# Minnkota Power**~Pg** 

### COOPERATIVE, INC.

1822 Mill Road· P.O. Box 13200 • Grand Forks, NO 58208·3200 • Phone (701) 795-4000 

### December 11, 2009

Terry O'Clair, P.E. Director Division ofAir Quality 918 E Divide Ave, 2nd 

### FI Bismarck, ND 58501-1947
Subject: BACT Cost Estimate

Dear Mr. O'Clair, YourTouchstone Energy" Partner 

# -

This letter is in response to the Department's letter, subject as above, dated Nov. 25, 2009. Enclosed, please find Minnkota's response to this request for additional information. Should you have any questions concerning the submitted information, please contact me at 701-795-4221.
Sincerely, 1.Nt-iIKCZPrA POW COOPERATIVE, INC

.



# .**A~** John T. raves, P.E. Environmental Manager C: David Sogard

### MINNKOTA POWER COOPERATIVE, Inc. and SQUARE BUTTE ELECTRIC COOPERATIVE
RESPONSES TO NDDH REQUEST NOx BACT ANALYSIS STUDY MILTON R. YOUNG STATION UNIT 1 and UNIT 2 REGARDING SCRECONOMIC FEASIBILITY
December 11, 2009

North DakotaDepartment ofHealth's Environmental Health Section, Division ofAir Quality has requested1 

### thatMinnkotaPower Cooperative Inc. ("Minnkota" or "MPC") provide more detailed and comprehensive costdata following theirreviews ofthe BestAvailable Control Technology (BACT) Analysis Study

- Supplementalreports2 

### submitted on November 12, 2009 for control of nitrogen oxides (NOx) emissions from existing Unit 1 and Unit 2 atMilton R. Young Station ("MRYS"). A detailedbreakdown ofcapital costs and operation and maintenance costs for hypothetical applications oflow-dust and tail end SCR alternatives, assuming that they are technically feasible to apply atMRYS as NDDH has recently advised3

, 

### are attached. Responses to the use ofsteam from the mainboilers for reheat ofthe flue gas are provided. A comparison ofcontrol costs from relevantrecent BACT Determinations versus the estimated control costs of hypothetical applications oflow-dust and tail end SCRtechnologies atMRYS includedwith the November2009 Supplemental Reports is also provided.

Burns & McDonnell (B&McD) was retainedby MPC as an independentconsultantto perform the referencedNOx BACT Analysis Stud y4 

### ofMinnkota's Unit 1 and Square Butte Electric Cooperative's Unit 2 atthe Milton R. Young Station (MRYS) in accordance with the requirements ofaConsentDecree (CD)5. TheNovember 2009 NOx BACT Analysis Study Supplemental Reports were generated inresponse to the NDDH's request6 

### to see Steps 3 and

1 See Reference number 1, November 25,2009. 2 See Reference number 2, November 12, 2009. 3 See Reference number 3, July 15,2009. SCRtechnology is consideredtechnically infeasibleby Minnkota for application atMRYS perthe October2006 NOx BACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, DOJ, and otherparties, including the November 2009 Supplemental NOxBACT Analysis Study reports. 4 See Reference number4, October 2006. 5 See Reference number 5, April 24, 2006. 6 Ibid Reference number 3, July 15,2009. SCRtechnology is consideredtechnically infeasible byMinnkotafor application atMRYS perthe October2006 NOxBACT Analysis Study report and subsequent submittals in response to commentsby the NDDH, EPA, DOJ, and otherparties, including theNovember2009 Supplemental NOx BACTAnalysis Studyreports.



### 1

### 4 ofthe BACT analysis process7

### be perfonned and include low-dust and tail end SCR alternatives.

Detailed NOx BACT Analysis Study Supplemental reports' Capital and Operating & 

### Maintenance CostSummary:
NDDH Request: "A detailed breakdown ofcapital costs and operation and maintenance costs for the bulleteditems onpage 4-16 shouldbe provided.,,8

BMcD Response: The referenced "bulleted items on page 4-16" ofthe November 2009 NOx BACT Analysis Study Supplemental reports are intendedto representthe major components (physical assets) thatwere identified as being required to install and operate low-dust and tail end SCRs ifthey were consideredtechnically feasible for application atMRYS. Preliminary SCRCostEstimates used

as inputs to the November 2009 NOx BACT Analysis Study Supplemental Reports were not developed basedupon a directmatch to each ofthe bulleted items includedin the reports. Thus it is notpossible to provide a costbreakdown inthat fonnat. In lieu ofa breakoutdirectly corresponding to the bulleted items, Bums & 

### McDonnell has modified ourcost estimate spreadsheets for the four "shared facilities" as well as the four "stand alone" hypothetical applications ofSCRtechnologies analyzed, to reflectthe costtabulation fonnat used in the "SCR Chapter" ofthe "EPA AirPollution Control Cost Manual- Sixth Edition" (Section4.2; Chapter 2).

Please see the attached "SharedFacilities Total Capital Investment" and "StandAlone Total Capital Investment" cost estimate tables thatfollow the outline ofTable 2.5 in the SCRChapter ofEPA's Control CostManual9 

### for these hypothetical applications ofSCRtechnologies analyzed. Note thatthis SCRChapterofthe EPA Control CostManual is intendedfor estimating costs ofhigh dust SCRs, as it states onpage 2-41 that "costs for the tail-end arrangement, however, cannotbe estimated from this reportbecause they are significantly higher

7 See Reference number 8, October 1990. 8 IbidReference number 1, November25,2009. 9 IbidReference number9, Section4.2, Chapter2, page 2-44, January 2002.



### 2

### than the high-dust SCR systems due to flue gas heating requirements"lO. The SCRChapter of the Control CostManual also states that "the costmethodology is valid for a low-dust SCR systembecause the costreductions are expected to be within the range ofuncertainty for studylevel costs"!!. We also suggestthat the SCR CostManual is not suitable for estimating the costs for the cold-side low-dust SCR arrangement analyzed in the Supplemental NOx BACTreports for MRYS because ofthe flue gas reheating required.

Also see attached tables ofestimated "SharedFacilities Total Annual Costs" and "StandAlone Total Annual Costs" that include the items described inpages 2-44 through 2-49 ofthe SCR Chapter ofEPA's Control CostManual!2 for an SCR application. As previously mentioned, the equations in the SCR CostManual's costmethodology were notused for estimating annual costs ofelectricalpowerconsumption, reagent usage, and catalystreplacements. Note thatbudgetary vendor quotes were the primary source ofinformationusedto calculate these estimated annual costs ofthe hypothetical applications ofSCRtechnologies analyzed.



### Use ofSteam from the main boilers for reheat offlue gas (forlow-dust and tail end SCR alternatives):
NDDH Request: "The use ofsteam from the mainboilers for the flue gas reheat should also be addressed."

