### MINNKOTA POWERCOOPERATIVE, Inc. and SQUARE BUTTE ELECTRIC COOPERATIVE RESPONSES TO NDDH REQUEST NOx BACTANALYSIS STUDY MILTON R. YOUNGSTATION UNIT I and UNIT2 REGARDING SCRECONOMIC FEASIBILITY DecemberII, 2009 Revised February 2010 (referto page 13 for Index of Revisions)


### North DakotaDepartmentofHealth's Environmental Health Section, Division ofAirQualityhas requested' thatMinnkotaPowerCooperative Inc. ("Minnkota" or"MPC")providemoredetailed andcomprehensive costdatafollowing theirreviews ofthe BestAvailableControl Technology (BACT) Analysis Study

- Supplementalreports2 

### submittedonNovember 12, 2009 for control of nitrogenoxides (NOx) emissions from existing Unit 1 andUnit2atMiltonR. Young Station ("MRYS"). Adetailedbreakdownofcapital costs and operationandmaintenancecosts for hypothetical applications oflow-dustand tailend SCRalternatives, assuming thatthey are technically feasible to apply atMRYS as NDDH has recently advised), are attached. Responses to the use ofsteamfrom themainboilers forreheat ofthe flue gas areprovided. Acomparison ofcontrol costs fromrelevantrecentBACT Determinations versus theestimatedcontrol costs of hypotheticalapplications oflow-dust and tail end SCRtechnologies atMRYS includedwiththe November2009 Supplemental Reports is also provided.

Bums & McDonnell (B&McD) was retainedby MPC as an independentconsultanttoperform the referencedNOxBACT Analysis Study4 

### ofMinnkota's Unit 1and SquareButteElectric Cooperative's Unit2atthe Milton R. Young Station(MRYS) inaccordance with the requirements ofaConsentDecree (CDi. 

### TheNovember2009 NOxBACTAnalysis Study Supplemental Reports were generatedinresponse to theNDDH's request6

### to see Steps 3 and

1

### SeeReferencenumberI, November25, 2009. 2

### SeeReferencenumber2,

### November 12, 2009. J 

### SeeReferencenumber3,

### July 15,2009. 

### SCRtechnologyisconsideredtechnicallyinfeasiblebyMinnkotaforapplication atMRYSpertheOctober2006

### NOxBACTAnalysisStudyreportandsubsequentsubmittalsinresponsetocommentsbythe NDDH,EPA,DOJ,andotherparties,includingtheNovember2009

### SnpplementalNOxBACTAnalysisStudyreports. 4

### SeeReferencenumber4,

### October2006. 5

### SeeReferencenumber5,

### April 24, 2006. 6

### IbidReferencenumber3, July 15,2009. 

### SCRtechnologyisconsideredtechnicallyinfeasiblebyMinnkotaforapplication atMRYSpertheOctober2006

### NOxBACTAnalysisStudyreportandsubsequentsubmittalsinresponsetocommentsbythe NDDH,EPA,DOJ,andotherparties,iucludingtheNovember2009

### SupplementalNOxBACTAnalysisStudyreports.

### 4 ofthe BACT analysis process7 

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



### DetailedNOx BACT Analysis Study Supplementalreports' Capital and Operating & 

### Maintenance CostSummary:
NDDH Request: "A detailedbreakdown ofcapital costs and operation and maintenance costs for the bulleted items on page 4-16 should be provided.,,8

BMcD Response: The referenced "bulleted items on page4-16" ofthe November 2009 NOx BACT Analysis Study Supplemental reports are intended to represent the majorcomponents (physical assets) that were identified as being required to install and operate low-dust and tail end SCRs ifthey were considered technically feasible for application at MRYS. Preliminary SCR Cost Estimates used

as inputs to the November 2009 NOx BACT Analysis Study Supplemental Reports were not developed based upon a directmatch to each ofthe bulleted items included in the reports. Thus it is notpossible to provide a costbreakdown in that format. In lieu ofabreakout directly corresponding to the bulleted items, Burns & McDonnell has modified ourcostestimate spreadsheets for the four "shared facilities" as well as the four "stand alone" hypothetical applications ofSCRtechnologies analyzed, to reflect the costtabulation format used in the "SCR Chapter" ofthe "EPA AirPollution Control Cost Manual- Sixth Edition" (Section 4.2; Chapter 2).

Please see the attached "SharedFacilities Total Capital Investment" and "Stand Alone Total Capital Investment" cost estimate tables that follow the outline ofTable 2.5 in the SCR Chapter ofEPA's Control Cost Manual9 

### for these hypothetical applications ofSCR technologies analyzed. Note that this SCRChapterofthe EPA Control CostManual is intended for estimating costs ofhigh dust SCRs, as it states on page 2-41 that "costs for the tail-end arrangement, however, cannotbe estimated from this reportbecause they are significantlyhigher

7 See Reference number 8, October 1990.

, Ibid Reference number 1, November 25, 2009. 9 Ibid Reference number9, Section 4.2, Chapter 2, page 2-44, January 2002.



### 2

### than the high-dust SCR systems due to flue gas heating requirements"lO. The SCR Chapterof the Control Cost Manual also states that "the costmethodology is valid for alow-dust SCR system because the costreductions are expected to be within the range ofuncertainty for studylevel costs"!!. We also suggest that the SCR Cost Manual is not suitable for estimating the costs for the cold-side low-dust SCR arrangement analyzed in the SupplementalNOx BACTreports for MRYS because ofthe flue gas reheating required.

