIlt

....tmeni. OAOPS CIlepIet 2. PIll't2<:12. AdminiStration S920.00c**~,.** Q/ to2'capilli! investment. OIIOPS Cllapter2. page 2·32.

TOUIi Indired Operl/Iing Cost $1.840.00c Total AMUIII ODer.ting COli SS,270.8OCl TOTAL ANNUAL COST AIInuali1ed capltat Coat $4,344.000 AIInual Oper.tlng Coat SS.270.8Oll

T0l.1 AMUIII Coal $9614110Cl

Page B·IIMontana-Dakota Utitities Heskett Unit 2- BART Delermination May 30. 2006 DRAFT BART Economic Evaluation

- SOl

. -Net FGD Details

COJI CAPITAL COSTS 1$1 Ba8Ia 10111 PuR:hat<ed Equipllltni Co.IIPF.CI S6Ut3.3Gl

. G_raI htililielo s&.&9t.3:U ElIIlnettlll& "- $6.691,3:U TOUIICIIPIII

______IIIUSEPA-aCl.eCcelW---._**C~"** St3.tll2.6n

_ ... IO

.........**_._~DrS&l.IOI ~_pRljICIL**  TOIlIII'I

.. CIm 512,278.701 DinId

___.. .. COlIC

..**map-COIIIfIO!**._IIIIy~_**

......, -. _ ..IICfIatIt:II-*>n 10' IlleFGO IOS(IItIer**I~. r~**  P'lllPI. iMIuC

...01IltIlnS.
- ...... ima_handono· -......_ Total PIanI CoSI 111'C)

...1Prime**ComrAClor'~** Markup S96.047.e6!**101l11Osh~ITCEl** '112.30$.581

.... 1IaIIding

...... All"",.ra" l"1IIld!I DIiiqCon.w. IAFDCl $10.120,91 TOIal Plant In

..:_nUTPI) $UXt.0426,4IH

Preprodu.:liooCO>lI> 53,747.141 In_orvCaol!al $330,'11 r",.1 c..,iltJl R«/I11,.,.,WI ITeR} $100,505,00( 1."",**OIpinilln~.oenl** (S.\W •**~I)** $20 30_. A"nUIIllud Capllal Cosu Capkal**~...,.** FlII'IOI" =II 1+ it III + I)' • I 0.0806 ",eta>< mtrfnOlllll6d "u. anpm.", _Ime

... _UIroll ,_ .,OAOPS lC.pllal.R«o"f' r..,lor, TOI.I (:IIpll.lln'·<!$I"",,,1I S8,S82,lIOe 7'!io**~1I!I1~lttlll/02·'S~** II

... OPERA ING. COSTS

OpeIttIng I Ualntenlnca Co

...Cb.uIGO 0II1IO'rt capacity 'actor)

Variable O&M**C~.I_** 11

...4an m.,.;mum '- inpuI. S02 ......,...'

....

## '_1. 1.00.lul:h........,.._

LlIIKISI_ Augenl Cos. $620.10( $ 30 ca<:q3. -caoadIY_.,.,.,

### _'OI_one. W_COSt 5270.20( 1IU""

...,.ogpmlJolW·gr_.

### _ClllllfCllr*

..... and'''tooogoJ 1Iued

..._ ...........

## 502._,_,_1.

__cftyIKIOI.

___ to'lloIi'y.an4.'_

.....lf

........._.**~"_t"""** .n;Iudes_WFGO """'_ """_ ""'_.,.un .. CPII FOO Waste Ois

__Cosl $344.0011 $**'O......-~** 

# _on._"'

__**-e.."'U",!ttO\l._(~,_._**



### -- AulcIlary PcMer COSt $l.an.4OC S 30 $3OI.IotW. TtJla/ Va

....1»e 0&61 COS/$ So4.611,7O(
Fixed O&M Costa ()peJalOI'II pet sllifl 3.V eo....... S&I. O&M_euo''''

_ FGO. 

### ,sN!tsIda,. 386 0 m.-
.......,• benelblw/IIeI1

.._110

...

__'101' _1liiy01 SlO.00<Vyei,.**~J.abol** $880.40( Supervosot UIbo< $132,IOC IUl'llo 0I_4dIng1IboI. OAQPS CttepIor 2

.... 2-20. 5.1l'IIo CUECoIt

__ 00IauII f_1O'**~"'** .......ac..- with ""OGd_ MaI_ MaIeIIaIs $3.29$.70(**m~** 6O.0'l. d

__II

_ (S&L 0&111

.._.,. Maltttenanct LlbCt $1.977.40<**T_F'ur~dO&MCo$l** 56.211UOt 1l1(li_1 OperallngCOlt PlopettyT_ $659,10( 1'10 dIClalUjlhl

....... _ OAOPSCItopItft."o-t·3:/. $659.10( l'Ji.oI_',,*,",&I

...

# u_ OAOPSa.,...'.pegeH2.



## ....

# "'- S1.318.3O( 2'110 olIOI'llC4

...... IIWet_ OAOI'S CItaIItett. DIM

### '.32­ AominialtIIIioIl

TOU/I_ Opf/tlltin(l COSI**~.63Uo(** TOIII AmuII·ODetatIncr Coal 51UaUCII TOTAl. ANNUAl.COST AMwIlHc.pa.JCOlI

...........o-.tina COlt 

## ,,1 

# ':::::: TOIII AnIlUll COlI I2a 111..7lII

Page B-BNorth Dakota Department ofHealth CUECOST Model Spreadsheets (Verification Only)

# ) I CUECost

- AirPollutionControl Systems Economics Spreadsheet !

# I I APCTechnology Choices Description Units Input 1 FGDProcess Integer 1 (1

- LSFO, 2 - LSD) Particulate Cootrol Integer 2 (1- Fabric FDter.2

­ FSP) NOxControl Integer '1 • (l

..SCR, 2

..SNCR, 3 == !NBs,4

..NOR) 

### INPUTS DescriptioD UIIItI Input 1 uts Location- Slate Abbrev. ND MW EquivalentofFlue Gas to Control System MW 78 Net PlantHeat Rate BtulkWhr 10,500 Plant CapacityFactor % 90% Total AirDownstreamofEconomizet % 120% AirHeater Leakage % 12% AirHeaterOutletGasTemperature OF 300 lnIetAirTe OF 80 Ambient AbsolutePressure In.olHa 29.4 Pressure After AirHeater In. ofH2O -12 Moisture in Air IbIlb dryair 0.013 Ash Split:

. F1yAsh % 80%" BottomAsb % 20% Seismic Zone Integer l' Retrofit Factor

. Integer 1.3 (1.0"Dew, 1.3 -.medium, 1.6== difficult) SelectCoaI Integer

. 7 Is Se1eeted Coal.PowderRiverBasinCoal? Yes/No No Economic In1!.uts 

# m-_.y"'Do"'"

.. Year 1998 • I..ife (leveLizationperiod) Years 30 tion Rate % 3% AfterTax Discount Rate (curient5'1) % 9% AFDC Rate (current $'1) % 11% First-year Carrying Charge (cqmmt$'I) % I 22% Levelized C e(current S's) % 17% YlrSt-year CarryingCbarxe (constant $'I) % 16% Levelized CarryingCharge (constantS's) % 12% Sales Tax % 6% &ca1ation Rates: Consumables (O&M) % 3% Capital Costs: Is Chem. EtIa. Coat IndeJtavailable? I Yes/No Yes If"Yos" inputcostbasisCEPlantIndex. Integer 388 If"No· inputescalation rate. % 3% Construction LaborRate SIhr S35 PrimeContractor's Markup % 3% 1000rating Labor Rate SIhr $30 PowerCost MillsIk 25 SteamCost $11000 Ibs 3.5 Limestone Fol'CItdOxldtltloll fLSFO) IllDuts S02 Removal Required

## .~ 95% lJORatio act 125 Design Scrubberwith Dibasic Acid

... 2 (I-YC5,2-DO)
Heskett Unit 2. InpUf«. Calculation Summary 1 Input Z 2 1 2

IDput2

ND 78 10,500 90% 120% 12% 300 I 80 29.4 -12 0:013 80% 20%

I 1.3 7 No

1998 30 3% 9% 11% 22% 17% 16% 12% 6% 3% Yes 388 3% S35 3% 530 25 3.5

95% 125

I Input3 Input4 inputS 0 0 0 0 0 0 0 0 0

laput3 InpIlt4 InputS

0 0 0 0 0 0 0 0 0 0% 0% 0% 0% 0% 0% 0% 0% Q% 0 0 0 0 0 (j 0 0 0 0 0 0 0 0 0 0% 0% 0% 0% 0% 0% 0 0 0 0 0 0 0 0 0 0 0 0

0 0 0 0 O. 0 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% C/% 0%. 0% 0% 0% 0% 0% 0% 0% 0% 0% 0 0 0 0 0 0% 

# =Fi 0% $0 $0 $0 0% 0% 0% $0 $0 $0 O· 0 .0 0 0 0

0% 

# +=F 0% 0 0 0 0 I 

# I l 3/4/2010, 10:40 AM 

# t t,CUECost

. Air Pollution Control Systems Economics Spreadsheet Adiabatic Saturation T: Of 127 127 0 0 0 Reagent Feed Ratio**~tor** 1.05 1.05 0 0 0 (Mole CaC031Mole SOlremoved) ScrubberSlurry Solids Concentration Wt%' 15% 15% 0"10 0% 0% Stacking, landfill, WaUboard Integer I I 0 . , 0 0 (I

.. stacking, 2

..lautill, 3 - waUboanl) NumberofAbsorbers ' Integer I I 0 0 0 (Max. Capacity'"' 700 MW periabsoroer)

. AbsorberMaterial Integer I 1 0 0 0 (1 

### = alloy, 2

..RLCS)



## == AbsorberPressure Drop in. H2O I 6 6 0 0 0 Reheat Required ? Jntcger I 1 0 0 0 (l-yes,2-uo) , AmountofReheat

. OF 25 2S 0 0 '0

. IReagentBulkStorage Days 60 60 0 '0 0

IReagentCost (delivered) Sfton SIS $IS SO $0 SO laudftD Disposal Cost Sfton . $30 $30 ' SO $0 SO Stac.king Disposal Cost $/ton S6 $6 $0 $0 $0 Cn:dit for Gypsum Byproduct $!ton S2 $2 $0 $0 $0 Maintenance Factors byArea (% oflustaIledCost) RcagentFeed % 5% 5% 0% 0% 0% S02Removal % 5% S% 0% 0"10 0%

### ~Handlin&. % 1=5% S% 0%

. 0% 0"10 I Byproduct % S% S% 0% 0%
. 0% Support Equipment % S% 5% 0% 0%' 0% Contingencyby Area (%ofJnstalled Cost) ReagentFeed %. 20% 20% 0% 0% 0% S02Removai % 20%. 20% 0"10 

# += 0% 0% Flue Gas Handling ,% 20% 20% 0% 0% 0% Waste I Byproduct % 20% 20"10 0% 0% 0% SupportEquipment % 20% 20% 0% 0% 0% General Facilities**~Area** (% ofJnstalledCost Reagent Feed % 

# '= 10% 10% 0% 0% 0%

, S02 Removal % 10% 10% 0% 0% 0%

Flue Gas Handlinll % 10% 10% 0% 0% 0% Waste I Byproduct % 10% 10% 0% 0% 0%**~ment** % 10% )0% 0% 0% 0% by Area. (% oflustalled Cost Reagent Feed

. % 10% I 10% =R% 0% 0% S02 RemovaL % 10% 10"10 % 0% 0% Flue Gas Handling % 10% 10% 0% 0% 0% Waste I Byproduct % 10%

. 10% 0% 0% 0% SupportEquipment % 10% 10% 0% 0% 0% LimeSl!.rar. D!l.erfLSDlInDUIs SOl Removal Required % 90% 90% 0% 0% 0% Adiabatic Saturation Temperature. OF 127 127 0 0 '0 Flue Gas Approach toSaturation Of 20 20 0 0 0 Spray DryerOutletT OF 147 147 0 0 0 IReagentFeed Ratio Factor 1.02 1.02 0.00 0.00 0.00 (Mole CaO I Mole IDIet S02) Recycle Rate Factor. , 8.2S S.2S 0 . 0 0 fib recycleliblime feed) Recyele Slurry SolidsCoocentratlon Wt% 35% 35% 0% 0% 0% NumberofAbsorbers

. Integer 2 2 0 0 0 (Max. Capacity

..300MW per"P"'Y W"",, Absorber Material Integer 1 1 0 0 0 (I

..aOoy, 2 - RLCS) in. H2O 5 5 0 0 0

# iB'~S"- 

# . Daj'll 

# .t= 60 I 60 0 0 0

entCost (delivered) $/ton

. S6S I· S6S $0 SO SO Waste Disposal Cost Sfton S30. $30 SO $0 SO Maintenance Factors byArea (%ofJnstaDcd Cost) ReagentFeed % 5% S% 0% 0"10 

# =+ 0%

. SOlRemoval % S% S% 0% 0% 0% Flue Gas Handling % S% 5% 0% 0% 0% uct % S% 5% 0% 0% 0%

. Support Equipment % S% 5% 0% 0% 0% Contingency by Area (%oflnstaUed Cost)
Hesken Unit 2. (nput " Calculation Summary 2 3/4/2010. 10;40AMCUECost

-Air Pollution Control Systems Economics Spreadsheet Reagent Feed % 20% 20% 00'('

. S02Removal % 20% 20% 0% FlueGas Handling % 20% 20% 0% Waste/ Byproduct % 20% 200,(, 0% SupportEquipment % 20% 200,(, 0% Genaal Facilities by Area Of,oflDstalledCost Reaaent Feed .% 10% 10% 0% S02Removal % 

# Im=HO% 0% Flue Gas Handling %**10~** 10% 0% Waste/Byproduct % 10% 0% 0% Support t % % 10% 0% Fees by Area {%oflDslal1ed Cost ReagentFeed % 10% 10% 0% S02Removai % 10% 10% 00,(, Flue Gas Handliog % 10% 10% 0% Waste/Byproduct % 100,(, 10% 0% Support t % 10% 10% 0% l!llrliculate Conlrfl.llnl!.uts Outlet Particlllate EmIssIon Limit IbsIMMBtu 0.015 O. 0 FabricFilter:

.Pressure ProP ill. H2O 6 6 0

## ~ 2-Pube!Lj

## ~ 2 2 0 -to-Cioth Ratio I ACFMlttl 35 3.5 0 Bag Material (ROFF fiberglass only) Integer 2 2 0

. (I

- Fiberglass, 2

..Nomex, 3 = Ryton)

. Bag Diameter inches 6 6 0

Bag Length

.feet 20 20==t: 0 Bag Reacb 3 3 0 Compartments outofServfce % 10% 10% 0% BagUCe Years 5 5 0 Maintenance (% of

### installed cost) % S% 5% 0% Contingency (% ofinstalled cost) % 20% 20% 0%

. Oenaal Facilities ('Yo ofinstalled cost) % 10% 10% 0%

Engineering Fees (% ofinstalled cost) % 10% 10% 0% ESP: Slrengtb ofthe electric field inthe ESP

..E leV/em 10.0 10.0 0.0 Plate Spacing in. 12 12 o· PlateHeigllt ft. 36 36 0 Pressure Dro,!)