BMcD Response: Natural gas-fired flue gas reheat is shown in the SCR Chapter ofEPA's Control CostManual for

an SCR application ofa tail end SCR example13, 

### so the use ofsuch reheat systems is notunique to Minnkota's study. MPC selected natural gas firing and rejected the use ofsteamfor flue gas reheating for the evaluation ofhypothetical applications oflow-dust and tail end SCR technologies at MRYS. Forthe SCR costestimate study by Bums 

### & McDonnell, it was necessary to establish the scope conceptual designbasis for estimating the costs associated with installation and operation andmaintenance ofthe hypothetical applications oflow-dustand tail

10Ibid Reference number9, Section4.2, Chapter2, page 2-41, January 2002. 11 IbidReference number 9, Section4.2, Chapter2, page 2-41, January 2002. 12 Ibid Reference number9, Section4.2, Chapter2, pages 2-44

- 2-49, January 2002. 13 IbidReference number9, Section4.2, Chapter2, page 2-21, January 2002.



### 3

### end SCRtechnologies. Minnkota's selection ofnatural gas-fired flue gas reheating for these conceptual designs and costestimates was made 

### in orderto avoid additional loss ofunit electrical energy generation output capacity.

A preliminary high level conceptual review ofthe MRYS Unit I steam cycle was done by Minnkotato investigate the feasibility ofusing steamto achieve the estimatedheatduty (31.1 million BTU/hrto raise flue gas temperature from 555°F to 580°F for one reactor) required for the hypothetical application oflow dust SCRtechnology. This preliminary review indicatedthat using steam for this service appeared to be feasible butwouldresultin aunit electrical output capacity derate of4-5 MW. This is because the high-temperature/high-pressure main steam extracted from the boilerfor flue gas reheat systemwouldnotpass through any stages ofthe high/intermediate/low pressure steamturbines, so less net electrical energy wouldbe produced.

The value oflost electrical generating capacitywas not calculated, butthe steady-state long term operation impactis believedto be approximately 50% ormore ofthe total auxiliary electricity demand estimatedin the November 2009 NOx BACT Analysis Study Supplemental Reports' Table 

### CA_3 14

### forthe hypothetical application ofSCRtechnologies atMRYS.

The preliminary concept assumed thatmain boiler steam (high pressure, high temperature, around 1000°F, 2500 psig) wouldbe diverted from the steamturbine's inletpiping, andbe routed for supplyto the flue gas heating system. This would involve the heating steam supplied being condensedusing heating coils inserted into the flue gas ductwork. The condensate liquid would thenbe returnedto the boilerfeedwater treatment systemfor reuse. The 4-5 MW Unit 1 derate for ahypothetical application oflow-dust SCRtechnology does not include additional downtime due to tube leaks orothermaintenance issues associatedwith the flue gas reheat steam system. Higherinduceddraftbooster fan discharge pressure requirementfor pressure drop is not included. Use ofsteam for cleaning the in-duct steamcoils' exterior surfaces orthe gas-to-gas heat exchangeronline during operationusing sootblowing is also not included in this estimate of the potential unitderate. The time required to modify the main steampiping and other steam turbine and boilerfeedwater treatment system components in the steam cycle powergeneration

14 IbidReference 2, page 4-27.



### 4

### andbalance-of-plant systems andboilerflue gas systems to accommodate such suggested changes wouldbe lengthy. The duration ofan outage to implement such modifications, and value oflost electrical generating capacity, wouldbe significant.

A similarpreliminary high level conceptual review ofthe MRYS Unit 2's steamcycle to investigate the feasibility ofusing steamto achieve the estimatedheat duty (2 reactors, 48.1 MMBTU/hreach to raise flue gas temperature from 535°F to 580°F) required for ahypothetical application oflow-dust SCRtechnology was notperformed. Although sizing was not evaluated for MRYS Unit2, using a scaling factor (ratio of477 MW dividedby 257 MWnameplate capacity ratings) to estimate Unit2's derate compared with Unit l's estimated derate couldbe applied for an approximation. This would yield apotential Unit 2 electrical generating output capacity derate on the orderofmagnitude of8 to 10 MW for ahypothetical application oflowdust SCRtechnology. Similarimpacts and issues as described for Unit 1 wouldbe expectedfor Unit 2.

A similarpreliminaryhigh level conceptual review ofthe MRYS Unit l's steamcycle to investigate the feasibility ofusing steamto achieve the estimatedheat duty (1 reactor, 60.3 MMBTU/hreachto raise flue gas temperature from 520°F to 563°F) required for ahypothetical application oftail end SCRtechnology was notperformed. Although sizing was not evaluated for this case, using a scaling factor (ratio of60.3 dividedby 31.1 heat duties) to estimate Unit l's derate comparedwith Unit l's estimatedderate for ahypothetical application oflow-dust SCR technology couldbe applied for an approximation. This would yield apotential Unit 1 electrical generating outputcapacity derate on the orderofmagnitude of8 to 10 MW for ahypothetical application oftail end SCRtechnology. Similarimpacts and issues as previously described for Unit 1 wouldbe expected.

A similarpreliminary high level conceptual review ofthe MRYS Unit 2's steamcycle to investigate the feasibility ofusing steamto achieve the estimatedheat duty (2 reactors, 50.8 MMBTU/hreach to raise flue gas temperature from 520°F to 563°F) required for ahypothetical application oftail end SCRtechnology was notperformed. Although sizing was not evaluated for MRYS Unit 2, using a scaling factor (ratio of101.6 dividedby 31.1 heat duties) to estimate



### 5

### Unit 2's derate comparedwith Unit l's estimatedderate couldbe applied for an approximation. This wouldyield apotential Unit 2 electrical generating output capacity derate on the order of magnitude of13 to 16 MW for ahypothetical application oftail end SCRtechnology. Similar impacts and issues as described for Unit 1 wouldbe expected forUnit 2.

These estimates oflost electrical generation outputs come from boilermain steamusage, larger induced draft fan powerrequirements, andpotential additional downtime associatedwith the flue gas reheating systems. Because the MRYS units' electrical energy generation outputcapacity is limitedby the steam energy production capacity ofeachboiler ("boilerlimited"), there is not "free capacity margin" available to offsetthe megawattlosses. Minnkota also cannot increase boilerhourly heat inputs (coal firing rates) in orderto compensate for the decrease in output because the increased emissions from higherfiring rates are notpermitted.

Additional arguments that supportthe decision to selectnatural gas firing and rejectthe use of steamfor flue gas reheating involving hypothetical applications oflow-dust andtail end SCR technologies atMRYS:

• Minnkota's previous experience with the use ofsteam for Unit 2's flue gas desulfurization system absorber outlet flue gas reheat (for stackplume buoyancy) was not positive andthe technique was abandoned in favor ofreheatvia scrubberflue gas bypass. The ConsentDecree does not allow Minnkotato continue the use ofunscrubbed flue gas for reheating the stackgas 15•



### • Boiler-turbine steam systems are complex and sensitive to steam inputs, extractions, and outlet conditions. There was insufficienttime available during the SCRcostestimate study to perform a comprehensive analysis ofpotential performance impacts from the modifications relatedto theuse ofsteam for flue gas reheat.

• High pressure/high temperature steam piping is expensive to procure and install, and requires special designto accommodate thermal growth and significantweight and dynamic loads without overstress. There was insufficienttime available during the SCR costestimate study to perform a comprehensive analysis ofpotential hanger supports,

15 IbidReference number 5, April 24, 2006.



## 6

### pipe sizing and routing from the main steam source to the multiple points ofuse and return ofcondensate to the boilerplant.

• The deposits removed during cleaning ofthe in-duct steam coils fouledby particulate, aerosols, and ashproducts emittedfrom the boilers and also removed from the gas-gas heat exchangerupstream ofthe flue gas reheaterwill be entrained inthe flue gas stream entering the SCRreactor. This will require a "largeparticle ash screen" that creates more pressure drop than the direct-fired ductburner.



### 7

### Comparison ofAverage and Incremental Control Costs for MRYS NOx BACT (for lowdustand tail end SCR alternatives) versus recentBACT determinations:


### NDDH Request: "It 

### shouldbe documented thatthe costs ofSCR atthe M.R. Young Station are significantly beyondthe range ofrecent costs normally associated with BACT for coal-fired powerplants (orBACT control costs in general) for the control ofnitrogen oxides (NSRManual ChapterB, SectionIV.D.2.C)."

BMcD Response:
A review ofavailable information on "costs normally associatedwith BACT" for control ofNOx emissions from coal-firedpowerplants indicates thatvery little documentation is published. Althoughboth the EPA's RACT BACTLAERClearinghouse (RBLC) [http://cfpub.epa.gov/rblc/htm/b102.cfm] and the EPA's "National Coal-Fired Utility Projects Spreadsheet" [available viahttp://www.epa.gov 

### /ttn!catc/products.html#misc] include an assigned database field for entry of"Control Cost Effectiveness" inunits of$/ton, neither ofthese sources contains much information. The assigned field where the data shouldbe entered is blankin the vastmajority ofcases entered in these databases.

This dearth ofdata on BACT costeffectiveness was encounteredby EPA Region 8 during its preparation ofthe "Responseto Public Comments" for the DraftPSD Permit for DeseretPower Electric Cooperative's proposed 110 MWwaste coal fired unit addition to the Bonanza Power Plant16

. 

### In seeking to defend the costbasis for its rejection ofa control technology as BACT, EPA Region 8 was able to identify only 13 cases (total for allpollutants) 

### in which control cost effectiveness data were identifiedinrecentpermit actions involving BACT.

Burns & 

### McDonnell reviewed the cases identifiedby EPA Region 8 in theirresponse for the DeseretBACT case to determine ifany data on "the cost associatedwith BACT" was available for cases involving NOx control for coal-firedboilers. Ofthe 13 cases for all pollutants identifiedby EPA Region 8, only one case involvedthe rejection ofthe "top" NOx control

16 See Reference number 10, pages 29-33.



### 8

### technology as BACT dueto whatwas identified as "excessive cost". This was the case of MDU's proposed Gascoyne project in North Dakota. The inability ofEPA Region 8 to identify

more cases inwhich the permitrecord clearly establishes the level ofNOx control costs illustrates the difficulty ofthis task.

Bums & 

### McDonnell was able to identify only two othercases, both also inNorth Dakota, in which the permitrecord shows thatthe "top" NOx control technology for a coal-firedboilerwas rejected as having an excessive "control cost effectiveness". The relevant data for these cases is tabulatedbelow, and comparedto similarinformation as stated in the Supplemental NOx BACT reports prepared for MRYS Units 1 and 2.



### 9

### Previous Coal-Fired BoilerNOx BACT Determinations Based on CostEffectiveness

State Utility Plant Technology Average Average Technology Name Considered Control Control Cost Recommended Technically Cost of of as BACT Feasible but Rejected Technology Rejected as Technology Accepted as

BACT by BACT State A2ency ND MDU Gascoyne SCR $7545/ton $2926/ton SNCR ND South South SCR $7640/ton $1690/ton SNCR Heart Heart Coal LLC ND GRE Spiritwood SCR $7640/ton $1843/ton SNCR

As shown in the table above, for coal-firedboilers the "average cost effectiveness ofBACT for NOx" as establishedinprevious permitactions ranges from $1690/tonto $2926/ton. By comparison, the estimatedcost forNOx control using SCR, which was rejected as BACT due to excessive costs inthese previous cases, ranged from 2.6 to 4.5 times the control cost ofthe technology established as BACTusing the "top down" process.
As shown in the table above, for coal-firedboilers the "average cost effectiveness ofBACT for NOx" as establishedinprevious permitactions ranges from $1690/tonto $2926/ton. By comparison, the estimatedcost forNOx control using SCR, which was rejected as BACT due to excessive costs in these previous cases, ranged from 2.6 to 4.5 times the control costofthe technology established as BACTusing the "top down" process.

10

### Control CostData from MRYS Units 1 & 

### 2 Supplemental NOx BACT Reports "Top" Technology Average Average Technology Recommended to be Control Control Cost Recommended as

Rejected as BACT Cost of ofTechnology BACT "Top" Recommended Technolo2Y as BACT MRYS Unit 1 Low- $3,396/ton $1,265/ton MRYS Unit 1 DustorTail End SCR to SNCRwith ASOFA withASOFA $5,969/ton MRYS Unit 2 Low- $3,859/ton $1,240/ton MRYS Unit 2 Dust orTail End SCR to SNCRwith ASOFA with ASOFA $6,597/ton

In the case ofMRYS Units 1 and 2, and taking the range ofcontrol costs for SCR (TESCR and LDSCR) with ASOFA as presented in the Supplemental NOx BACTreports (shown above), the ratio betweenthe cost ofthe technology proposed forrejection on a costbasis to the cost ofthe technology proposed as BACT for the MRYS units is quite similarto that seen inprevious permit actions. ForUnit 1, the costratio ranges from 2.7 to 4.7. ForUnit 2, the costratio ranges from 3.1 to 5.3. Thus it appears that the samerationale thatwas used to reject SCRtechnology as being "excessively costly on a $/ton control costbasis" in the case ofthese otherthree North Dakota BACT determinations should also apply to the case ofMRYS.

11

### REFERENCES

1. North DakotaDepartment ofHealth, Environmental Health Section, Division ofAir Quality letterby Terry 

### L. O'Clair, P.E. to John Graves, MinnkotaPower Cooperative, 

### Re: BACTCostEstimate, datedNovember25,2009.
2. 

### NO

### xBestAvailable Control Technology Analysis Study

- Supplemental Report for Milton R. Young Station Unit 1 for MinnkotaPower Cooperative, Inc., November, 2009; and a separate NO

### xBACT Analysis Study

- Supplemental Report for Milton R. Young Station Unit 2 for MinnkotaPower Cooperative, Inc. and Square Butte Electric Cooperative, November 2009, submittedby Minnkota to North Dakota Department ofHealth on November 12,2009.
3. 