## iIl.~0=t==k 3 0 Maintenance (% ofinstalledcost) 5% 00,(, Contingency (% ofinstalled cost) % 20% ·20% 0% Oeneral Facilities (% ofinstalled cost) % 10% 10% 0% Engineering Fees (% ofinstalled cost) % 10% 10% 0% NOx ControlInl!.ut!J ISelective Catalvdc Reduction

### {Scm. NH3JNOX Stoichiometric Ratio NH3JNOX 0.9 0.9 0 NOX Reduction Efficiency Fraction 0.80 0.80 0.00 InlctNOx lbaIMMBtu 0.36 0.36 0 Space Velocity (Calculatedifzero) Ilhr 0 0 0 OveraIJ Catalyst Life )'em 3 3 0 Ammonia Cost Slton· 205.66 205.66 0 CaIaly.stCost SIft3 356.34 356.34 0 Solid Waste Disposal Cost Slton 11,48 11.48 0 Maintenance (% ofinstalled cost) % 15% I.S% 0.0% Contingency (% ofiDstalled cost) % 20% 20%=K GeneralFacilities (% ofinstalled cost) 50/0 I 5% Engineering Fees (% ofinstalled cost) % 1'0% 10%

. 0% NumberofReactors

. mteger 2 2 0 NumberofAir Preheaters integer 1 1 0 ISdledve NonCatlllvtkRUllctiDn (SNCRJ IlUJuls iaaeut I:Urea 2:AmmioDia 1 1 0**Numberofmi~tor~b** integer 3 3 0 

# wci 0% 0% 0% 0% 0% 0% 0% 0% 00'(' 0%

. 0%

. 0% 0% 0% 00/. 0% 00'(' 0% 0% 0% 0% 0% 00'(' 0% 0% 0% 00,(, 0% 0%

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0% 0% 0 0 0% I 0% 0% I 0% 0% 0% 0% 0.0 0.0 0 0 0 0 0 0 0% 0% 0% 0% 0% 0% 0% 0%

0 0 0.00 0.00

0 0 0 0 0 O· 0 0 0 0 0 0 0.0% 0 0% 0% 0% 0% 00'(' 0% 0 0 0 0

0 0 0 0 

# I 1 

## t f

Heskett Unit 2, Input lit Calculation Summary 3 3/4/2010,10:40AMCUECost

-AIrPollutionControl Systems Economics Spreadsheet NumberofInjectors integer 18 18 0 0 

# Y. NumberofLaace Levels integer 0 0 0 Q. NumberofLances inlqcr '0 0 0 0 o - SteamorAirInjection forAmmonia integer I I 0 0 0 NOX Reduction Efficiency Fraction 0.40 0.40 0.00 0.00 0.00 InletNOx 

# Elf 0.36 0.36 0 0 0 NH3INOX StoicbiomclricRatio OX

# ~;. 0 0 0 Urea/NOX StoicbiomcIric Ratio OX 0 0 0 Un:aCost SIton
. 225 4.95 0 0 0 AmmouiaCost SIton 205.66 205.66 0 0 O. WaterCost $11,000 gal 0.407 0.407 0 0 0 Maintenance (%ofinstalledcost) % 1.5% 1.5% I 0.0% 0.0% 

### eon.;.........,; \,.ofiustaJlcdcost). % 20% 0% 0% 0% 0cDaalFacilities (%ofiastaIleClcost) % 5% .5% 0% 0% 0% Fees (%ofiDilalledcost) % .10% 10% 0% 0% I 0% Low NOXB_ TecllMion llUJua NOX Reduction Efficiency fraction 0.35 0.35

. 0.35 0.35 0,35 BoilerTypc T:T-fired.W:Wall T T T T T L:I.ow. A:Average. . RetrofitDifficulty H:High. A A A A A Maintenance Labor

## r" ofiDstalIed cost) % 0.8% 0.8% 0.8% 0.8% 0.8% Maintenance Materials (%ofinstalledcost) % I.2Y. 1.2% 1.2% 1.2% 1.2% NaturalfiB.Rebumln, l'1.l!l!Js. NOX Reduction Efficiency &action 0.61 0.61 0.61 0.61 0.61 OM RebumFraction &:action 0.15. 0.15 0.15 O.IS 0.15 Waste Disposal Cost $lton 11.48 11.48

. H,4s .1 1.48 11.48 NaturalOM Cost $/MMBtu 2.31 2.31 2.31 2.31 2.31 Maintenance (% ofiDsllllledcost) % 

# ==¥P.=t 1.5% 1.5% 1.5% l.S% Contingency (%ofinstalledcost) % 20% 20% 20% 20% General Facilities (%ofinsIalledCost) -% 2% 2% 2% 2% Engineering Fees(%ofinstalled cost)

. % 10% 10% 10% 10% I I

Heskett Unit 2. Input'" Calculation Summary 4 3/4/2010.10:40AM

### I**C~Cost** •AftPollution Control Systems Economics Spreadsheet



### .SUMMARYOFCOSTS

I Description Units**In~tl** APeTechnolot!1a NOxControl- SCR ParticulateControl ESP SOlControl LSFO INOx Co1tl1'o1 Costs SCR Total CapitalRequirement (TeR) S $10,027,752 SlkW $128.6 FIrstYearCosts FladO&M $ $174,883 SlkW·Yr 2.24 MilJ&lkWH 0.28 $/tonNOx removed $152 Yarlabil O&M $ $617062 SlkW·Yr 7.91 MillslkWH 1.00 $/tonNOx removed $537 Fixed CluJrgu $ $2,236,189 SlkW·Yr 28.67 MillslkWH 3.64 $/tonNOx removed SI,945 TOTAL $ S3 028133 SlkW-Yr 38.8-2 MillslkWH 4.92 S/ton NOxremoved $2634 Level.lzedCurrent DoUan FixedO&M SlkW·Yr 3.0S

- MillslkWH 0.39 $ItonNOitremoved $207 Yariable O&M SlkW-Yr 10.n MilJ&lkWH 1.37 $!tonNOxremoved $730 FixedChargu

- S/kW·Yr 21.73

, MillslkWH 2.76 $!ton NOx removed 51,474 TOTAL SlkW-Yr 35.54 MillslkWH 4.51 $/tonNOx removed $2,411 Levelhed Constant Donars FixedO&M S/kW-Yr 2.24 MillslkWH 0.28 $/tonNOxremoved S1S2 Variable O&M S/kW-Yr 7.91 MillslkWH 1.00 $/tonNOx removed. $537 FlxiI4 Cluugu S/kW-Yr 15.04 MiIlsIkWH 2.71 $/tonNOxremoved $1,449 TOTAL SlkW-Yr 25.19 MilJ&lkWH 4.00 $/tonNOx remQved
. $2 138 l.articul4U c.tJ{JtroiCert.! ESP rotalCapitalRequirwentffCRl $**$896~,187** SlkW SIIS FirstYear Costs FludO&M $ S3I6,128 S/kW-Yr 4.0S MillslkWH 0.51 $/tonPM removed SIS.0 Variable O&M $ $46,923 S/kW-Yr 0.60 MiIlsIkWH 0.08 $/tonPM removed $2.2 lnputZ Input 3

SNCR NOR PIFF PJFF LSD LSD SNCR NOR $1,553,228 fIN/A

S19.9 IIN/A $87,020 lIN/A

-1.12­ IINIA 0.14 IINIA S151 IINIA $209,602 $0

2.69 tlOIVIO! 0.34 #OIVto! $365 #OIVtol S346,370 fIN/A

4.44 IINIA 0.56 fIN/A $603 flN/A S642992 tlN/A

8.24 fIN/A '1.05 IINIA $1 118 IINIA

l.S2 lIN/A 0.19 lIN/A $206 IINIA 3.66 #OIVto! 0.46
. #OIV/O! S496 ·tlOIVIO! 3.37 lIN/A 0.43 IINIA

. $457 fIN/A 8.54 fIN/A 1.08 IINfA

.$1,159 tINIA

1.12 #N/A 0.14 fIN/A S151 flN/A 2.69 tlOIV/O! 0.34 tlOIVlO1 $365 #OIV/O!

. 2.33 fIN/A

0.42 tINIA $449 fIN/A 6.13 tINIA 0.90 tINIA $965 tINIA PIFF PJFF S9,87SJ'1 tlOIV/O!

$127 NOIV/OI $348J.34 i#OIVIOI

4.47 tlOIV/O! 0.57 i#OIVIO! $3.8 1#DIVtol**$23~002** . i#OIVIO! 2.99 tlOIVIO! 0.38 #OIVIOI $2.5 1#DIV/o! Input4

NOR PJFF LSD NOR fINIA fINIA fINIA IINIA tINIA tINIA SO #OIVIOI #OIVto! #OIVIOI fINIA fINIA fINIA flN/A fINIA fIN/A fINIA fIN/A tINIA fINIA fINIA #OIVIO! tlOIVIO! 1I0IV/01 fINIA fIN/A fIN/A fIN/A fIN/A fIN/A fINIA fINIA fINIA tlOIVlO1 tlOIVIO! #OIVtol fINIA IfNJA fINIA fINIA tINIA fIN/A PJFF #OIVIOI #OIVIOI tloIVIO! #OIVIOI tlOIVlO1 tlDIVIO! #OIVIOI tlDIVIO! #OIVIOI #OIV/OI Input5

NOR PIFF LSD NOR lIN/A fINIA fIN/A IINIA IINIA tINIA SO

- #OIVtol tlOIVto! tlOIV/OI

flN/A fINIA IINIA fINIA flN/A IINIA IIN/A fIN/A IINIA IINIA tiN/A tlOIVIO! tlDIVto! #OIVIO!

IINIA lIN/A fIN/A #NIA IINIA

. tlNlA'

.. #N/A flN/A tINIA #OIVIO! tlOIVIO!

. #OlVtol tINIA tINIA tINIA tINIA tINIA tINIA PJFF tlOIV/O! tlOIVIO! NOIV/O! tlOIVIO! tlDIVIO! tlDIV101 tlDIV/OI tlDIVIO! #OIVto! #OIVIO! 

# I 

# I I 

# I ! 

# I
f 

# I I I 

# I

CUECOST3, Inpul & Calculation Summary 2/8/2010,9:58 AM iCUECost

- AirPollution Control Systems Economics Spreadsheet FixedCharges

TOTAL

Levellzed CurreDt DoUan FixedOcIM

Variable O&M

.
Fixed CIuzrgu
TOTAL

Levellzed Conrtant DoUan FludOcIM
Variable O&M
Fixed Charges
TOTAL

S02 Control Costs

. Total Capital Requirement (TCR) Flrrt Year Carts FludOcIM

Variable OcIM ,

FludCharges

.. TOTAL

Levellzed CurreDt DoUan FludOcIM
Variable O&M

Fixed Charges
TOTAL
Levellzed ConnantDollan FiudOcIM $ $1,998,568 $/1cW-Yr 25.62 MilWkWH 3.2S S/ton PM removed $9S.0 S S2,361,619 SIkW-Yr 30.28 MillsIkWH 3.84 $/ton PM removed $112.2 SlkW-Yr S.S2 MillsIkWH 0.70 Slton PM removed $20.4 $IkW-Yr 0.82 MilWkWH 0.10 Slton PM removed $3.0 $/1cW-Yr 19.42 MilIsIkWH 2.46

..$Iton PM removed $72.0 SlkW-Yr 2S.7S MilWkWH 3.27 $/ton PM removed $9S.4 $/kW-Yr· 4.0S MilWkWH O.SI Slton PM removed $IS.0 SlkW-Yr 0.60 MillslkWH 0.08 Slton PM removed S2.2 SlkW-Yr 13.44 MillslkWH 2.42 S/ton PM removed $70.8 SlkW-Yr 18.10 MillsIkWH 3.01 Slton PM removed S88.0 LSFO $ $48,800,638 $IkW S626

S $2,691,290 $IkW-Yr 34.S0 MilWkWH 4.38 S/tOn S02removed S3S0.4 $ S903,322 SIkW-Yr 1l.S8 MilWkWH 1.47 Slton S02 removed S117.6 S S10,882,S42 $IkW-Yr 139.S2 MilWkWH 17.70 Slton S02removed $1,416.9 $ $14,477,IS4 $IkW-Yr 18S.60 MillsIkWH 23.S4 Slton S02removed $1,88S SlkW-Yr 46.9S MillslkWH S.96 Slton S02removed $476.8 $IkW-Yr IS.76

. MillsIkWH 2.00 Slton S02removed $160.1 $IkW-Yr 10S.73 Mills/kWH 13.41 $/ton S02 removed SI,073.8 SIkW-Yr 168.4S MillsIkWH 21.37 Slton S02removed SI,71O.7 SIkW-Yr 34.50 $2,202,176 28.23 3.S8 $23.8 S2,783,SI2 3S.69 4.S3 $30.1 6.08 0.77 $S.I 4.07 0.S2 $3.4 21.40 2.71 $18.1 31.S4 4.00 $26.6 4.47 0.S7 $3.8 2.99 ··0.38 S2.S 14.81 2.67 $17.8 22.27 ·3.61 S24.0 LSD S37,S64,351 S482 $2,092,480

26.83 3.40 $287.6 $1,828,714

23.4S 2.97 .$2S1.3 S8,376,850

107.40 13.62· $I,IS1.3 $ 12,298,04S JS7.67 20.00 $1,690

.. 36.SI 4.63 $391.3 31.90 4.0S $342.0 81.39 10.32 $872.5 149.80 19.00 SI,605.9

26.83 fIOIVIO! mIV101 /lDIV/o! fIOIVIO! #lDIV/o! #DIV/O! fIOIV/O! #DIV/O! #DIVIOI ##DIYIOI ##DIY/O! ##DIVIOI ##DIY/OI ##DIV/OI ##DIYIOI ##DIYIOI ##DIY/OI ##DIVIOI ##DIYIO! ##DIVIO! #DIVIO! #DIV/O! /lDIYIO! ##DIV/O! #DIY/O! #PIV/O! #lDIYIO! '#DIV/OI ##DIY/O! ##DIY/O! #DIYIO! #DIYIO!

LSD UN/A UN/A #NUM! '#NUM! #NUM! #NUM! #DIY/O! #DIY/O! ##DIYlOl #DIY/o!

UN/A UN/A UN/A #NIA #NUM! #NUM! #NUM!

#NIA #NUM! #NUM!

. #NUM!

##DIY/O! ##DIY/O! #lDIY/o!

UN/A #NIA UN/A .#NUM! #NUM! #NUM! IINUM! mIVIO! mIVIO! fIOIVIO! #DIV/O! #lDIV/O! #lDIV/O! #DIV/O! #DIVIO! #DIV/O! #DIV/OI .##DIV/O! #DIV/OI #DIVIO! ##DIVIO! ##DIV/OI ##DIVIOI #DIV/OI #lDIV/O! #DIV/Or #DIV/O! #lDIV/O! #DIV/O! #lDIV/O!

. /lDIY/O! #lDIV/O! #DIY/O! #DIY/O! #DIY/O! #DIV/O! #DIV/O! ##DIY/O! #DIY/O!

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. #NUM!

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lIN/A #N/A UN/A #NUM! #NUM! #NUM! #NUM! fIOIV/O! fIOIVIO! fIOIV/O!

. #DIV/o!

/lDIV/O! #lDIV/O! #lDIV/O!

. #lDIV/O! fIOIV/O! /lDIY/O! #DIV/O! fIOIV/O! fIOIY/O! ##DIVIOI ##DIV/O! ##DIY/OI #lDIV/O! #DIV/O! #DIY/O! fIOIV/O! #lDIV/O! #DIV/O! #DIV/O! #DIY/O! #DIV/O! #DIY/O! #DIY/O! #DIY/O! #DIY/O! fIOIY/O! #DIY/O! #DIV/O!

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# I I •

f 

# I i 

### f**~COST3,** Input & Calculation SummaJY 2 2/8/2010,9:58 AMCUECost

-Air PollutionControl Systems Economics Spreadsheet MillslkWH 4.38 .3.40 #NUMI ##NUM! ##NUM! $/ton S02removed $350.4 $287.6 II'I'IUMI ##NUMI ##NUM! J'ariable O&M $/kW-Yr (1.58 23.45 IIDIVIO! #DIVIO! #DIVIOI MillslkWH 1.47 2.97 IIDIVIOI mlVlO! nDIVIO! $/ton SOlremoved $111.6 $251.3 #DIVIO! IIDlVlO! nDlVlO! FixdCharges W-Ye" MillsIkWH 73.20 13.19 56.35 (o.tS t#NIA t#NIA fIN/A t#NIA t#NIA , t#NIA $Iton SOlremoved $1,055.9 S8S8.0 flNUMI 

# tR= t#NIA t#NIA TOTAL .$/kW-Yr 119.l9 106.62 flNUMI MillsIkWH 19.03 (6.53 #NUMI f#NUM! flNUM! $/ton S02removed $( 5l4.0 SI.396.9 tlNUMI f#NUM! tlNUMI

ctlEcosn, Input«. Calculation Summary 3 2/8/2010,9:58 AMAppendix A.2.4 Permit to ConstructENVIRONMENTAL HEALTH SECTION Gold Seal Center, 918 E. Divide Ave. 