### North DakotaDepartmentofHealth, Environmental Health Section, Division ofAir Quality letterby Terry 

### L. O'Clair, P.E. to John Graves, MinnkotaPower Cooperative, 

### Re: Milton R. Young Station BACTDetermination, dated July 15, 2009, and

### Re: Request for Time Extension, dated August 7, 2009.
4. 

### "BACT Analysis Study for Milton R. Young Station Unit 1 Minnkota PowerCooperative, Inc." and a separate "BACT Analysis Study forMilton R. Young Station Unit 2 Square Butte Electric Cooperative", October 2006, submitted to EPA Region 

### 8 andEPA Office of Regulatory Enforcement, and includedwith the "BART DETERMINATION STUDY for Milton R. Young Station Unit 1 and 2 MinnkotaPowerCooperative, Inc." Final Report, October2006 submittedbyMinnkotato North DakotaDepartmentofHealth.
5. 

### ConsentDecree filed in the United States DistrictCourtForThe District OfNorth Dakota, United States OfAmerica and State OfNorth Dakota, Plaintiffs, v. MinnkotaPower Cooperative, Inc. and Square Butte Electric Cooperative, Defendants, Civil Action No.1:06-CV-034, filed April 24, 2006.
6. ERG Memorandumto EPA Region 8 and EPA Office ofRegulatory Enforcement, 

### Review andCritique of theBurns & 

### McDonnellNO xBACT Analysis for the Milton R. Young Station OperatedbyMinnkota Power (October2006), written by RogerChristman, Eastern Research Group, Inc., January 8, 2007, faxed by North DakotaDepartment ofHealth to Minnkota, January 9, 2007.


### 7. EPA Region 

### 8PreliminaryAnalysis of Burns & 

### McDonnellBACT AnalysisForNitrogen Oxide atMilton R. Young Station, Units 

### 1 and

### 2January 

### 8, 2007faxedby North Dakota Department ofHealth to Minnkota, January 9,2007.
8. 

### EPA New Source Review Workshop Manual, Prevention ofSignificantDeterioration and Nonattainment Area Permitting, DraftOctober 1990 (The "NSRManual").
9. 

### EPA AirPollution Control CostManual- Sixth Edition (EPA/452/B-02-001), January 2002.


### 10. Response to Public Comments onDraftAirPollution ControlPrevention of Significant Deterioration (PSD) Permitto Construct[PermitNo. PSD-OU-0002-04.00}, U.S. EPA Region 

### 8, August 30, 2007.

12

### ATTACHMENTS

1. 

### "SharedFacilities Total Capital Investment" and "StandAlone Total Capital Investment" cost estimate tables for Low-Dust andTail End Selective Catalytic Reduction alternatives, as supporting information regarding Unit 1 and Unit 2 atMilton R. Young Station, November, 2009, Reference number 2, NOx BestAvailable Control Technology Analysis StudySupplemental Reports for MinnkotaPowerCooperative, Inc., dated December 7, 2009.
2. "SharedFacilities Total Annual Costs" and "StandAlone Total Annual Costs" tables for Low-Dust and Tail End Selective Catalytic Reduction alternatives, as supporting information regarding Unit 1 and Unit 2 atMilton R. Young Station, November, 2009, Reference number 2, NOx BestAvailable Control Technology Analysis Study

- Supplemental Reports for MinnkotaPowerCooperative, Inc., dated December7,2009.



### 13Milton R. Young Station Unit 1 and Unit 2 Estimates ofTotal Capital Investment for Low Dust and Tail End Selective Catalytic Reduction Alternatives Best Available Control Technology

- Supplemental Analysis Shared Facilities

DIRECT CAPITAL COSTS Low Dust U1 Low Dust U2 Tail End U1 Tail End U2 Notes (1) Purchased Capital Equipment (a) SCR System Equipment Capital Cost of SCR System $ 29,738,389 $ 52,565,778 $ 38,796,814 $ 70,418,628 Note 1 Capital Cost of Spare Catalyst Note 2 (b) Auxiliaries/Balance of Plant $ 23,756,987 $ 40,894,045 $ 33,414,080 $ 52,307,775 Note 3 (c) Instruments and controls Note 4 (d) Taxes Note 5 (e) Freight Note 6 PURCHASED CAPITAL $ 53,495,376 $ 93,459,823 $ 72,210,894 $122,726,403 Note 7 EQUIPMENT COSTS

- TOTAL (2) Construction Costs (a) Foundations and supports $ 15,097,939 $ 28,304,959 $ 20,041,826 $ 39,631,284 Note 8 (b) Urea storage building Note 9 (c) Electrical $ 6,901,578 $ 13,809,256 $ 7,690,294 $ 15,296,131 Note 10 (d) Mechanical/Piping $ 2,411,613 $ 4,718,286 $ 2,513,213 $ 4,995,255 Note 11 (e) Insulation $ 3,195,016 $ 4,686,967 $ 5,350,536 $ 7,143,550 Note 12 (f) PaintinQ Note 13 DIRECT CAPITAL $ 27,606,146 $ 51,519,468 $ 35,595,868 $ 67,066,221 Note 14 CONSTRUCTION COSTS

- TOTAL
DIRECT CAPITAL COSTS

- TOTAL $ 81,101,522 $144,979,291 $107,806,762 $189,792,624 Note 15
INDIRECT CAPITAL COSTS (3) Indirect Installation Costs

(a) Engineering & Field Support $ 12,165,228 $ 21,746,894 $16,171,014 $ 28,468,894 Note 16 (b) Construction Mgt & Indirects $ 3,244,061 $ 5,799,172 $ 4,312,270 $ 7,591,705 Note 17 (c) Startup Expenses $ 1,582,000 $ 2,938,000 $ 1,582,000 $ 2,938,000 Note 18 (d) Scope Contingency $ 12,486,493 $ 21,567,604 $ 16,536,353 $ 28,151,800 Note 19 (4) Other Indirect Costs

(a) Pricina ContingencY $ 12,486,493 $ 21,567,604 $ 16,536,353 $ 28,151,800 Note 20 INDIRECT INSTALLATION $ 41,964,276 $ 73,619,274 

### $ 55,137,991 $ 95,302,199 Note 21 COSTS

- TOTAL (5) Cost Escalation during Project $ 26,772,124 $ 40,212,687 $ 35,491 ,483 $ 52,726,778 Note 22 (6) Interest During Construction $ 17,441,200 $ 30,047,900 $ 23,097,900 $ 39,221,000 Note 23 (7) Natural Gas Pipeline

- Installed $ 2,362,500 $ 4,387,500 $ 2,362,500 $ 4,387,500 Note 24 (8) Owner's Costs

- Other $ 13,632,335 $ 24,182,077 $ 16,920,540 $ 29,632,862 Note 25
TOTAL CAPITAL INVESTMENT $183,273,957 $317,428,728 $240,817,176 $411,062,963 Note 26



### Minnkota Power Cooperative, Inc. 1 Burns & 

### McDonnell 12/11/2009Shared Facilities (SF) represents estimated costs if SCR equipment is retrofitted to both boilers concurrently. This table follows outline ofTable 2.5 of EPA OAQPS SCR Cost Manual, EPA/452/B-02-001 Section 4.2 NOx Controls Post Combustion, page 2-44. Note 1: Includes costs for SCR equipment including initial catalyst, flue gas heat recovery equipment, and flue gas reheat burner equipment as well mechanical setting ofthis equipment. Note 2: Does not include spare catalyst in purchased SCR equipment costs. Note 3: Includes service air and sootblower aircompressors, induced draft boosterfan(s) and dampers, ureato-ammonia conversion, flue gas reheat gas-firing burners and fan(s), SCR bypass ducts and isolation dampers, interconnecting ductwork, equipmentfor active coal yard storage modifications, and catalyst standby heating auxiliary equipmeht costs as well as mechanical setting ofthis equipment. Note 4: Instrumentation and controls are included in Electrical Construction costs (see Note 10). Note 5: Sales taxes for engineered equipment and permanent materials is not included; Taxes are included for consumable materials. Note 6: Delivery expenses are included in equipment costs. Note 7: Sum of SCR, Auxiliaries/Balance of Plant, and Instruments/Controls equipment costs; taxes and freight. Note 8: Includes site excavation, structural steel, concrete, and architectural construction costs. Includes SCR bypass ducts and isolation dampers, and interconnecting ductwork construction costs. Note 9: Estimated separately as shown in Table 4.5 SF in Supplemental BACT Control and Cost Effectiveness Analysis. Note 10: Instrumentation and Controls, additional plant electrical distribution equipment are included in Electrical construction costs. Note 11: Mechanical/Piping includes material and installation of all piping not provided with engineered equipment. Note 12: Insulation includes ductwork and piping insulation. Note 13: Painting included in structural and architectural construction costs. Note 14: Sum of Direct Capital Construction Costs. Note 15: Sum ofTotal Purchased Capital Equipment and Total Direct Capital Construction Costs; considered to be equivalent to "A" in EPA OAQPS SCR Cost Manual Table 2.5. Note 16: Sum of Engineering and Field Support Costs. Note 17: Sum of Construction Management and Construction Indirects. Note 18: Startup Costs include costs for startup engineering support. Note 19: Scope contingency is to account for potential changes in the project scope resulting from engineering, equipment, and/or construction work which were not identified or included. Note 20: Pricing contingency is to account for potential changes in project costs resulting from wages, productivities, equipment and/or materials costs being higherthan anticipated. Note: this does not intend to cover pricing increases overtime, Le. Escalation. Considered to be equivalent to "C" in EPA OAQPS SCR Cost Manual Table 2.5. Note 21: Sum of Indirect Capital Installation Costs; considered to be equivalent to "D", Total Plant Costs in EPA OAQPS SCR Cost Manual Table 2.5. Note 22: Escalation is a result of anticipated increases in costs that are due to higher costs overtime. Note 23: Interest During Construction (orAllowance for Funds During Construction) are considered to be equivalent to "E" in EPA OAQPS SCR Cost Manual Table 2.5. Note 24: Natural gas pipeline construction cost was assumed as an owner cost. Note 25: Other Owner Costs include Owner personnel, insurance, pilot testing, Owner Contingency and Spare Parts. Note 26: Total Capital Investment (TCI) is equivalent to Installed Capital Cost for Low-Dust and Tail End SCRs in the November2009 NOx BACT Supplemental Analysis Table 4-5SF, page 4-18. The installed capital cost of the Urea Storage Tanks and Building, and Advanced Separated Overfire Air (ASOFA) system, are not included in these numbers. See Table 4-5SF.



### Minnkota Power Cooperative, Inc. 2 Bums & 

### McDonnell 12/11/2009Milton R. Young Station Unit 1 and Unit 2 Estimates ofTotal Capital Investmentfor Low Dust and Tail End Selective Catalytic Reduction Alternatives Best Available Control Technology

- Supplemental Analysis Stand Alone

DIRECT CAPITAL COSTS Low Dust U1 Low Dust U2 Tail End U1 Tail End U2 Notes (1) Purchased Capital Equipment (a) SCR System Equipment Capital Cost of SCR System $ 29,738,389 $ 52,565,778 $ 38,796,814 $ 70,418,628 Note 1 Capital Cost of Spare Catalyst Note 2 (b) Auxiliaries/Balance of Plant $ 34,665,617 $ 46,348,360 $ 44,322,710 $ 57,762,090 Note 3 (c) Instruments and controls Note 4 (d) Taxes Note 5 (e) Freioht Note 6 PURCHASED CAPITAL $ 64,404,006 $ 98,914,138 $ 83,119,524 $128,180,718 Note 7 EQUIPMENT COSTS

- TOTAL (2) Construction Costs (a) Foundations and supports $ 20,120,339 $ 30,816,159 $ 25,024,641 $ 42,122,692 Note 8 (b) Urea storage building Note 9 (c) Electrical $ 8,399,220 $ 14,558,077 $ 9,489,326 $ 19,195,648 Note 10 (d) Mechanical/Piping $ 4,299,227 $ 5,662,093 $ 4,400,827 $ 5,939,062 Note 11 (e) Insulation $ 3,288,333 $ 4,733,626 $ 5,443,853 $ 7,190,209 Note 12 (f) Painting Note 13 DIRECT CAPITAL $ 36,107,120 $ 55,769,955 $ 44,358,647 $ 71,447,611 Note 14 CONSTRUCTION COSTS

- TOTAL
DIRECT CAPITAL COSTS

- TOTAL $100,511,125 $154,684,093 $127,478,171 $199,628,329 Note 15
INDIRECT CAPITAL COSTS (3) Indirect Installation Costs

(a) Engineering & Field Support $ 15,076,669 $ 23,202,614 $ 19,121,726 $ 29,944,249 Note 16 (b) Construction Mgt & Indirects $ 4,020,445 $ 6,187,364 $ 5,099,127 $ 7,985,133 Note 17 (c) Startup Expenses $ 1,582,000 $ 2,938,000 $ 1,582,000 $ 2,938,000 Note 18 (d) Scope Contingency $ 15,436,040 $ 22,988,134 $ 19,529,462 $ 29,593,180 Note 19 (4) Other Indirect Costs

(a) Pricino Continoency $ 12,486,493 $ 21,567,604 $ 16,536,353 $ 28,151,800 Note 20 INDIRECT INSTALLATION $ 51,551,194 $ 78,304,245 $ 64,861,776 $100,053,742 Note 21 COSTS

- TOTAL (5) Cost Escalation during Project $ 30,170,164 $ 42,869,269 $ 42,013,593 $ 55,436,089 Note 22 (6) Interest During Construction $ 21,561,300 $ 32,027,100 $ 27,278,800 $ 41,228,900 Note 23 (7) Natural Gas Pipeline

- Installed $ 6,750,000 $ 6,750,000 $ 6,750,000 $ 6,750,000 Note 24 (8) Owner's Costs

- Other $ 23,114,224 $ 27,867,439 $ 26,204,034 $ 33,248,637 Note 25
TOTAL CAPITAL INVESTMENT $236,658,008 $342,502,146 $294,586,374 $436,345,697 Note 26