### NORTH DAKOTA Bismarck, NO 58501-1947 DEPARTMENTofHEALTH 701.328.5200 (fax) www.ndhealth.gov

July 22, 2010 

# FILE

Ms. Abbie Krebsbach Environmental Manager Montana DakotaUtilities Co. 400 N Fourth Street Bismarck, ND 5850I Re: Heskett Station Unit 2 Limestone Injection Project Dear Ms. Krebsbach: Enclosed is a Pennit to Construct which establishes sulfur dioxide emission limits for the R.M. Heskett Station Unit 2. A public comment period was held regarding the Pennit to Construct and other elements ofthe North Dakota Regional Haze State Implementation Plan Supplement No. 1 from June 10 through July 11,2010. The only significant changeto the draft Pennit to Construct was a revision ofthe language in the first sentence under Section II, Pennit Conditions. This sentence was revised to indicate that the limits are only effective if, and when, EPA approves those limits as part of the North Dakota Regional Haze SIP.

. Please advise the Department within 15 days after completing the project to allow for an inspection by the Department. Compliance with the emission limits in the Pennit to Construct must be achieved as expeditiously as possible but not later than five years after the Environmental Protection Agency's approval ofthose limits as part oftheNorth Dakota Regional Haze SIP

.

. In addition, within 12 months after commencing operation of the new andlor modified equipment, a

pennit revision application for the project for a significant modification to the Title 

### V Pennit to Operate must be submitted to the Department. Ifyou have any questions, please contact Tom Bachman ofmy staffat (701)328-5188. Sincerely,

Terry L. OtClair, P.E. Director Division ofAir Quality TLOIfB:saj Ene: xc: Gail Fallon, EPA Region 8 CusterDistrict Health Unit, Mandan, ND
Environmental Health Division of DMslonof Division of Division of Section Chiefs Office Air Quality Municipal Facilities Waste Management Water Quality 701.328.5150 701.328.5188 701.328.5211 701.328.5166 701.328.5210 Printedon recycledpaper.ENVIRONMENTAL HEALTH SECTION Gold Seal Center, 918 E. Divide Ave.

# ~~ NORTH DAKOTA Bismarck, ND 58501-1947

### ~~ DEPARTMENTofHEALTH 701.328.5200 (fax) www.ndhealth.gov

AIRPOLLUTION CONTROL

PERMIT TO CONSTRUCT

Pursuant to the Air Pollution Control Rules ofthe State of North Dakota (North Dakota Administrative Code Article 33-15, Chapter 3j-15-14 and Chapter 33-15-25), the North Dakota Department ofHealth hereby grants a Pennitto Construct for the following source: I. General Information: A. Permit to Construct Number: PTCI0028 B. Source: I. Name: R.M. Heskett Station Unit 2 2. Location: Mandan, North Dakota, Morton County 3. Source Type: Fossil-fuel fired steam electric unit with a nominal generating capacity of 916.5 million British thenna! units per hour (106 Btu/hr). C. Owner/Operator: I. Name: Montana-Dakota Utilities Co. 2. Address: 400 N Fourth Street Bismarck, ND 58501-4092 II. Permit Conditions: This Pennit to Construct establishes sulfur dioxide emission limits for R.M. Heskett Station Unit 2 if, and when, EPA approves those limits as part of the North Dakota Regional Haze SIP. While this Pennit to Construct authorizes the construction and initial operation ofnew or modified air pollution control equipment and process changesto reduce sulfurdioxide emissions, the pennitteemayberequired to apply for a Prevention ofSignificant Deterioration (PSD) pennit to authorize any significant net emissions increase ofparticulate matter, PMIO and/or 

### PM2.

### s , that will result from the installation ofthe new or modified pollution control equipment and the process changes.

Environmental Health Division of Division of Division of Division of Section Chiefs Office Air Quality Municipal Facilities Waste Management Water Quality 701.328.5150 701.328.5188 701.328.5211 701.328.5166 701.328.5210 Printed on recycledpaper.Page.£of

### 2­**PenIrit~o.** 10028 If new emission units are created, a new Permit to Construct may be required in accordance with**~DAC** 33-15-14-02. The source shall be operated inaccordance with the terms ofthis Permitto Construct, anyrequired PSD permit and the Title V Permit to Operate until a revised Title V Permit to Operate is issued. The source is subject to all applicable rules, regulations, and orders now or hereafter in effect ofthe North Dakota Department ofHealth and to the conditions specified below: A. Special Conditions: 1. Emission Limits: The term "12-month rolling average," as used in this penIrit, shall be determinedby calculating anarithmetic average ofall operating hourlyrates for the current month and the previous 11 months. A new 12-month rolling average shall be calculated by the 30th day following the endofeachmonth. Each 12-monthrolling average rate shall include start-up, shutdown, emergency and malfunction periods unless those periods are exempt by this permit. The 12-month roJling average emission rate is calculated from average monthly values as follows: Ifdemonstrating compliance with the limit in Condition II.A.l.a(I), calculate the S02 removal efficiency for the month as determined by the outlet S02 emissions measured by the continuous emissions monitoring system (CEMS) and compareto the average sulfur input to the boiler. The average monthly sulfur input to the boiler shall be based onthe amount offuel combusted inthe boiler and the average ofthe coal sulfur concentration samples measured during the month. If demonstrating compliance with the limit in Condition II.A.I.a(2), provide the outlet S02 emissions as measured and calculated by the CEMS.

a. The permittee shall not discharge or cause the discharge of sulfur dioxide (S02) into the atmosphere from Unit 2 in excess ofeither: 

### (l) 30.0% of the S02 equivalent reaching the inlet of the boiler (70.0% reduction) ona 12-monthrolling average basis, or as an alternative; (2) 0.60 pounds per million British thermal units 

### (lb/106 Btu) on a 12-month rolling average basis. b. Thepermittee shall conduct an optimization study to establishthe highest sustained sulfur (S02)removal efficiency achievableby adding limestoneto the bed material, taking into account any technical, operational, and reliability considerations, other pollutant emissions and environmental impacts, and cost effectiveness. (1) Within 180 days ofinitial start-up ofthe limestone injection system, the penIrittee shall submit a protocol that describes the parameters to be monitored/measured during the study and provide a schedule for completion ofthe study and report. (2) Upon Department approval of the test protocol and schedule, the

. optimization study shall be completed and a report submitted to the

Department within the schedule approved in the study protocol.Page 

### l ofJ..... Pennit No. 10028 (3) Ifthe study results indicates that sulfur (S02) removal beyond the limits in Condition II.A.I.a(I) and ILA.l.a(2) is achievable, aftertaking into account technical feasibility, operational and reliability consideration, other pollutant emissions and environmental impacts, and cost effectiveness, the pennittee shall apply for a Pennit to Construct to make the new S02 limit federally enforceable. The pennittee shall begin complying with the new limit as outlined in the new, or amended, Pennit to Construct.

c. The S02 emission limits apply at all times including startup, shutdown, emergency and malfunction. 

### 2. Compliance Date: Compliance with the emission limits and other requirements ofthis permit is required as expeditiously as practicable but in no event later than five years after the U.S. Environmental Protection Agency (EPA) approves this pennit as part of the Regional Haze SIP. For purposes ofestablishing the first month ofthe 12-month rolling average limits in Condition ILA.I., the pennittee shall begin monitoring for compliance within five years ofEPA approval ofthe SIP, as described above, or within six months after initial startup ofthe limestone injection system, whichever is earlier. 

### 3. Continuous Emission Monitoring System (CEMS): The emissions from Unit 2 (main stack) shall be measured by continuous emission monitors (CEM) for S02, C02, and flow. The monitoring requirements under Condition n.A.4 shall be the compliance determination method for S02. 

### 4. MonitoringRequirements and Conditions:

a. Requirements: Testing and monitoring protocols used to demonstrate compliance with the emission limits ofCondition ILA.1 above shall he as follows: Table 1 MonitoringRequirements by PollutantIParameter 

# I 

# I 

# I

b. Emission Monitoring Conditions: (1) The monitoring shall be in accordance with the following applicable requirements ofChapter 33-15-06 ofthe North Dakota Air Pollution 

# t ! !

, 

### , i 

# , I ! PollutantlParameter Monitoring Requirement (Method) Condition Number S02 (inlet) Coal Sampling Data 4.h.(6) S02 (outlet) CEMS 4.b.(l), 4.h.(2), 4.b.(3), 4.b.(4) & 4.b.(6) CO2 CEMS 4.b.(I), 4.b.(2), & 4.b.(3) & 4.b.(4) Flow Flow Monitor 4.b.(1), 4.b.(2), & 4.h.(3) & 4.b.(4)

### PageA..ofL Pennit No. 10028 Control Rules and the Acid Rain Program. Emissions are calculated using 40 CFR Part 75. (a) Section 33-15-06-04 of the North Dakota Air Pollution Control Rules, Monitoring Requirements. (b) 40 CFR 72 and 40 CFR 75. (2) 

### The Department may require additional performance audits ofthe CEMS. (3) 

### When a failure of a continuous emission monitoring system occurs, an alternative method, acceptable to the Department, for measuring or estimating emissions must be undertaken as soon as possible. The procedures outlined in 40 CFR 75, Subpart D for substitution are considered an acceptable method for the emission rate limit. Timely repair ofthe emission monitoring system must be made. (4) 

### The permittee shall maintain and operate air pollution control monitoring equipment in a manner consistent with the manufacturer's recommended procedures, or a site-specific QAlQC 

### Plan required by 40 CFR 75. The permittee shall have the QAlQC 

### Plan available on-site and provide the Department with a copy when requested. (5) 

### Within 180 days ofinitial startup ofthe equipmentrequired to meetthe S02 limits, conduct an emissions test to measure particulate emissions, using EPA Test Method 5, 5B or Method 17 in 40 CFR Part 60, Appendix A. Othertest methods may be used provided they are approved, in advance, by the Department. (6) 

### The requirements in 40 CFR 60, Appendix A, Method 19, Section 12.5.3 shall be used to determine overall reduction of S02 emissions based on outlet CEMS data and inlet coal sample analysis. Section 12.5.3.2 shall be used to calculate the inlet S02 rate. In place of the ASTM D 2234 requirements of 12.5.2.1 of Method 19, coal sample collection will be conducted at least daily when the boiler is in operation to generate the average monthly inlet S02 emissionrate. Coal sample analysis shall occur at least weekly whenever samples are collected during that week. Daily samples within a calendar week may 

### be combined to form a composite sample that is analyzed for the required parameters. For purposes of determining compliance with the S02 percent reduction requirement, the reduction efficiency shall 

### be determinedas follows: % Reduction Inlet**SO~** 

### Rate-Outlet S02 Rate x 100 Inlet S02 Rate Where: The Inlet S02Rate is in units oflb/l06 

### Btu or lblhrandthe Outlet S02 Rate is in the same units as the Inlet S02 Rate.Page 

### 2. of.l PermitNo. 10028 5. Recordkeeping Requirements:

a. The permittee shall maintain compliance monitoring records for Unit 2 as outlined in Table 2 - Monitoring Records, that includes the following information: (1) A copy ofthe sample analysis report(s), including the date that the sample analysis was performed; the company, entity, or person that performed the analysis; and the testing techniques ormethods used. (2) The records ofquality assurance for emissions measuring systems including but not limited to quality control activities, audits and calibration drifts as required by the applicable test method. (3) A copy ofall field data sheets from the emissions testing. (4) A record shall be kept ofall major maintenance activities conducted on the emission units or air pollution control equipment. (5) Records shall be kept as to the type offuel usage. Table 2 Monitoring Records PollutantlParameter Compliance Monitoring Record S02 outlet (Ib/l0° Btu & lblhr) CEMS Data S02 inlet (lb/l0° Btu) Coal Sampling Data CO2 CEMSData Flow Flow Monitor Data b. In addition to requirements outlined in Condition 1I.5.a., recordkeeping for Unit 2 shall be in accordance with the following applicable requirements of Chapter 33-15-06, Chapter 33-15-14 ofthe North DakotaAirPollutionControlRules and the Acid Rain Program: (1) Section 33-15-06-05 of the North Dakota Air Pollution Control Rules, Reporting and Recordkeeping Requirements. (2) 40 CFR 72 and 40 CFR75 as incorporated by NDAC 33-15-21-08.1 and 09.


### c. The permittee shall retain records of all required compliance monitoring data and support information for a period ofat least five years from the date ofthe compliance monitoring sampling, measurement, report, or application. Support information includes all maintenance records ofthe emission units and all original strip-chart recordings/computer printouts and calibrations of the continuous compliance monitoring instrumentation, and copies ofall reports required bythe permit.**Page~of.l** 

### PennitNo. 10028 6. Reporting:

a. Reporting shall be in accordance with the following applicable requirements of Chapter 33-15-06 and Chapter 33-15-14 ofthe North Dakota Air Pollution Control Rules and the Acid Rain Program: (1) 

### Section 33-15-06-05 of the North Dakota Air Pollution Control Rules, Reporting and Recordkeeping Requirements. (2) 40 CFR 72 and 40 CFR 75 as incorporated by NDAC 33-15-21-08.1 and 09. (3) NDAC 33-15-14-06.5. b. Quarterly excess emissions reports for Unit 2 shall be submitted no later than the 30th day following the end ofeachcalendarquarter. Excess emissions are defined as emissions which exceed the emission limits for Unit 2 as outlined in Condition ILA.I.a(t) or (2). Excess emissions shall be reported for the following: Parameter Reporting Period S02 % 

### reduction (Monthly and 12-month rolling average)

or S02 Ib/I06 

### Btu at outlet (Monthly and 12-month rolling average)

c. The pennittee shall submit a semi-annual report for all monitoring records required under Condition II.A.5 on fonns supplied or approved by the Department. All instances of deviations from the pennit must be identified in the report. A monitoringreport shall be submitted within45 days afterJune 30 and December 31 ofeach year. d. Thepennittee shall submit an annual compliancecertificationreportwithin45 days after December 31 ofeach year on fonns supplied or approved by the Department.

e. For emission units where the method ofcompliance monitoring is demonstrated by either an EPA Test Method or portable analyzer, the test report shall be submitted to the Department within 60 days after completion ofthe test. f. The pennittee shall submit an annual emission inventory report on fonns supplied or approved by the Department. This report shall be submitted by March 15 of each calendar year. Insignificant units/activities listed in this pennit do not need to be included in the annual emission inventory report. g. The pennittee shall notify the Department within 15 days ofthe actual startup date ofthe equipment required to meet the S02 permit limit.Page.lof.l PermitNo. 

### 10028 B. 

### General Conditions: 1. This pennit shall in no way pennit or authorize the maintenance ofa public nuisance or danger to public health or safety. 

### 2. The pennittee shall comply with all State and Federal environmental laws and rules. In addition, the pennittee shall comply with all local building, fire, zoning, and other applicable ordinances, codes, rules and regulations. 

### 3. All reasonable precautions shall be taken by the pennittee to prevent and/or minimize fugitive emissions during the construction period. 

### 4. The pennittee shall at all times, including periods ofstartup, shutdown, and malfunction, maintain and operate Unit 

### 2 and all other emission units including associated air pollution equipment and fugitive dust suppression operations in a manner consistent with good air pollution control practices for minimizing emissions. 