### MinnkotaPower Cooperative, Inc. 3 Burns & 

### McDonnell 12/11/2009Stand Alone (SA) represents estimated costs if SCR equipment is retrofitted to both boilers independently. This table follows outline ofTable 2.5 of EPA OAQPS SCR Cost Manual, EPA/452/B-02-001 Section 4.2 NOx Controls Post Combustion, page 2-44. Note 1: Includes costs for SCR equipment including initial catalyst, flue gas heat recovery equipment, and flue gas reheat burner equipment as well mechanical setting ofthis equipment. Note 2: Does not include spare catalyst in purchased SCR equipment costs. Note 3: Includes service air and sootblower air compressors, induced draft boosterfan(s) and dampers, ureato-ammonia conversion, flue gas reheat gas-firing burners and fan(s), SCR bypass ducts and isolation dampers, interconnecting ductwork, equipment for active coal yard storage modifications, and catalyst standby heating auxiliary equipment costs as well as mechanical setting ofthis equipment. Note 4: Instrumentation and controls are included in Electrical Construction costs (see Note 10). Note 5: Sales taxes for engineered equipment and permanent materials is not included; Taxes are included for consumable materials. Note 6: Delivery expenses are included in equipment costs. Note 7: Sum of SCR, Auxiliaries/Balance of Plant, and Instruments/Controls equipment costs; taxes and freight. Note 8: Includes site excavation, structural steel, concrete, and architectural construction costs. Includes SCR bypass ducts and isolation dampers, and interconnecting ductwork construction costs. Note 9: Estimated separately as shown in Table 4.5 SA in Supplemental BACT Control and Cost Effectiveness Analysis. Note 10: Instrumentation and Controls, additional plant electrical distribution equipment are included in Electrical construction costs. Note 11: Mechanical/Piping includes material and installation of all piping not provided with engineered equipment. Note 12: Insulation includes ductwork and piping insulation. Note 13: Painting included in structural and architectural construction costs. Note 14: Sum of Direct Capital Construction Costs. Note 15: Sum ofTotal Purchased Capital Equipment and Total Direct Capital Construction Costs; considered to be equivalentto "A" in EPA OAQPS SCR Cost Manual Table 2.5. Note 16: Sum of Engineering and Field Support Costs. Note 17: Sum of Construction Management and Construction Indirects. Note 18: Startup Costs include costs for startup engineering support. Note 19: Scope contingency is to account for potential changes in the project scope resulting from engineering, equipment, and/or construction work which were not identified or included. Note 20: Pricing contingency is to account for potential changes in project costs resulting from wages, productivities, equipment and/or materials costs being higherthan anticipated. Note: this does not intend to cover pricing increases overtime, Le. Escalation. Considered to be equivalent to "C" in EPA OAQPS SCR Cost Manual Table 2.5. Note 21: Sum of Indirect Capital Installation Costs; considered to be equivalent to "D", Total Plant Costs in EPA OAQPS SCR Cost Manual Table 2.5. Note 22: Escalation is a result of anticipated increases in costs that are due to higher costs overtime. Note 23: Interest During Construction (orAllowance for Funds During Construction) are considered to be equivalent to "E" in EPA OAQPS SCR Cost Manual Table 2.5. Note 24: Natural gas pipeline construction cost was assumed as an owner cost. Note 25: Other Owner Costs include Owner personnel, insurance, pilot testing, Owner Contingency and Spare Parts. Note 26: Total Capital Investment (TCI) is equivalent to Installed Capital Cost for Low-Dust and Tail End SCRs in the November2009 NOx BACT Supplemental Analysis Table 4-5SA, page 4-17. The installed capital cost of the Urea Storage Tanks and Building, and Advanced Separated Overfire Air (ASOFA) system, are not included in these numbers. See Table 4-5SA.



### Minnkota PowerCooperative, Inc. 

### 4 Bums & 

### McDonnell 12/11/2009Milton R. Young Station Unit 1 and Unit 2 Estimates ofTotal Annual Costs for Low Dust and Tail End Selective Catalytic Reduction Alternatives Best Available Control Technology - Supplemental Analysis Shared Facilities

DIRECT ANNUAL COSTS Low Dust U1 Low DustU2 Tail End U1 Tail End U2 Notes (1) Annual Maintenance Costs 

### $ 4,189,181 

### $ 7,514,611 

### $ 5,444,530 

### $ 9,608,381 Note 1 (2) Annual Reagent Costs Note 2 Scenario A 

### $ 2,710,313 

### $ 4,171,528 

### $ 2,709,417 

### $ 4,170,150 Scenario B 

### $ 2,725,539 

### $ 4,204,613 

### $ 2,724,643 

### $ 4,204,613 (3) Annual Electricity Costs Note 3 Scenario A 

### $ 5,929,642 

### $ 9,730,376 

### $ 6,011,088 

### $ 9,740,159 Scenario B 

### $ 11,939,901 

### $ 24,539,279 

### $ 11,982,549 

### $ 25,083,883 (4) Annual Water Costs Note 4 (5) Catalyst Replacement Costs Note 5 Scenario A 

### $ 709,951 

### $ 958,131 

### $ 709,951 

### $ 963,350 Note 6 Scenario B 

### $ 4,387,500 

### $ 10,260,000 

### $ 4,387,500 

### $ 10,260,000 Note 7 (6) Natural Gas for F.G. Reheating 

### &

Urea-to-Ammonia Conversion sys. Note 8

Scenario A 

### $ 2,136,238 

### $ 6,064,108 

### $ 3,931,511 

### $ 6,416,128 Scenario B 

### $ 1,944,698 

### $ 5,296,499 

### $ 3,580,852 

### $ 5,574,558 Note 9 (7) Operating laborfor SCR equipment and urea-to-ammonia eqpmnt Note 10 DIRECT Annual COSTS - TOTAL Note 11 Scenario A 

### $ 15,675,326 

### $ 28,438,754 

### $ 18,806,498 

### $ 30,898,167 Scenario B 

### $ 25,186,819 

### $ 51,815,002 

### $ 28,120,074 

### $ 54,731,434
INDIRECT Annual COSTS (8) Annual Costs from Capital Recovery 

### $ 12,174,396 

### $ 21,838,601 

### $ 15,822,632 

### $ 27,923,414 Note 12 (9) Administrative overhead, insurance and property taxes for SCRs and aux. Note 13 INDIRECT Annual COSTS - TOTAL 

### $ 12,174,396 

### $ 21,838,601 

### $ 15,822,632 

### $ 27,923,414
TOTAL ANNUAL COSTS Note 14 Scenario A 

### $ 27,849,722 

### $ 50,277,355 

### $ 34,629,130 

### $ 58,821,580 Scenario B 

### $ 37,361,215 

### $ 73,653,603 

### $ 43,942,706 

### $ 82,654,848
LEVEL/ZED TOTAL ANNUAL/ZED COSTS Note 15 Scenario A 

### $ 31,748,616 

### $ 57,350,872 

### $ 39,306,834 

### $ 66,506,822 Scenario B 

### $ 43,625,884 

### $ 86,541,448 

### $ 50,936,958 

### $ 96,268,092



### MinnkotaPowerCooperative, Inc. 1 

### Bums & 

### McDonnell 12/11/2009Shared Facilities (SF) represents estimated costs if SCR equipment is retrofitted to both boilers concurrently. This table includes values that are identified in the EPA OAQPS SCR Cost Manual, EPA/452/B-02-001 Section 4.2 NOx Controls Post Combustion, page 2-44 through 2-49 but use calculated and vendorquoted values instead ofthe formulas provided in the OAQPS manual Total Annual Costs consist ofdirect costs, indirect costs, and recovery credits (if any). Direct Annual Costs and variable and semi-variable costs that are proportional to the quantity offlue gas processed by the control system. Indirect Annual Costs are fixed costs incurred independent of control operation, and include capital recovery costs, insurance, administrative charges, and overhead (payroll and plant). Note 1: Annual maintenance was assumed to be 3% of installed capital cost ofthe SCRequipment and auxiliary equipment related to the SCR systems, not including catalyst replacement costs. Maint. costs forASOFA are included. Note 2: Annual reagent costs are for "Scenario A" and "Scenario B" operation and related chemical usage based on receiving 50% aqueous urea solution, assumed to be $379.29 perton in 2006$. Note 3: Annual electricity costs are for "Scenario A" and "Scenario B" operation and related electricity consumption and lost generation, assumed to be $35/MW-hr in 2006$. See Tables C.4-1 through C.4- 4 in the November2009 NOx BACT Analysis Study Supplemental Reports for details. Note 4: Annual water costs were not calculated, but may be more than zero, ifconcentrated liquid urea liquor (70% concentration) is purchased, which must be diluted to 50% concentration for storage. Note 5: Annual catalyst replacement costs are for "Scenario A" and "Scenario B" operation, and are assumed to be based on $7,500 per cubic meter in 2006$. Note 6: Annual catalyst replacement costs for "Scenario A" are assumed to be based one layer per reactor every two years (approx. 16,000 operating hours), and follows the EPA OAQPS SCR Cost Manual for annualizing the purchase cost using Equations 2.51 and 2.52 on page 2-47 and Equation 2.53 on page 2-48 assuming 6% peryear annual interest rate. Tail end SCRs were assumed to have 10 layers replaced during the 20-year economic evaluation period, and 12 layers for Low-dust SCRs, but the annual catalyst replacement costs for U2 used in the November2009 NOx BACT Analysis Study Supplemental Report underestimate the cost per layer due to assuming regular depth layers instead ofdeep layers recommended byvendor. Note 7: Annual catalyst replacement costs for"Scenario B" are assumed to be based three layers per reactor every year (approx. 2,667 operating hours) for U1 and four layers per reactor peryear (approx. 2,000 operating hours) for U2. There were no adjustments for annualizing the purchase cost (Equations 2.51 and 2.52 on page 2-47 and Equation 2.53 on page 2-48 of the EPA OAQPS SCR Cost Manual were not used). U1 Low-dust and Tail end SCRs were assumed to have 60 layers replaced during the 20-year economic evaluation period, and 80 layers for U2's Tail end SCRs. Note 8: Annual costs of natural gas firing for flue gas reheating and urea-to-ammonia conversion system operation for "Scenario A" and "Scenario B" are assumed to be based on $7.98 per million BTU in 2006$. Note 9: Annual costs of natural gas firing for "Scenario B" are lowerthan "Scenario A" due to fewer annual hours ofoperation resulting from additional catalyst replacements. Note 10: Annual costs of operating laborfor SCR equipment, flue gas reheating, and urea-to-ammonia systems were assumed to be zero, but this may underestimate actual requirements. Note 11: Total Direct Annual Costs are the sum of maintenance, reagent, electricity, catalyst replacements, and natural gas for Scenario A and Scenario B operations. This may underestimate actual requirements. Note 12: Annual Costs from capital recovery are the same for Scenario A and Scenario B operations. See Appendix C in the 2006 NOx BACT Analysis Study reports for details. The capital recovery factor used to calculate the annual costs is 0.087185. Capital recovery costs forASOFA are included. Note 13: Annual costs of increases in administrative overhead, insurance premiums, and property taxes for SCR equipment and related auxiliaries were assumed to be zero, but this may underestimate actual requirements. Note 14: Total Annual Costs are the sum of increases in Direct Costs and Indirect Costs for SCR equipment and related auxiliaries. These values may underestimate actual requirements. Note 15: Levelized Total Annualized Costs are TDC multiplied by the levelization factor (1.24873 ) plus the Total Indirect Annual Costs (capital recovery). See Appendix C in the 2006 NOx BACT Analysis Study Reports for details. These values may underestimate actual requirements.


### MinnkotaPowerCooperative, Inc. 2 Bums 

### & McDonnell 12/11/2009These numbers are the same Levelized Total Annualized Costs for Low-Dust and Tail End SCRs in the November 2009 NOx BACT Supplemental Analysis Tables 4-6SF, 4-7SF, 4-8SF, and 4-9SF. The capital recovery costs ofthe Urea Storage Tanks and Building, and Advanced Separated Overfire Air (ASOFA) system, based on the installed capital costs shown in Tables 4-4SF and 4-5SF, are included in these numbers.



### MinnkotaPowerCooperative, Inc. 

### 3 Bums & 

### McDonnell 

### 1211112009Milton R. Young Station Unit 1 and Unit 2 Estimates ofTotal Annual Costs for Low Dust and Tail End Selective Catalytic Reduction Alternatives Best Available Control Technology· Supplemental Analysis Stand Alone

DIRECT ANNUAL COSTS Low Dust U1 Low Dust U2 Tail End U1 Tail End U2 Notes (1) Annual Maintenance Costs 

### $ 5,422,167 

### $ 8,123,552 

### $ 6,685,918 

### $ 10,222,003 Note 1 (2) Annual Reagent Costs Note 2 Scenario A 

### $ 2,710,313 

### $ 4,171,528 

### $ 2,709,417 

### $ 4,170,150 Scenario B 

### $ 2,725,539 

### $ 4,204,613 

### $ 2,724,643 

### $ 4,204,613 (3) Annual Electricity Costs Note 3 Scenario A 

### $ 5,929,642 

### $ 9,730,376 

### $ 6,011,088 

### $ 9,740,159 Scenario B 

### $ 11,939,901 

### $ 24,539,279 

### $ 11,982,549 

### $ 25,083,883 (4) Annual Water Costs Note 4 (5) Catalyst Replacement Costs Note 5 Scenario A 

### $ 709,951 

### $ 958,131 

### $ 709,951 

### $ 963,350 Note 6 Scenario B 

### $ 5,850,000 

### $ 10,260,000 

### $ 4,387,500 

### $ 10,260,000 Note 7 (6) Natural Gas for F.G. Reheating 

### &

Urea-to-Ammonia Conversion sys. Note 8

Scenario A 

### $ 2,136,238 

### $ 6,064,108 

### $ 3,931,511 

### $ 6,416,128 Scenario B 

### $ 1,944,698 

### $ 5,296,499 

### $ 3,580,852 

### $ 5,574,558 Note 9 (7) Operating laborfor SCR equipment and urea-to-ammonia eqpmnt Note 10 DIRECT Annual COSTS· TOTAL Note 11 Scenario A 