### 5. Any duly authorized officer, employee or agent oftheNorth Dakota Department ofHealth may enter and inspect any property, premise or place at which the source listed in Item I.B. ofthis pennit is or will be located at any time for the purpose ofascertaining the state of compliance with the North Dakota Air Pollution Control Rules and the conditions ofthis pennit. 6. The conditions of this pennit herein become, upon the effective date of this pennit, enforceable by the Department pursuant to any remedies it now has or may in the future have, under the North Dakota Air Pollution Control Law, NDCC Chapter 

### 23-25. Each and every condition ofthis pennit is a material part thereof, and is not severable.
FORTHE NORTH DAKOTA DEPARTMENT OF HEALTH



### Date:

__....... 

### .....

# 7+~....;;Z-2.'-=..jI--=I=()'--

__

# ~L¢.ocL:**T~rry** 

### L. O'C 

### r, P.E. DIrector Division ofAir QualityAppendix F.l Public Participation Record

### Notice ofIntent to Amend the State Implementation Plan for AirPollution Control Relating to the Reduction ofRegional Haze

The North Dakota Department ofHealth has prepared a supplement to the State Implementation Plan (SIP) for the Control of Air Pollution for the State of North Dakota which addresses Regional Haze (visibility impairment) in the Federal Class I areas. The supplement addresses requirements for the R.M. Heskett Station Unit 2. The requirements will reduce regional haze in Theodore Roosevelt National Park (TRNP) and Lostwood Wilderness Area (LWA). The supplement includes a Permit to Construct for R.M. Heskett Station Unit 2 which establishes sulfur dioxide emission limits which are intended to improve visibility impairment in TRNP and LWA.

A copy of the proposed supplement may be reviewed at the Department's website at www.ndhealth.gov/AO/RegionaIHazel

. A copy ofthe proposed supplement may be obtained by writing to the North Dakota Department of Health, Division of Air Quality, 918 E Divide Avenue, 2nd 

### Floor, Bismarck, ND 58501-1947 orcalling (701)328-5188. Written comments may be submitted to the above address from June 11, 2010 through July 11,2010. A public hearing will be held only ifthere is a request from the public for a hearing. Any request for a public hearing must be submitted in writing and received by the Department before the end of the public comment period. Ifa public hearing is requested, it will be held on July 16, 2010 at 9:00
a.m. CDT in the Gold Seal Center's fourth floor conference room at 918 E Divide Avenue, Bismarck, ND. If a public hearing is requested, the public comment period will remain open through July 26, 1020.

The National Park Service, Federal Land Manager for TRNP, has provided comments on the proposed supplement. The comments and the Department's response to those comments may be accessed at the website listed above orbycontactingthe Department.Ifyou plan to attend a requested hearing and 

### will need special facilities or assistance relating to a disability, please contact the Department ofHealth at the above address at least three days prior to the hearing.

26th Dated this day ofMay 2010
Terry L. O'Clair, P.E. Director, Division ofAir Quality

# Affidavit of Publication

Colleen Park, being duly sworn, states as follows: 1. 

### ram the designated agent, under the provisions and for the purposes of, Section 31-04-06, NDCC, for the newspapers listed on the attached exhibits. 2. The newspapers listed on the exhibits published the advertisement of: ND Health Dept
- Notice of Intent Air Pollution; 1 time(s) as required by law or ordinance. 

### 3. All ofthe listed newspapers are legal newspapers in the State of North Dakota and, under the provisions of Section 46-05-01, NDCC, are qualified to publish any public notice or any matter required by law or ordinance to be printed or published in a newspaper in North Dakota. Signed:

# _.I...t::.~~::!o:::!::Z=......!fL.L==-_,

# _

State of 

# /110
Couhtyof 

# BlI1</&4H nAil

. \}.' 11, 11 

# ,c. J/) 

### Subscribed and'

### sWorn·to before me

### thi~ day 

### of

___ 

## u:::...­**..t.tI_....::W~...;;...;;;;;;**

## __"20.!JL. 

# /ndti 

# udd

LINDA J. JUDD • Notary Public**~** 

## state of North Dakota**~** j My Commission Expires July 9, 2014**~**""1 •••- Nl.IJ"W.!NIM.....

.**V~** "'It

..... 1 t""'t"'='''I. '""",,Wt Utc
., SlIndra**K.1Ci.Iltz.~** #05186 '. d4!scribeIt III dlrJud&lnent to die IIWIIIIt ' THIS IS AN A1TEf1PT ro COlLECT bidder fer ash at public IIICdoII lit die

. NotIceoflnClent THE REFERENCED DEBT AND ANY

. frontdooroftheCounhouseirllheOqof toAmendthe INFOkMATION OBTAINED WILL BE Bismarck in the County of Burleigh and StaCIa Implell'lelltaCiol1 Plan USED FOR THAT PURPOSE. THIS SI3te ofNorth Dakota, onjune 30,2010,at

. forNt PollutIon ConI:roI COMMUNICATION IS FROM A DEBT the hour of 10:00AM. (Cl). to sadlly the RelatIngtothe RedudIon COt.LECTOR. amount due.with inIIlnstIhereo!!.and the ofRezIonaI Haze SI22.29 1615

- 6OS4S4 COSIS andexpenses ofsuchAli.or 101IIICh '

, The North DaIcota Department ofHealth thereof u the proceeds of such sale wi

.

flu prepared a sUpplement to the State 

# saIi* The property to be sold 5 siwated ImpIementaIion Plan (SIP) for the Control STATE OF NORTH DAl<'Ol'A in the County of BurleIgh and SI3te of ., of Air PoIIuIion for the State of North IN 0ISTRlCT COURT

. North DakDta. and described u follows:

. Dakotawhich addresses Regional Hue(vis- COUNTY OF BURLEIGH SOUTHWEST The North23 FeetofLot I9.AM ofLot20 ibIIity Impairment) in the federal Class I JUDICIAlDISTRlCT and the South 10 FeetofLot 21,BIock38. areas. The supplement addresses require- BlI1lJo M.Jadcson, fisher AddIIion to the Oq of Bbmarck 

# !

menu for the'ltM. Heskett Stidon UIlIt 1 Plaintiff. for Street. HIpiIy arid UIlIic.y Purposer The wiM reduce regional haze w. by Imtrument Reterded in Book ll9;.' in Theodore Roosevelt Nadonal Park MorrIs E.Jackson, Paa 480 aka 1207 N. 14th St Bismardc:., 1\ 

# C Pl and Lostwood WiIdemess Area Derendant

. ND 58501. ,I**~.The** supplementIncludes a IiIrmItto tim No. INTESTIMONYWHEREOF. I '- hereun­ " a foi 1lM. Heskett Station Unit 2. SUMMONS to set rrrt hand and seal this Ilth day rJ' whid1 establishes sulfur dk»dde emission THE STATE OF NORTH DAKoTA**~20IO.** fnnlls which areintended toIrnprow vIslbil- TO' THE ABOVE-NAMED Is/Pat 0 HeInert Ity impairment inTRNP and lWA." .' DEfENDANT. Pit 0 Heinelt Acopy ofthe proposed supplementmaybe 'YOU A1lE HEREBY SUMMONED and' SheriffofBurtei&b**Cou~** North Dakota reviewed lit the Oepartmem's websIca at required to appear and defend IfIInst the BrJs/Dan

### v.nu www.ndhealth.govlAQIRegIonaIHaze1. A ComptaInt in the KIion,which Is IIiIrMth Deputy copy of the pn:!pOSed supplement may be senIid upon rou. orwII be ftIed with the STATE OF NoRTH DAl<'Ol'A

# L:

. obaJned by.writing to the North Dakota Cleric of this Court, by serving upon the IS. , Department of Health. Division of Air undersigned an. answer or other proper, , County ofBurleIgh

. ..' QualIty. 9.18 E DIvIde A\'!Inue. 2nd Floor. response within. twenty (20) iI:qs after On this Ilth dayof I1a);2010. ,me.

### a: Bismarck. ND 58501-1947 or alII", the SI!nke,:of this Summons IlPQlq'OlI. Notary Public in and for said County and

. 

### :) (701)328-51saWr1tter! COIIIIllIIIti.may be, eKdusiwl ofthe d:Iti.ofsertIce.**If:~** r.II tl)**Sta~** personally appeared Dan Wentz. , submitted to the aboYeaddrestfromJune

. do judgment by default wi bi\.tal!.en known. to me to be the penon Who IS:. l' 

### I i II. 20I 0 through July**II~** 20**I~** •.,. publie 3pinst you for tile relief ,iJemanded in described In,and whose name Is subscribed'. hearingwill beheld only ifthere iurequest the ' . ,. ' tothis insIrument

. '. from die public for a hearing.Arrt request :. IsINormaj. Braddock .' ' 

### i 

# ·n for a public hearing must be submitted In

. NotaryI'ubIIc .': 

# II , writing and reCeM!d by the " under. Rule**p.~** pfthe oaJcOi:a**~** Budel&h County. North**~** . ,.. i befOre the end oftheWblie cOmmentriert-,of.CO\.II1, lIPOII servlCl! of this summons. " My COmmIssion 1Ilqiires:2120113**(Seil~** '; I ocI.ffa publJc hearln, Isrequested..!twl!I be ,,ou; ar)d the plaintiff,.**~** b!)!JIid :by, the ' MACKDfF K8.1OGG. LAWBRM

.. , . held on JuIr 16.2010 at 9:00 a.m. CDT In

. 'foIlo'oYI", restr'aInts: " .'

.... .' P'Q Box 1097

.<.' the GoldSf:aI Center's fourth floor confer.' (I) Neither spouse**!1lIlid~l?fisell"** OkkInson. NO 58602-1091" ,', 'elite room at 918 E Divide AVenue, '.ei)(I!mbeI;«otherWise diSsiP.;ite"**'A~** for PlalIItIIf :' '. ",

.

.Bismarck. NOh public heatin, Is request- , any oft/leparties' aSsets. except!**\"(Publlshed:06IOS;06/I2;~,*lDr'**

. ; eel,the public comment period wil remain' 1A) For.**~iIies** oflife or for

. 615. 12 1 19·**~~!~** 

### .., open throughJuly 26, 1020. , the,necessary generation of The Nalional Park· ServIce. federal Land income orpresenalion of

. Manager forTRNP, has provided comments assets;or . on the proposed sUpplement The com-
. (8) , For retalnlngctluniel·.to ments and the Depal:trnent's response to
. cmyonortocontestthe

. those. comments- mar. be accessed at the

. . pro(eedln,c. . ' '

.. websIca Hsted above "r by contacdng the ·If a spouse disposes of,**sells,;~'** Department'.

. ..or dissipate!!**~,durIng,_the** If )"011 plan tp attend a requested hearin, Interim periQiI..t!lai Sj)O\ISe. shall •

.and will need

## C! facilities or assistance· to.the other spouse'an aCtOuntiRz within

. 

# !**~aof H.:r·ar::~o::':t=thi(f)~~Pouse!III!T~**  the**~er** 'n..-.TI_, at leastthreedIrs prtor tothe hearing. spouse,·,,· . Dated this**~6th** day ofMay 20I O. (3) All curl'l\llltly avallabhj Insonnce Ten-y LO'Qalr. P.E. c:amaae must be malri!alned and Director, Division ofAir QualIty ,continued WIthout change.· In

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. . provisions. that spouse may be In 

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# I I

, , STATE OF NORTH DAKOTA CCII1temptofcourt.. IN DISTRICT COURT Dated this 17th day ofFebruary, 2010. COUNTY OF BURlEIGH , 1s1Thcrisa L Cole

,SOUTH CENTRAl.JUDICIAlDISTRICT TheresaLCole American Legal Senlces. P.e.

. I 

# l' Che¥y Chue

### ~k. FSa. Plaintiff. ' 521 East MaInA\'!Inue.Suite 400 Bismardc. ND 5850I

### ~=tIon, joIe and any penon In poss8ssion. (101) 258-1074 Defendants. ' Fax (101) 530-1943

### ~;:::;~~ Civl1 No. 10.c1 8 NO Bar1lO5l85**,·DM.~** \Nfl) (Bid Schedule I) and the instal.

. SUMMONS ·ration and usoclated piping. Owner .' At:tomtq fer PlaIntiff THESTATE OF NORTH DAl<'Ol'A10THE 6/5,12 & 19

- 605516 fumlshed pre-treatJ11elltequipment.Owner ABCN£ NAMED DEFENDANTS: l'umlshed MFIUF membrane equlpment". You are hereby summoned to appear and chemial feed eqUipment, headng and , Deadlines defend IfIInst the Complaint in this aaIon, · ventilation, eIectriaI,. and additional '10. which hu. been filed with the Cleric of miscellaneous items atMandareeWTP (Bid .• PUBLISH BY RECEIYEBY Schedule 2). BidSchedule 31sfor combined'

. servin& upon the undersigned a copy ofan Court and .is herewith ser'II!d uponrou. by BId Schedules I and 2 with BidAdjusCment. ' answer 0/' other proper response within dedua for. conna award of both I $chedules to a single Bidder. The

.Four 1 (20) dIrs after the service of this 1bes.•• ; ............. FrL 12,Nooft SuinmoM UJlOfIrou. IIKClusiwl ofthe day of ,t!ears and Mandaree projects are located in,

.,i ·McKenzie County ofNorth Dakota. service. If you fall to do so. judgment by Wed. .• .or. ............ '. t4on.**N~** default will be taken against lOu for the &dl BID must be a«ompanled by

# a. 'f relief demanded in the <:ompIaInt. 'The rate enwIfope containing acopy ofacurrent ., original Complaintis flied with the Cleric of and valid Nerd! Dakota Contractor's

·LIcense (must have been'lssued at least the District Court in the County in which FrIday

...................'*RIeI. 5P14 

### '


## .. this acdon is commenced, , 10 calendar dIrs befOre the date of BId This acdon relates to the foreclosure of a openlng.) and a BIDDER's Band equal to lat..•••••••••••Wed. 12 Noon 1M! percent of the full amount ofthe BID. IIIOI1pIe uponthe f'oIlowIlII described real 

# I propertyIn the County ofBurleigh,State of executed bytheBIDDERas Prlnc'P!' and by i

### North Dakota Newspaper Association 1435 Interstate Loop Bismarck, ND 58503-0567 Ph (701) 223-6397· Fax (701) 223-8185 

### INVOICE

Order 

### 27875·1006lNAO Invoice# 

### 131966 Attn: TOM BACHMAN ND REALmDEPARTMENT 600 E BOVLEV ARD AVE. DEPT. 301 BISMARCK, ND 58505-0200 Voice: 701.328.5188 Fax: 101.328.5200 June 25,2010 Advertiser: Administrative Serv: Accounting P.O.#: Amount Due $257.61 AmoU;llt Paid
PIet1Se detaell andretum thllportion wiJII your payment
Administrative Serv: Accounting Invoice# 27875-10061NAO-I31966 AdSize Rate Type Rate Total Discount (%) Caption Page RunDate
Brsmarck Tribune (Bismarck ND) 60.00 SPR2 0.72 .43.20 0.00 Notice of Intent Air P 06105110 Dickinson Pre

.. (DIckinson NO) 63.00 SPR2 0.63

. 39.69 0.00 Notice of IntentAIr P 06l06I10. Fargo, The Forum (Fargo NO) 63.00 SPR2 0.69 43.47 0.00 Notice**~f** IntentAIr P 06107/10 Grand Forks Herald (Grand Forks NO) 63.00 SPR2 0.71 44.73 0.00

. Notice of IntentAIr P 06105110 Minot Dally News (MInot NO) 87.00 SPR2 0.49 42.63 0.00 NoticeOf IntentAIr P 06l06I10. WIlliston Herald (WIlliston NO) 57.00 SPR2 0.77 43.89 0.00 NoticeofIntentAIr P 06l06I10
Gross Advertising 257.61 TotalMisc 0.00 AmountPaid**O~OO** Ar,alcyDiscount Tax 0.00 Adjustments 0.00

OtherDiscount 0.00 Total Billed 257.61 Payment Date ServiceCharge 0.00 Unbilled .0.00 Balance Due 257.61

Your payment Is due upon nK:e1pt. Thank)'Ou In advance for)'OUt prompt paymenUResponse to Public Comments

Commenter: Dakota Resource Council and National Parks Conservation Association (hereafter referred to as DRC) 

### Comment 1: DRC questions whether Heskett Unit 2 was properly evaluated under Reasonable Progress instead ofunder BART. 

### Response: The Department determined that Heskett Unit 2 was not subject to BART based on refined modeling submitted by MDU on June 9,2006. This modeling showed that the impact of emissions from Heskett Unit 2 was less than 0.5 deciviews (98th percentile) at the three units of Theodore Roosevelt National Park (TRNP) and Lostwood Wilderness Area (LWA). The Department, in a letter dated May 8, 2007, agreed that Heskett Unit 2 was not subject to BART. EPA and the FLMs questioned the modeling protocol that was used. A new protocol based on EPA and FLM criteria, which the Department does not necessarily agree with, was developed. MDU submitted modeling**~ased** on the EPA and FLM protocol which showed the maximum impact of emissions from Heskett Unit 2 was even less than the previous modeling at 0.28 deciviews (98th percentile). Both EPA and the FLMs have reviewed the 2009 modeling and did not object to the determination that Heskett Unit 2 was not subject to BART.


### Comment 2: DRC claims that the modeling that shows Heskett Unit 2 was not subject to BART
was not subject to public review. 

### Response: Both the 2006 and 2009 modeling analyses were posted on the Department's website for review during the public comment period for the Regional Haze SIP (December 2009

­ January 2010). The Department made its decision that Heskett Unit 2 was not subject to BART based on the 2006 modeling. The Department agreed to review that decision ifthe 2009 results showed Heskett Unit 2 was subject to BART. The Department found no reason to revise its May 8, 2007 decision that Heskett Unit 2 was not subject to BART. Both the 2006 and 2009

### modeling analysis were included in the final Regional Haze SIP submitted to EPA in March 2010.

The commenter indicates the impact to TRNP is 0.3 deciviews with the cumulative effects of0.5 deciviews including LWA. These results are from the 2009 modeling analysis. Apparently, the commenterhas reviewed the 2009 analysis and extracted data from it.


### Comment 3: DRC claims MDU's own modeling results shows Heskett Unit 2 to be subject-toBART when cumulative impacts to multiple class I areas are "appropriately" considered. Response: 

### DRC's position that a cumulative assessment ofthe impacts on multiple Class I areas is required to determine BART applicability is inconsistent with 40 CFR 51, Appendix Y ­ Guidelines for BART Determinations under Regional Haze. Section 111.3 of 40 CFR 51, Appendix Y, under Option 1, states "You can use dispersion modeling to determine that an individual source cannot reasonably be anticipated to cause or contribute to visibility impairment in !! [emphasis added] Class I area and thus is not subject to BART." There is no discussion regarding adding results for multiple Class I area. The modeling protocol the Department developed for determining whether sources are subject to BART (see Appendix A.l ofSIP) does not require a cumulative assessment ofimpacts on multiple Class I areas. The determination of whether a source is subject to BART is based on the maximum impact (98th 

### percentile) at any single Class I area. The Department's modeling protocol is consistent with 40 CFR 51, Appendix Y.


### Comment 4: The DRC provided several general concerns, with no supporting data for those concerns, regarding the Reasonable Progress Assessment.

4a. DRC states that overestimated costs tend to reduce the apparent cost effectiveness ofviable control technologies like Selective Non-Catalytic Reduction (SNCR). Response: 

### The Department compared the cost ofSNCR estimated by MDU to cost estimates for SNCR at four other small 

## « 200 MWe) facilities. The results show that the MDU cost estimate

### (annualized cost) was near the average with two estimates being higher. It 

### appears MDU's estimate is reasonable compared to similar size facilities.
4b. DRC has concerns that comparing costs and cost effectiveness primarily or solely based on North Dakota facilities may be flawed. 

### Response: The Department did not rely solely on cost estimates from other North Dakota facilities. MDU's cost estimate for SNCR was compared to two facilities in Minnesota, one in Montana and one in North Dakota. MDU's cost estimates for the wet scrubber and spray dryerlbaghouse were compared against results from EPA's CUECOST model. This model is used allover the U.S. The cost oflow dust SCR was compared to results generated for the PGE Boardman Plant in Oregon (this was a compilation of results by ERG, Inc. from allover the nation) and cost estimates from two North Dakota facilities. MDU's estimate fell within the midrange ofERG's estimated range for high dust SCR at the PGE Boardman plant. Low dust SCR is expected to cost more than 

### high dust SCR because ofthe flue gas reheat costs. This makes MDU's estimate even more conservative. The Department believes MOU's estimates are within the ± 

### 30% range required for BART control estimates even though this source is not subject to BART.
4c. DRC has concerns about not using the 98th 

### percentile visibility results for determining reasonable progress. 

### Response: As pointed out in the Response to Comments to EPA's comments on the FLM Consultation version of this supplement, the Regional Haze rule and EPA guidance does not require use ofthe 98th 

### percentile results. In 40 CFR 51.308(d) it states "The reasonable progress goals must provide for an improvement invisibility for the most impaired days over the period of the implementation plan and ensure no degradation in visibility for the least impaired days over the same period." 40 CFR 51.301 states "most impaired days means the average visibility impairment (measured in deciviews) for the twenty percent ofmonitored days in a calendar year with the highest amount of visibility impairment," Least impaired days means the average

### visibility impairment (measured in deceiviews) for the twenty percent of monitored days in a calendar year with the lowest amount ofvisibility impairment.
The Department is not aware of any EPA guidance that indicates the 98th 

### percentile visibility results should be used. To the contrary, in EPA's document "Additional Regional Haze Questions" August 3, 2006, this issue is addressed. In the response to Question 1 under the Reasonable Progress section EPA states "Unlike the technical demonstration for CAIR or BART, the reasonable progress demonstration involves a test ofa strategy. The strategy includes
a suite of controls that has been identified through the identification of pollutants and source categories ofpollutants for visibility impainnent

- the application of four statutory factors and how much progress is made with a potential strategy with respect to the glide path. Modeling occurs with a strategy and is not a source-specific demonstration like the BART assessment." [Emphasis added)

In response to Question 2, it is stated "Reasonable progress is not required to be demonstrated based on a source-by-source basis. It 

### is demonstrated based on a control strategy developed from a suite ofcontrols that has been assessed with the four statutory factors and the uniform rate ofprogress." [Emphasis added]

It is clear to the Department that a BART type assessment (Le. 98th 

### percentile) is not required. In fact, an assessment ofindividual sources is not required. The Response to both Question 1and 2 indicates any modeling should be assessed against the uniform rate ofprogress (glidepath). In Section 2.2 of "Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program", the uniform rate ofprogress, or glidepath, is determined for the average ofthe 20% worst days or 20% best days.
The Department has provided both the individual modeling results for sources and the cumulative modeling results for a control strategy for the group of sources that remained after the initial evaluation process was completed (see Section 9.1.5 ofthe RH SIP). We interpret the EPA guidance on Reasonable Progress to indicate that results for individual sources are notrequired. Therefore, any results presented would not have to include the 98th percentile values and should be compared to the average ofthe 20% worst days.

4d. DRC has a concern with a 12-month rolling average instead ofa 30-day rolling average and indicates the limit should be written as a nwneric limit and a percent reduction. 

### Response: Heskett Unit 2 is subjectto review under the Reasonable Progress requirements ofthe Regional Haze rule, not the BART requirements. The Department has found that it is not reasonable to require any reductions of S02 or NOx emissions from Unit 2. The reductions at Heskett Unit 2 are somewhat voluntary. Therefore, the Department believes that MDU should be afforded some flexibility in achieving the S02 reductions. A twelve month rolling average and allowing MDU to meet either a Ib/106 Btu limit or a percent reduction requirement allows this flexibility while still achieving the reduction of553 tons per year ofS02. The Department's modeling shows the proposed reduction in emissions will have virtually no effect on visibility in the Class I areas. Therefore, the averaging period ofthe emission limit will not affect visibility impacts. The Department has included adequate monitoring, recordkeeping and reporting in Conditions II.A.3-6 ofthe Permit to Construct. The commenter provided no specifics to dispute this finding.

Comment 5: DRC states that they attach and incorporate by reference the comments submitted
onJanuary 8, 2010 for the Regional Haze SIP. 

### Response: The Department incorporates by reference its response to the January 8, 20I 0 DRC comments (see Appendix F.8

- Environmental Groups ofthe North Dakota State Implementation Planfor Regional Haze; Adopted February 24, 2010).

Commenter: Montana Dakota Utilities (MDU)

Comment 1: MOU has concerns that the requirement for a PSD Permitto Construct for changes associated with the S02 removal project could delay the installation ofthe sulfur dioxide removal project. MDU requested that language be included in the supplement for the S02 removal

### project which would allow the compliance date to be changed based on when the PSD Permit to Construct is issued. 

### Response: The compliance date in the proposed Pennit to Construct for the S02 removal project states "as expeditiously as possible" but in no event later than five years after the U.S. EPA approval ofthe pennit as part of Regional Haze SIP. The Department interprets the language "expeditiously as possible" of this condition, to allow consideration of the timing of other pennits. Therefore, MDU will have up to five years to obtain any other required pennits. The supplement will 

### be revised to indicate that the issuance ofa PSD pennit for the removal project will affect the compliance date for the project.

## DAKOTA RESOURCE COUNCIL P. O. Box 1095, Dickinson NO 58602-1095 (701) 483-2851; www.drcinfo.com

July 11,2010 Terry O'Clair, Director Division ofAir Quality North Dakota Department ofHealth 918 East Divide Avenue, 2nd Floor Bismarck, NO 58501-1947 RE: Comments on the May 2010 Supplement No.1 to the North Dakota State Implementation Plan for Regional Haze
Dear Mr. O'Clair:
On behalfofthe Dakota Resource Council and the National Parks Conservation Association, we respectfully submit the following comments on the May 2010 Supplement No. I to the North Dakota State Implementation Plan (SIP) for Regional Haze (the Supplement), which addresses the Montana Dakota Utilities' (MDU) Heskett Unit 2 (Heskett) under the Reasonable Progress section ofthe Regional Haze Rule. We additionally attach and incorporate by reference the comments our organizations submitted on the State's Regional Haze Rule. l
We submit these comments on behalfofour more than 320,000 members and out ofconcern for the millions ofpeople who visit America's national parks and public lands each year. North Dakota's recently submitted Regional Haze SIP identified Class I areas affected by emissions from North Dakota facilities, including Heskett. Impacted lands include Theodore Roosevelt National Park and Lostwood National Wildlife Refuge Wilderness Area in North Dakota, as well as public lands in South Dakota, Montana, Minnesota, and Michigan.
We question whether Heskett is properly evaluated under the Reasonable Progress, rather than the BestAvailable Retrofit Technology (BART), portion ofthe SIP. Additionally, we echo the concerns raised by the Department ofthe Interior (001) and the Environmental Protection Agency (EPA), which were largely unaddressed by the North Dakota Department ofHealth (NDDH).

I Comments ofNational Parks Conservation Association et. al. on North Dakota's Regional Haze State Implementation Plan, January 8, 2010.Review ofHeskett under the Reasonable Progress requirements is questionable for two reasons. First, the public has not had opportunity to review the modeling, submitted to NDDH byMDU in December 2009. As described by EPA in its January 8, 2010 comments on the Regional Haze SIP,
"

...this updated modeling was completed after the start ofthe current public comment period on the Regional Haze SIP

...NDDH will need to revise the SIP to include the updated modeling and yourrelated conclusions. The revision will need to follow North Dakota's public participation process for SIP revisions." (p. 3) However, the modeling this purports to establish Heskett as not subject-to-BART has not, to our knowledge, been subject to public review. Its conclusions are instead here presented as fact. Second, MDU's own modeling shows Heskett to be subject-to-BART when cumulative impacts to mUltiple Class I areas are appropriately considered. The impact to Theodore Roosevelt National Park (TRNP) is 0.3 deciviews, with cumulative effects of0.5 deciviews including Lostwoods National Wildlife Refuge. Based on this cumulative impact, we believe that Heskett is more appropriately evaluated as subject-to-BART. 

### In general, we concur**wit~** the comments submitted by DOl and EPA, and find NDDH's response to these comments inadequate and unpersuasive. In particular we have continued concerns about: Overestimated costs, which tend to reduce the apparent cost effectiveness ofviable control technologies like Selective Non-Catalytic Reduction (SNCR). Comparing costs and cost effectiveness primarily or solely with other North Dakota facilities, which may be similarly flawed, rather than a broaderpool. When compared to determinations around the country, most ifnot all ofthe options available are cost effective on a $/ton basis.

. The dismissal of98th percentile dayresults (and direct EPA comments on this matter) in examining visibility benefits, as required in a BART analysis. This tends to minimize the visibility benefits ofemissions reductions. The lack ofstringency in the limit established, with regard to the numeric limit, averaging time, and otherparameters. There is no reason to establish a less stringent 12-month rolling average rather than a 30-dayrolling average. Although the optimization described in the permit may result in a lower limit, this process is not subject to review by anyone other than NDDH. The permit limit should require compliance with both a percent emission reduction and a numeric limit, not a choice ofone orthe other.We ask that the analysis ofthe Heskett facility be considered in the context ofthe far-reaching impacts ofthe facility's emissions on air quality, visibility, public lands and public health. The Heskett facility is likely more appropriately considered under the BART rubric rather than Reasonable Progress. This analysis, like many in the Regional Haze Plan, seems to have overinflated costs, underestimated benefits, and a severely limited the pool ofcomparison for what is deemed "cost effective," thereby making reasonable technologies appear less so. There is no reason for NDDH to allow the Heskett facility to reduce its emissions a minimal amount when better, cost effective options exist.
Thank you for the opportunityto comment on the Reasonable Progress analysis ofthe Heskett facility. Sincerely,

Mark Trechock, StaffDirector Dakota Resource Council P.O. Box 1095 Dickinson, ND 58602-1095 701-483-2851

Stephanie Kodish National Parks Conservation Association 706 Walnut Street, Suite 200 Knoxville, TN 37902 865-329-2424

CC: U.S. EPA Region 8 NPS, Air Resources Division

# V. MONTANA-DAKOTA
• UTILITIES

### CO ADiviSlOll ofMDUResources Group. Inc. 400**N;Jrr;~** Faul!h Strear Bismarck ND 5850I i7!)l) 22N9O(i July 9, 2010 Mr. Terry O'Clair Director Division ofAir Quality 2nd Floor North Dakota Department ofHealth 918 E. Divide Avenue Bismarck, ND 58501-1947 Re: Comments on the North Dakota Department ofHealth May 2010 Supplement No.1 to the State Implementation Plan for Reducing Regional Haze

## 1-~Y71 Dear**M~** ....O'Clair.' Montana Dakota Utilities Co. (Montana-Dakota) is submitting this letter to provide comment on Supplement No. 1to the North Dakota State Implementation for Regional Haze (RH SfP Supplement) dated May 2010. Montana-Dakota generates, transmits and distributes electricity and distributes natural gas in North Dakota, South Dakota, Montana and Wyoming. The company owns and operates electric steam generating facilities which are subject to extensive regulation W1der the Federal Clean Air Act. The following comments pertain to R.M. Heskett Station Unit 2 (Heskett Unit 2) in the RH SIP Supplement. The RH SIP Supplement incorporates a permit to construct (PTC) specific to Heskett Unit 2. Section II ofthe PTC acknowledges that certain physical changes that will be necessary to meet the sulfur dioxide conditions in this PTe may require a separate permit: "While this Permit to Construct authorizes the construction and initial operation of new ormodifiedairpollution control equipment andprocess changes to reduce sulfur dioxide emissions, thepermittee may be required to apply for a Prevention of Significant Deterioration (PSD)permit to authorize anysignificant net emissions increase of particulate matter, PM10 and/or PM2.5 that 

### will result/rom the installation of theflew ormodifiedpollution control equipment andprocess changes. This condition is unique to Heskett Unit 2 as compared to the other PTCs that wi\] be issued to North Dakota power plants subject to BART and Reasonable Progress Goals; therefore, it is important to address possible timing concerns that arise from a situation where pemlitting delays to authorize a project could prevent meeting the compliance date specified in PTC condition I1.A.2. Specifically, 

### ifa PSD permit is required in order to meet the conditions in the PTC, then lhe time necessary to complete PSD review can take several months and could potentially jeopardize the timing ofproject completion.Montana·Dakota Comments on May 2010 Supplement No.1 for the NDDH RH SIP July 9,2010 Page 2

The purpose ofthis comment letter is to request that the RH SIP acknowledge the inherent risk in issuing a PTC for an emissions reduction when the PTC itselfdoes not authorize changes to the facility that are necessary to meet the emissions reduction. We request that the following Janguage be inserted onpage 5 ofthe RH SIP Supplement at the end ofthe section titled "Time Necessary for Compliance" as evidence ofthis acknowledgement: "TheDepartment recognizes that limestone injection in the Unit 2AFBCmaypotentially cause an increase in otherpollutants for which a separatepermit to construct, including a PSDpermit, maybe necessitated. 