### $ 16,908,311 

### $ 29,047,696 

### $ 20,047,886 

### $ 31,511,788 Scenario B 

### $ 27,882,304 

### $ 52,423,943 

### $ 29,361,462 

### $ 55,345,056
INDIRECT Annual COSTS (8) Annual Costs from Capital Recovery 

### $ 15,757,639 

### $ 23,608,277 

### $ 19,430,293 

### $ 29,706,692 Note 12 (9) Administrative overhead, insurance and property taxes for SCRs and aux. Note 13 INDIRECT Annual COSTS· TOTAL 

### $ 15,757,639 

### $ 23,608,277 

### $ 19,430,239 

### $ 29,706,692
TOTAL ANNUAL COSTS Note 14 Scenario A 

### $ 32,665,951 

### $ 52,655,972 

### $ 39,478,179 

### $ 61,218,481 Scenario B 

### $ 43,639,944 

### $ 76,032,220 

### $ 48,791,755 

### $ 85,051,748
LEVELIZED TOTAL ANNUALIZED COSTS Note 15 Scenario A 

### $ 36,871,522 

### $ 59,880,950 

### $ 44,464,651 

### $ 69,056,347 Scenario B 

### $ 50,575,055 

### $ 89,071,526 

### $ 56,094,775 

### $ 98,817,617



### MinnkotaPowerCooperative, Inc. 

### 4 Burns 

### & McDonnell 12/11/2009Stand Alone (SA) represents estimated costs if SCR equipment is retrofitted to both boilers independently. This table includes values that are identified in the EPA OAQPS SCR Cost Manual, EPA/452/B-02-001 Section 4.2 NOx Controls Post Combustion, page 2-44 through 2-49 but use calculated and vendorquoted values instead ofthe formulas provided in the OAQPS manual Total Annual Costs consist ofdirect costs, indirect costs, and recovery credits (if any). Direct Annual Costs and variable and semi-variable costs that are proportional to the quantity offlue gas processed by the control system. Indirect Annual Costs are fixed costs incurred independent of control operation, and include capital recovery costs, insurance, administrative charges, and overhead (payroll and plant). Note 1: Annual maintenance was assumed to be 3% of installed capital cost ofthe SCR equipment and auxiliary equipment related to the SCR systems, not including catalyst replacement costs. Maint. costs forASOFA are included. Note 2: Annual reagent costs are for "Scenario A" and "Scenario B" operation and related chemical usage based on receiving 50% aqueous urea solution, assumed to be $379.29 perton in 2006$. Note 3: Annual electricity costs are·for "Scenario A" and "Scenario B" operation and related electricity consumption and lost generation, assumed to be $35/MW-hr in 2006$. See Tables C.4-1 through C.4- 4 in the November2009 NOx BACT Analysis Study Supplemental Reports for details. Note 4: Annual watercosts were not calculated, but may be more than zero, ifconcentrated liquid urea liquor (70% concentration) is purchased, which must be diluted to 50% concentration for storage. Note 5: Annual catalyst replacement costs are for "Scenario A" and "Scenario B" operation, and are assumed to be based on $7,500 per cubic meter in 2006$. Note 6: Annual catalyst replacement costs for "Scenario A" are assumed to be based one layer per reactor every two years (approx. 16,000 operating hours), and follows the EPA OAQPS SCR Cost Manual for annualizing the purchase cost using Equations 2.51 and 2.52 on page 2-47 and Equation 2.53 on page 2-48 assuming 6% peryear annual interest rate. Tail end SCRs were assumed to have 10 layers replaced during the 20-year economic evaluation period, and 12 layers for Low-dustSCRs, but the annual catalyst replacement costs for U2 used in the November2009 NOx BACT Analysis Study Supplemental Report underestimate the cost per layer due to assuming regular depth layers instead ofdeep layers recommended byvendor. Note 7: Annual catalyst replacement costs for "Scenario B" are assumed to be based three layers per reactor every year (approx. 2,667 operating hours) for U1 and four layers per reactor peryear (approx. 2,000 operating hours) for U2. There were no adjustments for annualizing the purchase cost (Equations 2.51 and 2.52 on page 2-47 and Equation 2.53 on page 2-48 ofthe EPA OAQPS SCR Cost Manual were not used). U1 Low-dust and Tail end SCRs were assumed to have 60 layers replaced during the 20-year economic evaluation period, and 80 layers for U2's Tail end SCRs. Note 8: Annual costs of natural gas firing forflue gas reheating and urea-to-ammonia conversion system operation for "Scenario A" and "Scenario B" are assumed to be based on $7.98 per million BTU in 2006$. Note 9: Annual costs of natural gas firing for "Scenario B" are lowerthan "Scenario A" due to fewer annual hours of operation resulting from additional catalyst replacements. Note 10: Annual costs ofoperating laborfor SCR equipment, flue gas reheating, and urea-to-ammonia systems were assumed to be zero, but this may underestimate actual requirements. Note 11: Total Direct Annual Costs are the sum of maintenance, reagent, electricity, catalyst replacements, and natural gas for Scenario A and Scenario B operations. This may underestimate actual requirements. Note 12: Annual Costs from capital recovery are the same for Scenario A and Scenario B operations. See Appendix C in the 2006 NOx BACT Analysis Study reports for details. The capital recovery factor used to calculate the annual costs is 0.087185. Capital recovery costs for ASOFA are included. Note 13: Annual costs of increases in administrative overhead, insurance premiums, and property taxes for SCR equipment and related auxiliaries were assumed to be zero, but this may underestimate actual requirements. Note 14: Total Annual Costs are the sum of increases in Direct Costs and Indirect Costs for SCR equipment and related auxiliaries. These values may underestimate actual requirements. Note 15: Levelized Total Annualized Costs are TDC multiplied by the levelization factor (1.24873) plus the Total Indirect Annual Costs (capital recovery). See Appendix C in the 2006 NOx BACT Analysis Study Reports for details. These values may underestimate actual requirements.


### Minnkota Power Cooperative, Inc. 5 Burns & 

### McDonnell 12/11/2009These numbers are the same Levelized Total Annualized Costs for Low-Dust and Tail End SCRs in the November2009 NOx BACT Supplemental Analysis Tables 4-6SA, 4-7SA, 4-8SA, and 4-9SA. The capital recovery costs ofthe Urea Storage Tanks and Building, and Advanced Separated Overfire Air (ASOFA) system, based on the installed capital costs shown in Tables 4-4SA and 4-5SA, are included in these numbers.



### MinnkotaPowerCooperative, Inc. 

### 6 Burns 

### & McDonnell 12/11/2009