### If a relatedpermit to construct is required, then that permittingschedule mayimpact the timingof the contemplatedS02 emissions reductions pennitattachedto this supplement. The Department recognizes that the S02 reduction pennit may needto bemodifiedto address the schedule forprocessing any relatedpermit action. " Thank you for the opportunityto provide comments on the proposed RH SIP Supplement. Please contact me at (701) 222-7844 ifyou would like to discuss this further. Sincerely,

# ~:~;k~_ Abbie Krebsbach Environmental Manager

cc: Andrea Stomberg, Vice President Electric Supply AlanWelte, Generation Manager Tony Stroh, R.M. Heskett Station ManagerAppendix J.1.5 National Park Service Consultation Comments on Supplement No. 1 And Department's ResponseNPS Prelim.inary Comments onReasonable Progress Requirements for Montana Dakota Utilities CMDID R.M. HeskettStationUnit#2 May 14, 2010 Montana Dakota Utilities (MOU) operates the R. M. Heskett Station Unit 

### #2 near Mandan, North Dakota, about 160 

### kIn east ofTheodore Roosevelt National Park 

### (NP), a Class I area administered by the National Park Service

..Heskett #2 includes an .atmosphericbubbling fluidized bed boiler fired with lignite from an adjacent mine and is rated 

### at 78 

### MW output. Current emission control equipment consists ofan electrostatic precipitat 9r. Out of 3;558 Electric Generating Units.(EGUs) in EPA's·Clean 

### Air Markets (CAM) database in 2008, Heskett

### #2 ranked #713 for**S~** at 2,403 toris and #988 for NOx at 432 tons. According to modelingresults provided byMDU, emissions from ijeskett #2 cause 0,3 dv .of impairment in visibility at Theodore Roosevelt NP and 0.5 dv cumulatively when Lostwood National Wildlife·Refuge is included. Consistent with EPA guidance, the

..North Dakota Department ofHealth (NDDH) has sehicted 

### O.S dv at each Class 

### i 

## area

individually as its signifiCance level for triggering review under the Best Available Retrofit Technology (BART) program. Therefore, NDDH has detennined that Heskett #2 is not subject to BART. However, NDDH did review Heskett #2 with. respect to reasonable progress control requirements.

.

.­ Reasonable Progress. ControlTechnologyAnalysis While the "standardu

.five-step BART analysis is itot specified for analyses under the Reasonable Progress program, -it provides' a _ useful approach that is consistent and comparable to actual BART analyses.

. SulfurDioxide

­ Step 1: IdentifyAll AvallableTechnolofiies 

### -We**a~** that-NDDH has chosen a reasonable sui'te ofoptions.

Step 

### 1: EllminateTechnicallyInfeasible 9ptions We agree

### With NDDH's selectionofteelmicallyfeasible**options~** Step3: Evaluate ControlEffectiveness ofEachRemainingControlTechnology We disagree with NDDH's estimates of94% control effectiveness oflimestone injection and a**spray-dry~** with a baghouse to achieve 0.09 Ib/mmBtu.For example, NDDH has

. issued two pennits for fluidized bed boilers burning ND lignite in the past decade.

According to EPA's RACTIBACTILAER Clearinghouse (RBLC), NDDH issued a penniton 

### 9114/07to Oreat River Energy for the' I 12 MW Spiritwood Station. Thatpermit limited S02 emissions 

### to 0.06 Ib/mmBtu saying "SULFUR DIOXIDE CONTROL SYSTEM (LIMESTONE INJECTION AND SPRAY DRYER) WILLACHIEVE 98.7% REMOVAL OF POTENTIAL EMISSIONS BASED ON THE WORST CASE, 30 DAYI 

### LIGNITE. THE REMOVAL RATE WILL BE 98.8% BASED ON THE WORST CASE 24 HOUR LIGNITE."

. The RBLC also contains an entry for a pennit issued by NDDH on 

### 6/03/05 to MDU for the 220 MW Gascoyne GCQerating Station which states, "THE [98.9%] EFFICIENCY IS THE OVERALL REMOVAL EFFICIENCY OF POTENTIAL S02**EMIS~IONS** 

### (COAL-TO-STACK) USING BOTH LIMESTONE INJECTION AND A SPRAY DRYER 

### IT IS BASED ON BURNING LIGNITE THAT CONTAINS 1.0 % SULFUR (AS-RECEIVED) AND 

### TIm 30 DAY**.ROLL~G** 

### AVERAGE EMISSION RATE OF 0.038, LBIMMBTU." NDDH has presented no justification for the much lower 94% efficiency it used in

### its 

# I analysis. We also disagree with NDDH's assumption that limestone injection into the fluidized bed can achieve only 60% control andt:educe**;S~** 

### no lower than 0.364 

### Ib/mmBtu. It is 

# I generally accepted that a limestone fluidized bedboiler can inherentlyremove 90% ofthe uncontrolled

.SOa. 1 

### Applying that 90%

. reduction to the 2.15 

### Ib/mmBtu average uncontrolled emission rate provided by MOU yields a 0.215 Ib/mmBtu eIl)ission rate 

# I I

.from theboiler. 

### Step 4: Evaluate Impacts and Document Results Despite repeated advice from EPA**ag~inst** 

### using the CUECost model instead of the 

# I**'OAQP~** 

### Control Cost ManuaI (Cost Manual), MDU'and NDDH have used the CUECost 

# I mexlc:ll to estimate the costs ofthe wet scrubber andspray.-dryer options. We believe this 

# I has resulted in an. overestimationofcOsts. For example, MOD' has estimated the Total Capital Investment (TCI) for a spray-dryer 'at $37,564,351 or $4821kW. By compariSQD, 

# I the Colorado Department ofPublic Health and Environment has determined that BART for the 85 MW Martin Drake Unit #6 is a spraydryer with a TCI of$447IkW. ' 

# I
It is impossible

### froin the data provided to evaluate MDU's .estimates for operating costs. 

# i We request that MDU ·and/or NDDH provide an evaluation of operating costs in a ! 

### manner that is transparent and similar to that .presented in the CostManuaI. For example, in the evaluation ofthe· spray-dryer option, 

# we**requ~t** 

### estimates ofuse rates for solvent 

# ! I and reagent, waste generation. rate, and the,cost of electrici.ty

.associated with the I 

### scrubber. NDDH and MOD**h~ve** 

### improperly increased the operation and maintenance I 

### costs 

### by 36,%--:this is not supportedand not allowed by the Cost Manual. 

# I NODI:I.should.support and explain'its $9,815,000 estimate for· the Total Annual COst for the**spray~erlbaghouse** 

### combination.', ' 

# I I

I For example, NDDH estimated that limestone injection would achieve 88%**S~** control in its May 2007 analysis ofWestmoreland Power's Gascoyne 500 MW circulating fluidized bedboiler.
2

### Step 5: Evaluate Visibility Results It is impossible from the data provided to evaluate MOU's estimates 'of the visibility improvements resulting from the control options evaluated. 

### As noted by EPA in its May 12, 2010, letter, "

...visibility improvements are likely underestimated by your hybrid modeling system
..." NDDH should at least use the method described in the 12109 BART modelingreport. 

### Nitrogen Oxides Step 1: IdentifyAll AvaHable Technologies Weagree that NDDH has chosen a reasonable suite ofoptions. 

### Step 2: EliminateTechnically Infeasible Options We agree with NDDH's selectionoftechnically feasible options. 

### Step 3: Evaluate ControlEffectiveness ofEach Remaining ControlTechnology NDDH has assumed that SNCR can reduce NOx emissions by 33%.2 We believe that

.MDU's assumption of40% NOxreduction is more appropriate. 

### Step 4: Evaluate Impacts andDocumentResults

.We**believ~** that NDDH haS overestimated the capital cost of SNCR by comparing the $521kW cOst at HeSkett to an average3 ofcosts from other BART analyses conducted by sources trying to avoid addition of SNCR. According to the Institute of Clean Air Companies,4 "Typical SNCR capital costs (including installation) for utility applications are $5-15IkW, vendor scope, which corresponds to a maximum of$201kW ifbalance-of­ plant capital requirements are included." Itis impossible from the data provided toevaluate MOU's estimates for SNCR operating costs. We request that MDU and/or NDDH provide an evaluation ofoperating costs in a i

.manner that is transparent 

### and similarto that presented inthe CostManual.'

. 

### t ! We note that, while NDDH presented much lower Total Annual Costs based upon applying the Cost Manual approach, it provided neither its Cost Manual-based analysis nor a reason for rejecting the Cost Manual result in favor ofthe MOU cost which was 

## r , 

## • more than two times higher. 1 

## 1 .Step S: Evaluate VisibilityResults 

## i It is impossible from the data provided to evaluate MOU's estimates of the visibility

### ~ improvements resulting from the control options evaluated. 

### As noted by EPA in its May 

# I f 12, 2010, letter, "

...visibility improvements are likely underestimated by your hybrid modeling system
..." NDDH should at least use the method described in the 12109 BART modeling report.
r . 2 NDDH estimated that SNCR would achieve 40% NOxcontrol in its May 2007 analysis ofWestmoreland

Power's Gascoyne 500 MW circulating fluidized bed boiler. 3which shouldnot have included Heskett 

# I

4 May 2000White Paperon "Selective Non-Catalytic Reduction (SNCR) for Controlling NOli Emissions" 

## t 3 

# I f I.Time Necessary for Compliance

.. "The Department [NDDH] believes up to 6.5 years would be necessary for some control options (i.e., scrubbers and selective catalytic reduction)." We believe that such controls could be added much more expeditiously_ For example, Minnesota Powerhas advised the 

### MN Public Utilities commission ofthe following schedule fQr installation of a spray­ dryer, carbon injection, SCR and a baghouse at 

### its 330

### MW Boswell Unit #3. Minnesota Power's Boswell 3 Environmental Improvement Plan submitted October 27, 2006 to the Minnesota Public Utilities Commission Docket No. EOIS/M-06-1501
Pursuant to Minn. Stat. 

### §§ 216B.68SI, subd, 5, 216B.1692, the following table ts 

### tho epJann 1 ed h du e 

### 1ft' I t tion acti 

### 'f presen sc e ortmpJemen a V1 tes: Activity Timeline Phase 1 - Conceptual Engineering Target**Procurem~t** Activities

- Environm.entaI Equipment'

### Apr:i006-~ 'Target.ProcurementActivities- Turbine/Generator Oct 2006

- May 2007

.Phase 2

.. 

### FinalDesign &**Procurem~:qt**

FabricatelDeliver

.. SCR (incl. major steel and truss work) Jun 2007

.. May 2008 FabricatelDeliver

.. Fabric Filter: Apr.2008

.. May 2008 FabricatelDeliver

.. FGD System Dec 2007

- Jun 2008 FabricatelDeliver

.. Turbine/Generator Jun 2007

- Dec 2008 Phase3

.. Construction Site Preparation Apr2007

.. Jun 2007 Construction

.. SCR Jun 2007

.. Jun 2009 Construction

.. Fabric Filter Jun'2007 -May2009 Construction

.. FGD Jun 2007

- Jun 2009 Construction

.. ChimneylMonitoringEquipment Apr2009- Jun 2009 Construction

- Turbine/Generator Jan 2009

.. Nov 2009 Phase4- 

### Start-Up Checkout & Commissionfor Tuning Dec 2008

- Jun 2009 Final Plant Start-Up and Tuning Apr2009**~Sep** 2009 Results, Conclusions & Recommendations • MDU is proposing to voluntarily replace the s.and in the fluidized bed with limestone to improve 

### 802 capture·to 0.60 

### Ib/mmBtu. We.believe that this approach is capable ofmuch lower**(e.g,~** 0.20 Ib/mmBtu) 

### 802 emissfons.



### 4

### • NDDH has improperly relied upon the CUECost model to estimate costs instead ofthe OAQPS Control Cost Manual approach recommended by EPA. • NDDH should show the parameters used to estimate operating costs so that these critical evaluations are transparent and canbe evaluatedby outside parties. • NDDH has overestimated the costs of the spray-dryerlbaghouse option, and underestimated its benefits. • NDDH should base its estimates of SNCR Total Capital Investment costs upon industry data for actual installations instead ofinflated cost estimates provided by 

### MDU and other sources seeking to avoid additional controls. • NDDH presented much lower Total 

### Annual Costs based upon an application of the Cost Manual approach and should provide that analysis as well as areason for rejecting the Cost Manual result in favor ofthe 

### MDU cost which was more than 

### two times higher. • . NDDH is proposing no additional NO" reductions. We believe that a proper anal'ysis that reflects the higher control efficiency and lower costs ofSNCR may result,in significantly better cost-effecti:veness, and lead to adifferent conclusion. • NDDH should at least use the method described in the 12/09 

### BART modeling report.



### j 

# I !
j 

# I I

5

### Response to National Park Service Comments May 14,2010
Sulfur Dioxide: 1. The NPS does not agree with 94% reduction ofS02 from limestone injection and a spray dryer

.

.Response Heskett Unit 2 is an atmospheric bubbling fluidized bed boiler, not a circulating fluidized bed boiler like the Gascoyne 175 and Gascoyne 500 plants. In 

### addition, this unit was not originally designed as a bubbling fluidized bed combustor. 

### It was converted from a spreader stoker design to a bubbling bed combustor in 1986. Thus, this unit may not be able to achieve 90% reduction bylimestone injection that was proposed for the Gascoyne plants. North Dakota has one other bubbling bed combustor operating at Red Trail Energy, LLC. This boiler has not been able to achieve 90% S02 reduction with limestone injection. This boiler has both limestone injection and sodium bicarbonate injection into the flue gas (estimated at 70·90% efficiency). The two systems at this bubbling fluidized bed combustor have achieved a maximum combined S02 removal efficiency of 92.1 %. In the BACT review for Red Trail Energy, it was estimated that limestone injection and a spray dryer would reduce S02 emissions by 93% at this bubbling fluidized bed combustor. This is primarily due to a lower removal efficiency for limestone injection. The amount ofS02 removal by limestone injection plus a spray dryer at Heskett Unit 2 is not known at this time due to its retrofit status. However, the Department believes 94% is reasonable based on the uncertainties (retrofit) and the experience with Red Trail's bubbling fluidized bed combustor. The evaluated emission rate of0.055 Ib/l06 

### Btu is very similar to the Gascoyne 500 value of0.06 Ib/l06 

### Btu for a spray dryer plus limestone injection. Regarding limestone injection, the additional 60% S02 reduction by limestone injected into the combustor equates to 82% overall reduction within the combustor. Based on our experience with Red Trail and the fact that Heskett Unit 2 was not originally designed as abubbling fluidized bed unit, we believe 82% is reasonable. 2. NOOH has used the CUE Cost Model to generate costs for wet scrubber and spray dryer instead on the Control Cost Manual. Response The commenter is incorrect in this statement. The costs that were used in this evaluation for a spray and wet scrubber were provided by MOU. The NDDH only used the CUE Cost model to verify MOU's cost estimates. MOU provided a site specific cost estimate for the wet scrubber and spray dryer using the Control Cost Manual procedures. Additional information has been provided to show the specifics ofeach cost estimate.

### The NPS points out that the Colorado Department ofPublic Health estimated the cost of a spray dryer at Martin Drake Unit #6 at 

### $4471kw compared to 

### $4821kw at Heskett Unit 2. This is a 7.8% difference in the cost ofthe spray dryer. Site specific factors can easily account for this amount of difference. In 

### addition, the estimate for controls for Reasonable Progress, as well as BART., only have to have a ±30% accuracy. The estimate provided by MDU is well within this range when compared to the estimate for Martin Drake Unit #6. 3. The NDDH should support and explain its $9,815,000 estimate for the Total Annual Cost for the spray dryerlbaghouse combination. Response The cost for the spray dryerlbaghouse was provided by MDU and adjusted to 2009 dollars. MDU Used the Control Cost Manual procedures for estimating the cost. Details ofthe analysis have been included in the supplement. 4. As noted by EPA in its May 12, 2010, letter "

...visibility improvements are likely underestimated by your hybrid modeling system; NDDH should use the modeling method described in the 12/09 

### BART Modeling report." Response States in the west are relying on WRAP's modeling to establish Regional Haze visibility improvement progress much like we suspect EPA will for their own purposes in preparing the Montana Regional Haze SIP. As shown in Table 8.11 of our Regional Haze SIP, the Department's hybrid modeling approach predicts significantly greater improvement in visibility for the BART controls compared to WRAP's modeling. This was expected, given the more,realistic treatment of point source plumes by Calpuff compared to WRAP's grid modeling. Therefore, it appears inconsistent for EPA, or the NPS, to argue that the Department's hybrid modeling system is underestimating visibility improvement, while accepting WRAP's modeling of visibility improvement for other states. The Department has included in Section 8.6 ofour Regional Haze SIP submittal a Performance Evaluation of the hybrid modeling system. The results show very good agreement between modeled concentrations and observed concentrations at the 98th 

### percentile, 90th 

### percentile, average ofthe 20% worst days and annual average. The comment also suggests that the modeling results should include the 98th 

### percentile results. We believe including the 98th 

### percentile results is contrary to rule and EPA guidance on this issue. In 

### 40 CFR 51.308(d) it states "The reasonable progress goals must provide for an improvement in visibility for the most impaired days over the period ofthe implementation plan and ensure no degradation in visibility for the least impaired days over the same period." 40 CFR 51.301 states ''most impaired days means the average visibility impairment (measured in deciviews) for the twenty percent of monitored days'in a calendar year with the highest amount of visibility impairment." Least impaired days means the average visibility impairment (measured in deciviews ) for the twenty percent ofmonitored days in a calendar year with the lowest amount of visibility impairment.
2

### The Department is not aware of any EPA guidance that indicates the 98th 

### percentile visibility results should be used. To the contrary, in EPA's document "Additional Regional Haze Questions" August 3, 2006, this issue is addressed. In the response to Question I under the Reasonable Progress section 

### it states· "Unlike the technical demonstration for CAIR or BART, the reasonable progress demonstration involves a test ofa strategy. The strategy includes a suite ofcontrols that has been identified through the identification of pollutants and source categories of pollutants for visibility impairment

- the possible controls for these pollutants (and their precursors) and source categories

- the application offour statutory factors and how much progress is 

### made with a potential strategy with respect to the glide path. Modeling occurs with a strategy and is not a source-specific demonstration like the BART assessment. [emphasis added] The response to Question 2 in the "Additional Regional haze Questions" document, it is stated "Reasonable progress is not required to be demonstrated on a source-by-source basis. It 

### is demonstrated based on a control strategy developed from a suite ofcontrols that has been assessed with the four statutory factors and the uniform rate of progress. [emphasis added] It 

### is clear to the Department that a BART type assessment (Le. 98th 

### percentile) is not required. In fact, an assessment ofindividual sources is not required. The Response to both Question 1and 2 indicates any modeling should be assessed against the uniform rate ofprogress (glidepath). Section 2.2 of"Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program", the uniform rate of progress, or glidepath, is determined for the average ofthe 20% worst days and 20% best days. The Department has provided both the individual modeling results for sources and the cumulative modeling results for a control strategy for the group ofsources that were left after the initial evaluation process was completed (see Section 9.5.1 ofthe RH SIP). We interpret the EPA guidance on Reasonable Progress to indicate that results for individual sources are not required. Therefore, any results presented would not have to include the 98th 

### percentile values and should be compared to the average ofthe 20% worst days. Nitrogen Oxides 1. We believe that NDDH has overestimated the capital cost ofSNCR. Response The cost for SNCR that was used in the analysis was provided by MDU (adjusted to 2009 dollars). The Department verified the cost by comparing MDU's estimate to other similar sized facilities. MDU's estimate was near the middle of the range of costs evaluated. MDU's estimate is a site specific estimate for a combustion unit that was retrofitted to be a fluidized bubbling bed combustor. The details of the estimate have been included in the supplement. The NDDH believes the estimate is within the ±30% accuracy required for this analysis and more accurate since it is site specific.

3The annual operating cost was $1,041,000 per year (2009 dollars) or $13.36Ikw. This is nearly identical to the SNCR annual operating cost at M.R. Young Station Unit 1 of $13.44Ikw (2006 dollars) and $14.061kw (2006 dollars) at Stanton Unit 1. The operators ofM.R. Young Station have not tried to avoid putting on SNCR. In fact, it may bejust the opposite. The Stanton Unit·l estimate was made using EPA's Control Cost Manual. The NDDH believes the MDU estimate is within the ±30% accuracy required for this analysis. 2. Visibility modeling should use the method described inthe 

### 12/09 BART modeling report. Response See response to Comment4 under the sulfur dioxide section. Time Necessary for Compliance The NPS believes controls can be added more expeditiously. Response The Department provided a time necessary for installing the top control technologies that were considered cost effective. The amount oftime will be affected by an available work force and scheduled outages. Several sources have begun working on BART controls early because of concerns about product and work force availability. We believe the amount of time is reasonable for a source subject to the Reasonable Progress requirements. Results, Conclusions and Recommendations 1. The voluntary control oflimestone injection can achieve a lower S02 emission rate than 0.60 Ib/106 Btu. Response The NDDH has determined that no additional controls are required under the Reasonable Progress portion of the Regional Haze rules. The addition of limestone is somewhat voluntary by MDU. The 0.60 Ib/l06 Btu emission rate is the rate that MDU is comfortable that the particulate matter emission limits can be met using an electrostatic precipitator. An optimization study will be conducted to determine if a greater sulfur dioxide removal efficiency can 

### be achieved. Ifit can, the proposed permit requires the lower emission rate (greater removal efficiency). 2. NDDH should not rely on the CUE Cost model. Response See response to Comments 2 and 3 in sulfur dioxide section and Comment 1 of the nitrogen oxides section.



### 4

### 3. NDDH should show the parameters used to estimate costs. Response The beginning ofthe supplement discusses the source characteristics, capacity, baseline emission rates, estimated control efficiencies, etc. The inlet sulfur content is shown in the excerpts from MDU's draft 

### BART analysis. All the infonnation needed to estimate the operating cost, and the capital cost, is available. 4. NDDH has overestimated the cost ofspray dryerlbaghouse option. Response See response to Comments I and 2 in the sulfur dioxide section. 5. NDDH should base its estimates on SNCR Total Capital Investment Costs on industry data instead ofinflated estimates by sources seeking to avoid controls. Response The Department 

### has made a comparison of MDU's estimated capital and annualized costs to other estimates in BART analyses. This comparison showed very good agreement with the average of all units. The annualized cost agrees very well with estimates for the M.R. Young Station and Leland Olds Station on a dollar-per-kilowatt basis. The NPS has been using the out-of-date EPA Control Cost Manual to estimate costs. The NDDH believes the site specific estimate for Heskett Unit 2 is reasonable based on the estimates provided for other facilities. 6. NDDH should provide reasons for rejecting the Cost Control Manual results in favor of the MDU results. Response See response to Comment 6 of this section and page 3 of the Supplementary Cost Infonnation. 

# I

,**~** 

### 7. NPS believes aproper NOx 

### cost analysis will lead to a different conclusion about costs. I 

### Response The NDDH believes the site-specific cost estimate provided MDU is sufficiently accurate 

# I
for the Reasonable Progress analysis (see Response to Comment I, Nitrogen Oxides 

# I section and Comments 2, 5 and 6 ofthis section). The amount ofvisibility improvement in the most impaired days for the application ofSNCR will be less than 0.009 deciviews (estimated at 0.001 deciviews). This amount ofvisibility improvement is negligible. As stated in EPA's Guidance for Settling Reasonable Progress Goals under the Regional Haze Program (June I, 2007), the NDDH has the right to include other relevant factors in 

# I
its decision on reasonable progress. The cost ofSNCR on a dollar-per-ton and dollar-per­ deciview basis is excessive. The negligible amount of visibility improvement and the cost clearly indicates SNCR is not reasonable.

58. NDDH should use the BART modeling methodology. Response See response to Comment 4 in the Sulfur Dioxide section.

6Appendix 1.3.3 U.S. Environmental Protection Agency Comments on Supplement No. 1 And Department's Response

### ENCLOSUREl EPARegion 8 Preliminary Comments on March 

### 8.2010 DraftRegional Haze SIP SupplementNumber 

### 1 (ELM Consultation Version)
General Comment 

### • As noted in our January 8, 2010 comment letterfor Antelope Valley Station and Coyote Station, based on your analysis, there appearto be available controls for Heskett Station Unit 2 under Reasonable Progress that carry similarcosts to those found reasonable under BART. Given that the potential visibility improvements are likely underestimated by yourhybridmodeling system, the analysis does not support your conclusions that it is not reasonable to 

### impose these controls at this**tim~.** 

### For further guidance, please referto the Regional Haze Rule (64 FR 35732, July I, 

### 1999). Detailed Comments SIP Text:·



### . 1. Reasonable Progress Goals

- Required Controls for Point Sources and Table 9.9, Visibility Improvement and Cost Effectiveness: North Dakota Department ofHealth (NDDH) has chosen to heavily rely on visibility

. improvement to 

### reject Reasonable Progress controls for Heskett Station Unit 2 and other

facilities on a unit-by-unit basis. However, visibility improvement is not one ofthe four Reasonable Progress statutory factors (cost.ofcompliance, time necessary for compliance, energy/non-air quality environmental impacts ofcompliance, and remaining useful life of any potentially affected sources). While we think·the State has the flexibility to 

### consider visibility improvement for individual unit controls in Its decision-making, we have concerns with the State's methodology. When considering visibility improvement associated with controls at individual units, we consider it importarlt to include the 98th 

### percentile day results in addition to 

### the 20% worst days' results. Looking only at the 20% worst days dilutes the beneficial impacts of individual unit controls. We recognize that partofthe focus in setting the reasonable progress goals vis-a-vis the uniform rate ofprogress i$ onthe 20% worst days, butthe uniformrate ofprogress and the reasonable progress goalS represent cumulative impacts and reductions across a range ofsources and source categories. In that context, a cumulative regional scale deciview improvement value may have adifferent meaning because it is compared to 

### a valueneeded to reach the uniform rate ofprogress. For example, while a deciview improvement of0.1 deciview might not seem significantin an absolute sense, it may be significant iftotal deciview improvement needed to reach the unifonn rate ofprogress is 1or 2 deciviews. For evaluating individual unit visibility

. impacts, the BART approach represents the more reasonable model because it is specifically geared to consideration ofunit-by-unit impacts. In our view, since the 98th 

### percentile day results are used in determining BART, they should also be used in - 1 ­

### determining Reasonable Progress controls for individual units. Also, arelatively low visibility benefit for controlling an individual unit should not be a major factor when selecting Reasonable Progress measures; given the ultiritate purpose ofthe Regional Haze program, cumulative effects across sources need to be considered. Heskett Station and other.powerplants are some of the 

### larger emittersin.the State and controls are available atreasonable cost effectiveness levels. 2. 

### Table 9.8, Control Options Cost:

. Table 9.8 requires some clarification. The statement in the middle ofthe table with an

asterisk is unclear and could perhaps be 

### deleted. Regarding footnote b, as

### the State used the Montana-DakotaUtilities Company (MDU) estimate, the references to Leland Olds and M.R. Young should be removed to 

### eliminate confusion. NDDH references information related to the PGE Boardmanplant. EPA Region 10 

### has 

### not determined that these analyses are reasonable. Furthermore, in general we do not recommend relying on the 'CUECost model. This·was the·'model that MDUpriinarily used to estimate the costs that you referto in your analyses. According to the BART Guidelines, in order to 

### maintain and improve consistency, costestimates should be based on the OAQPS Control Cost Manual where po·ssible (70 

### FR 39166, 

### July 6, 2005). 3. 

### Section 10.6.1.3, 

### R.M. Heskett Station Unit 

### 2: It

### appears that MDU andNDDH believe at least this minimal level ofcontrol is reasonable now. As such, it should be included as 

### a required Reasonable Progress control inthe SIP. NDDH notes that MDU has committed to increase S02 removal efficiency to aminimum of70%

### in this planning period. We note that in aJune 9, 2006 

### letter from MDU to Terry O'Clair, MDU commits to "control S02 emissions by installing and ' operating the necessary equipment to use limestone as 

### the bed material in the boiler." Is this still the intended teohnical approach for limestone injection? We suggest language be included in the SIP text to clarify theintended technical approach for limestone injection. In addition, the proposed 0.60 

### IblMMBtu emission limit is problematic; as 

### discussed in comment 5below, amore stringent limit is appropriate and reflects optimal use ofthe control technology. NDDH Proposed Permitto Construct

- Heskett Station: 

### 4. Based on your discussions with MDU, it appears that this level ofminimal control is considered reasonable at this time. Therefore, even ifyou disagree with our other comments regarding Reasonable Progress, at least this level ofS02 control should be included in the SIP as 

### arequired Reasonable Progress control measure. As 

### such, the permit should more closely mirror the BARTpenmt format, including the appropriate 3O-dayrolling average emission limit and compliance detennination, monitoring, recordkeeping, and reporting requirements. 5. Basedon ourreview ofthe control efficiency and emission rate specified in theproposed permit, the emission limit should calculate out to 0.38 

### IblMMBtu, not 0.60 

### IblMMBtu. The permit control efficiency of70% 

### removal is on a basis ofS(hequivalent to the boiler inlet, while the 60% 

### control efficiency that appears in SupplementNo. 1is on the basis of -2­

### uncontrolled S02 in the exhaust stream. Considering that your analysis and cost estimates are based on the latter, the permit limits should be revised to be consistent with the findings in the analysis. According to the Clean Air 

### Markets Division database, the:highest uncontrolled emission rate (exhaust) at Heskett Station Unit 2 

### in the past ten years was 0.951blMMBtu. At 60% control this equates to a 0.381b1MMBtu limit. In comparison, we find the 0.60 IblMMBtu specified in the proposed permitrepresents an excessive margin of compliance, at only about 37% control. We would expect that the proposed permit specify an initial limitin the vicinity ofO.38IblMMBtu. IfNDDHhas reason to believe a lower limit might not be achievable, the permit could include aprovision to adjust the limit upward, pending review ofstack test results. In order to adjust the permit limit later, a SIP revision would be required. An optimization study that is not defined in the permit and is subject only to NDDH approval (not EPA approval) does not ensure, in terms offederal enforceability,-thatthe so1.irCe will ultimately be subject to an emission limit in IblMMBtu that corresponds to at leaSt 60% control. IfNDDH wants to require an optimization study to determine ifcontrols can do better than 0.38 IblMMBtu and 60% control, we would have no issue with that.

- 3 ­ENVIRONMENTAL HEALTH SECTION Gold Seal Center, 918 E. Divide Ave. 

### NORTH DAKOTA Bismarck, NO 58501-1947 DEPARTMENTofHEALTH 701.328.5200 (fax) www.ndhealth.gov

May 27, 2010

Ms. Callie Videtich Director, Air Program U.S. EPA, Region 8 1595 Wynkoop Street Denver, CO 80202-1129 Re: Comments on RH SIP Supplement No. 1 DearMs. Videtich: This letter is in response to comments that your staffprovided on the Department's Supplement No. 1 to the North Dakota State Implementation Plan for Regional Haze. With respect to the comments, our responses are as follows: General Comment As noted in our January 

### 8, 2010 comment letterforAntelope Valley Station and Coyote Station, based on your analysis, there appear to be available controlsfor Heskett Station Unit 2 under Reasonable Progress thai carry similar costs to thosefound reasonable under BART. Given that thepotential visibility improvements are likely underestimated byyour hybrid modeling system, the analysis does not supportyour conclusions that it is not reasonable to impose these controls at this time. For further guidance, please refer to the Regional Haze Rule (64 FR 35732, July I, 1999).

. Response: The only controls at Heskett Station Unit 2 that have costs on a dollar-per-ton basis that are similar to required BART controls are limestone injection for sulfur dioxide control and staged combustion for nitrogen oxides controls. Limestone injection has a cost of more than $116.7 million per deciview and staged combustion has a cost greater than $40.7 million per deciview. 

# I These costs are considered excessive. EPA Guidance (Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program; June 1, 2007) states "therefore, in assessing additional 

# i emissions reduction strategies for source categories orindividual, large scale sources, simple cost effectiveness estimates based on a dollar-per-ton calculation may not be as meaningful as a 

# I

Environmental HeaM Division of Division of Division of Division of Section Chiefs Office AlrQuality Municipal Facilities Waste Management WaterQuality 701.328.5150 701.328.5188 701.328.5211 701.328.5166 701.328.5210 Printedon recycledpaper.

### Ms. Videtich 2 

### May 27, 2010 dollar-per-deciview calcu.Iation". Clearly, cost on a dollar-per-deciview basis is one ofthe four statutory factors that must 

### be evaluated. We have evaluated all four statutory factors. The EPA Guidelines, Section 5.0, states**"Howeve~.,** 

### you have flexibility in how to take into consideration these statutory factors and any other factors that you have determined to be relevant." Since the purpose ofthe Regional Haze rules is to improve visibility in the Federal Class I areas, the Department has determined that actual visibility improvement by a reduction strategy for a source category, or source, is a relevant factor. The maximum improvement for the most impaired days is 0.009 deciviews when sulfur dioxide emissions from Heskett Station Unit 2 are reduced by 95% and nitrogen oxides by 40%. Any control alternative that reduces emissions by a smaller amoUnt would have even less impact on visibility impairment. The 0.009 deciview improvement represents 0.05% improvement at Theodore Roosevelt National Park and Lostwood WildemessArea. This amount ofvisibility improvement is negligible and does not warrant additional controls. The comment also states "Given that the potential visibility improvements are likely underestimated by your hybrid modeling system, the analysis does not support your conclusions that it is not reasonable to impose these controls at this time." States in the west are relying on WRAP's modeling to establish Regional Haze visibility improvement progress much like we suspect EPA will for their own purposes in preparing the Montana Regional Haze SIP. As shown in Table 8.11 of our Regional Haze SIP, the Department's hybrid modeling approach predicts significantly greater·improvement in visibility for the BART controls compared to WRAP's modeling. This was expected, given the more realistic treatment of point source plumes by Calpuffcompared to WRAP's grid modeling. Therefore, it appears inconsistent for EPA to argue that the Department's hybrid modeling system is underestimating visibility improvement, while accepting WRAP.'s modeling ofvisibility improvement for other states. The Department has included in Section 8.6 ofour Regional Haze SIP submittal a Performance Evaluation of the hybrid modeling system. The results show very good agreement between modeled concentrations and observed concentrations for the 98th 

### percentile, 90th 

### percentile, average of the 20% worst days and the annual average. EPA has provided no basis for your statement that our hybrid modeling system is likely underestimating the amount of visibility improvement! Based on the excessive cost and virtually no visibility improvement from additional air pollution controls, we have determined that no additional controls are reasonable at this time. 

### SIP Test 1. Reasonable Progress Goals

- Required Controlsfor Point Source and Table 

### 9.9, Visibility Improvement andCost Effoctiveness: North Dakota Department ofHealth (NDDH) has chosen to heavily rely on visibility improvement to reject Reasonable Progress controlsfor Heskett Station Unit 2 

### and other facilities on a unit-by-unit basis. However, Visibility improvement is not one ofthefour Reasonable Progress statutoryfactors (cost ofcompliance, time necessaryfor compliance,

### Ms. Videtich 

### 3 May 27, 2010 energy/non-air quality environmental impacts ofcompliance, and remaining useful life of any potentially affected sources). While we think the State has theflexibility to consider visibility improvement for individual unit controls in its decision-making, we have c(}ncerns .with the State's methodology. When considering visibility improvement associated with controls at individual units, we . consider it important to include the 

### 9l1hpercentile 4ay results in addition to the 20% worst days'results. Lookingonly aithe 20% worstdaJ's dilutes the beneficial impacts of individual unit controls. We recognize thatpart of thefocus in setting the reasonableprogress goals vis-II-vis the uniform rate of progress is on the 20% worst days, but the uniform rate of progress and the reasonable progress goals represent cumulative impacts and reductions across a range of sources andsource categories. In that context, a cumulative regional scale deciview improvementvalue may have a different meaning because it is comparedto a value neededto reach the uniform rate of progress. For example, while a deciview improvement of 0.1 deciview might not seem significant in an absolute sense, it may be significant if total deciview improvement needed to reach the uniform rate of progress is 

### 1 or 

### 2 deciviews. For evaluating individual unit visibility impacts, the BART approach represents the more reasonable model because it is specifically geared to consideration ofunit-by-unit impacts. In our view, since the 

### 98'hpercentile day results are used in determining BART, they should also be used in determining Reasonable Progress controlsfor individual units. Also, a relatively low visibility benefit for controlling an individual unit shouldnot be a major factor

. when selecting Reasonable Progress measures; given the ultimatepurpose ofthe Regional

Haze program, cumulative effects across sources needto be considered Heskett Station and otherpowerplants are some of the larger emitters in the State andcontrols are available at reasonable cost effectiveness levels. 

### Response: As stated in the response to the General Comment, the Department evaluated the cost on a dollar-per-ton and dollar-per-deciview basis (statutory factor). The Department also used its allowed discretion in evaluating the amount of actual visibUity improvement (deciviews)

.

.After having considered all four statutory factors, and other relevant factors as allowed by EPA guidance, the Department has concluded that no additional controls are warranted. This decision was not based solely· on the amount of visibility improvement as you have

. suggested.

The comment also suggests that the modeling results should include the 98th 

### percentile results. We believe including the 98th 

### percentile results is contrary to rule and EPA guidance on this issue. In 40 CFR 51.308(d) it states "The reasonable progress goals must provide for an improvement in visibility for the most impaired days over the period of the implementation plan and ensure no degradation in visibility for the least impaired days over the same period." 40 CFR 51.301 states "most impaired days means the average visibility impainnent (measured in deciviews) for the twenty percent ofmonitored days in a calendar year 

### with the highest amount of visibility impainnent." Least impaired days means the average visibility impainnent (measured in deciviews) for the twenty percent ofmonitored days in a calendar year with the lowest amount ofvisibility impainnent.

### Ms. Videtich 4 May 27, 2010

The Department is not aware ofany EPA guidance that indicates the 98th 

### percentile visibility results should be used. To the contrary, in EPA's document "Additional Regional Haze Questions" August 3, 2006, this issue is addressed. 

### In the response to Question 1 under the Reasonable Progress section it states "Unlike the technical demonstration for CAIR or BART, the reasonable progress demonstration involves a test of a strategy. The strategy includes a suite of controls that has been identified through the identification ofpollutants and source categories ofpollutants for visibility impairment - the possible controls for these pollutants (and their precursors) and source categories

- the application offour statutory lacton and how much progress is made with a potential strategy with respect to the glide path. Modeling occurs with a strategy and is not a source-specific demonstration

.like the BART assessment. [Emphasis added] In response to Question 2, it is stated "Reasonable progress is not required to be demonstrated based on a source-by-source basis. It is demonstrated based on a control strategy developed from a suite ofcontrols that has been assessed with the four statutory factors and theuniform rate ofprogress. [Emphasis added] It

### is clearto the Department that a BART type assessment (i.e 98th 

### percentile) is not required. In fact, an assessment ofindividual sources is not required. The Response to both Question I and 2 indicates any modeling should be assessed against the uniform rate of progress (gJidepath). In Section 2.2 of "Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program", the uniform rate of progress, or glidepath, is determined for the average ofthe 20% worst days or20% best days. The Department has provided both the individual modeling results for sources and the cumulative modeling results for a control strategy for the group ofsources that were left after the initial evaluation process 

### was completed (see Section 9.5.1 ofthe RH SIP). We interpret the EPA guidance on Reasonable Progress to indicate that results for individual sources is not required. Therefore, any results presented would not have to include the 98th 

### percentile values and should be compared to the average ofthe 20% worst days. With regard to cost, you claim that some ofthe controls are available at a reasonable cost. However, EPA has provided no guidance on cost effectiveness on either a dollar-per-ton, or more importantly, a dollar-per-deciview basis. As you have pointed out, other relevant factors may be considered in our decision regarding controls for Reasonable Progress. We believe the lack ofvisibility improvement by the addition ofcontrols is extremely relevant. 

### 2. Table 9.8, Control Options Cost: Table 9.8 requires some clarification. The statement in the middle ofthe table with an asterisk is unclear andcouldperhaps be deleted. Regardingfootnote b, as the State usedthe Montana-Dakota Utilities Company (MDU) estimate, the references to Leland

### aids andMR. Young should be removed to eliminate confusion. NDDH references information related to the PGE Boardman plant. EPA Region 10 has not determined that these analyses are reasonable. Furthermore, in general we do notrecommendrelying on the CUE Cost model.

### Ms. Videtich 5 

### May 27, 2010


### This was the model that MDUprimarily used to estimate the costs thatyou refer to in your analyses. According to the BARTGuidelines, in order to maintain and improve consistency, cost estimates should be based on the OAQPS Control Cost Manual wherepossible (10 

### FR 39J 

### 66, July 

### 6, 2005). Response: 

### The statement in the middle ofthe table and footnote b will be removed. Regarding the CUE Cost Model, the Department only. used it to determine the cost of controls for Heskett Unit 2 for the purpose of checking' MDU's estimate. Based on our testing ofthe CUE Cost Model for SNCR versus the Control Cost Manual, it appears they provide similar results. All costs were provided by MDU or extrapolated from 

### other BART analyses. MOU used the Control Cost Manual Procedures to develop their cost estimate. Additional information has been included which provides the details of MDU's cost estimates. The Department has also reviewed the estimated cost ofthe baghouse and compared it to the cost at Stanton Unit 1 and the Gascoyne 175 plant. The annualized cost for Stanton Unit 1 was $25.921kw (2007 dollars) and $15.34Ikw (2004 dollars) at Gascoyne 175. The annualized cost at Heskett Unit 2 is $ 16.661kw 

### (2009 dollars). Both the Stanton Unit 1 and Gascoyne 175 estimates were prepared using the procedures of the Control Cost Manual. We beJieve the estimate is accurate. The CUE Cost Model is easierto use and is provided by EPA. It 

### appears to provide reliable results. 3. 

### Section 10.6.1.3, 

### R.M HeskettStation Unit 2: It appears that MDU and NDDH believe at least this minimal level ofcontrol is reasonable now. As such, it should be included as a required Reasonable Progress control in the SIP. NDDH notes that MDU has committed to increase S01 removal efficiency to a minimum of70% 

### in this planningperiod We note that in June 

### 9, 2006 

### letter from MDUto Terry

# a 'Clair, MDUcommits to "control S01 emissions by installing and operating the necessary equipment to use limestone as the bed material in the boiler." Is this still the intendedtechnical approachfor limestone injection? We suggest language be included in the SIP text to clarify the intended technical approach for limestone injection. In addition, the proposed 0.60 

### IblMMBtu emission limit is problematic; as discussed in comment 

### 5 below, a more stringent limit is appropriate and reflects optimal use of the control technology. Response: 

### The Department has determined that additional controls at Heskett Unit 2 are not reasonable at this time. The S02 reductions that will be achieved are an agreement between the Department and MDU and are not required by the Regional Haze rules.

### Ms. Videtich 

### 6 May 27, 2010
The technical approach is still to use limestone in the bed ofHeskett Unit 2 to achieve reductions fr-om their current sulfur dioxide emission rate. Section 10.6.1.3 already indicates that limestone will be injected into the boilers. Whether the limestone will replace all of the bed material is unknown at this time. We believe Section 10.6.1.4 covers this issue. NDDHProposedPermit to Construct

- HeskettStation 4. Based on your discussions with MDu, it appears that this level ofminimal control is considered reasonable at this time. Therefore, even 

### ifyou disagree with our other comments regarding Reasonable Progress, at least the level of S02 control should be included in the SIP as required Reasonable Progress control measure. As such, the permit should more closely mirror the BARTpermitformat, including the appropriate 30-day rolling average emission limit and compliance determination, monitoring, recordkeeping, andreporting requirements. Response: Since we have detennined that no additional controls are required under Reasonable Progress, we believe it is inappropriate to include the reductions that will be achieved at Heskett Station Unit 2 under that portion ofthe SIP. We have included the reductions in 10.6.1, Emission Reductions Due to Ongoing Air Pollution Control Programs. Because of our findings on the Reasonable Progress analyses and the somewhat voluntary nature of the reductions, we believe the discussion of the Heskett Unit 2 reductions is more appropriately included in this section. For the same reasons, we believe the Permit to Construct should afford MDU some flexibility in meeting the emission limits. 5. Basedon our review of the control efficiency andemission rate specified in theproposed permit, the emission limit should calculate out to 0.38 IblMMBtu, not 0.60 IbIMMBtu. Thepermitcontrol efficiency of 70% removal is on a basis ofS02equivalent.to the boiler inlet, while the 60% control efficienCy that appears in Supplement No. J

### is on the basis of uncontrolled SO} in the exhaust stream. Considering that your analysis and cost estimates are basedon the latter, thepermit limits should be revised to be consistent with thefindings in the analysis. According to the Clean AirMarkets Division database, the highest uncontrolledemission rate (exhaust) at Heskett Station Unit 2 

### in the past ten years was 0.95 IbIMMBtu. AT 60% control this equates to a 0.381b1MMBtu limit. In comparison, wefind the 0.50 IblMMBtu specified in the proposed permit represents an excessive margin of compliance, at only about 37% 

### control. We would expect that the proposed permit specify an initial limit in'the vicinity ofO.38IbIMMBtu. 

## If NDDHhas reason to believe a lower limit might not be achievable, the permit could include a provision to adjust the limit upward, pending review of stack test results. In order to adjust the permit limit later, a SIP revision would be required An optimization study that is not defined in the permit and is subject only to NDDH approval (not EPA approval) does not ensure, in terms of federal enforceability, that the source will ultimately be subject to an emissionMs. Videtich 

# f 7 May 27, 2010


### limit in IblMMBtu that corresponds to at least 60% control. 

## If NDDH wants to require an optimization study to determine 

### if controls can do better than 0.38JblMMBtu and60% control, we wouldhave no issue with that. Response: The 70% reduction of potential S02 emissions is the rate that MDU believes can 

### be achieved while still maintaining compliance with their particulate matter emission limit.' Since Heskett Unit 2 is equipped with an electrostatic precipitator, not a baghouse, the Department believes an increase in particulate matter emissions is a concern. This is one ofthe reasons for the optimization,study. In addition, the amount of**~02** reduction from limestone injection at a retrofitted bubbling fluidized bed combustor is unknown. Our experience with Red Trail Energy's bubbling fluidized bed combustor indicates that the 80-90% removal rate at circulating fluidized bed combustion units may not be achievable at some bubbling fluidized bed units. The Reasonable Progress analysis indicates a 60% reduction from the current actual emissions. This equates to an 82% reduction of the potential-to-emit. The agreement (included in the Permit to Construct) only requires an overall removal efficiency of70% from the potential-to-emit. The agreement with MDU will reduce current emissions by about 34% (see Section 10.6.1.3). Using a baseline of 0.91 

### Ib/l06 Btu, this equates to 0.60 

### Ib/l06 Btu. Based on an annual average sulfur content of0.71% and a heat content of 7100 Btu/lb, the potential-to-emit is 2.0 Ibll06 Btu. Thirty percent of the sulfur reaching the inlet ofthe boiler (70% reduction ofthe inlet sulfur content) equates to 0.60 

### Ib/l06 Btu. The Department cannot guarantee that emissions will be any lower than 0.60 

### Ib/10 6 Btu after the optimization study is completed. Ifa lower rate can be achieved, the Permit to Construct requires the lower rate. Ifyou have any questions, pJease contact Tom Bachman ofmy staffat (701)328-5188.

# r?~~ Terry L. O'Clair, P.E. Director Division ofAir Quality TLOITB:csc xc: Abby Krebsbach, MDU