Also see attached tables ofestimated "Shared Facilities Total Annual Costs" and "Stand Alone Total Annual Costs" that includethe items described in pages 2-44 through 2-49 ofthe SCR Chapter ofEPA's Control Cost Manual!2 for an SCR application. As previously mentioned, the equations in the SCRCost Manual's cost methodology were notused for estimating annual costs ofelectrical powerconsumption, reagent usage, and catalystreplacements. Note thatbudgetaty vendorquotes were the primary source ofinformation used to 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 Cost Manual for

an SCRapplication ofa tail end SCRexamplelJ, so the use ofsuchreheat systems is notunique to Minnkota's study. MPC selected natural gas firing and rejected the use ofsteam for flue gas reheating for the evaluation ofhypothetical applications oflow-dustand tail end SCR technologies at MRYS. Forthe SCRcostestimate study by Burns & 

### McDonnell, itwas necessary to establish the scope conceptual design basis for estimating the costs associated with installation and operation and maintenance ofthe hypothetical applications oflow-dustand tail

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

- 2-49, January 2002. 13 Ibid Reference number 9, Section 4.2, 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 preliminalY high level conceptual review ofthe MRYS Unit I steam cycle was done by Minnkotato investigate the feasibility ofusing steam to achieve the estimated heatduty (was 31.1 but is now 54.5 million BTU/hI' to raise flue gas temperature from**~"'F--535°F** 

### to 580°F for

onereactor) required for the hypothetical application oflow dust SCRtechnology. This preliminalYreview indicated thatusing steam for this service appearedto be feasible butwould result in aunitelectrical output capacity derate of4 5 M\'i 7 to 9 MW. This is because the hightemperature/high-pressure main steam extracted li'om the boilerfor flue gas reheat systemwould not pass through any stages ofthe high/intermediate/low pressure steam turbines, so less net electrical energy wouldbe produced.

The value oflost electrical generating capacity was notcalculated, butthe steady-state long term operation impact is believed to be approximately 90% ormore ofthe total auxiliary electricity demand estimated in the November 2009 NOx BACT Analysis Study Supplemental Reports' Table 

### CA_3 14 

### for the hypothetical application ofSCR technologies atMRYS.

The preliminary concept assumed that mainboiler steam (high pressure, high temperature, around 1000°F, 2500 psig) would be diverted from the steam turbine's inletpiping, andbe routed for supply to 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 then be retumed to the boilerfeedwater treatment system for reuse. The 7 to 9 MW (was 4-5 MW) Unit I 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. Higher induceddraft booster fan discharge pressure requirement for pressure drop is not included. Use ofsteam for cleaning the in-duct steam coils' exterior surfaces orthe gas-to-gas heat exchangeronline during operationusing sootblowing is also not included in this estimate ofthe potential unit derate. The time requiredto modify the main steam

14 Ibid Reference 2, page 4-27.



### 4

### piping and othersteam turbine andboilerfeedwater treatment system components inthe steam eycle powergeneration and balance-of-plantsystems and boiler flue gas systems to accommodate sueh suggested ehauges would be lengthy. The duration ofan outage to implement such modifieations, andvalue oflost eleetrieal generating eapaeity, would be signifieant.

A similarpreliminmy high level eoneeptual review ofthe MRYS Unit2's steam eycle to investigate the feasibility ofusing steamto aehieve the estimated heatduty (2 reactors, 48.1 MMBTUlhreach to raise flue gas temperature from 535°F to 580°F) required for ahypothetieal application oflow-dust SCR technology was notperformed. Although sizing was not evaluated for MRYS Unit2, using a sealing factor (4-5 MW times the ratio of96.2 divided by 31.1 MMBTU/hrheat duty values 

### 477 M\V aiviaed 

### by 257 MWnameplate eapaeityfatings) to estimate Unit2's derate compared with Unit I's estimatedderate couldbe applied for an approximation. This would yield apotential Unit2 electrical generating outputcapacity derate

on the orderofmagnitude of8 10 M\V 12.4 to 15.5 MW for ahypothetieal application oflowdust SCR technology. Similarimpaets and issues as described for Unit 1 wouldbe expected for Unit2.

A similarpreliminary high level conceptual review ofthe MRYS Unit I's steamcycle to investigate the feasibility ofusing steamto achieve the estimated heatduty (I 

### reactor, 60.3 MMBTU/hreaeh 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 this case, using a scaling factor (ratio of60.3 dividedby 31.1 heatduties) to estimate Unit I's derate compared with Unit 1's estimated derate for ahypothetical application oflow-dust SCR technology couldbe applied for an approximation. This would yield apotential Unit I eleetrical generating output capacity derate on the orderofmagnitude of8 to 10 MW for ahypothetical applieation oftail end SCR teehnology. Similarimpaets and issues as previously described for Unit 1 would be expeeted.

A similarpreliminary high level conceptual review ofthe MRYS Unit 2's steam cycle to investigate the feasibility ofusing steam to aehieve the estimated heatduty (2 reactors, 50.8



### 5

### MMBTU/hreach to raise flue gas temperature from 520°F to 563"F) required for ahypothetical application oftail end SCR technology was notperformed. Although sizing was not evaluated for MRYS Unit 2, using a scaling factor (ratio of 101.6 divided by 31.1 heatduties) to estimate Unit2's derate compared with Unit l's estimated derate could be applicd for an approximation. This wouldyield apotential Unit2 electrical generating outputcapacity derate on the order of magnitude of 13 to 16 MW for ahypothetical application oftail end SCR technology. Similar impacts and issues as described for Unit I would be expected for Unit 2.

These estimates oflost electrical generation outputs come from boilermain steamusage, larger induced draft fan powerrequirements, and potential additional downtime associated with the flue gas reheating systems. Because the MRYS units' electrical energy generation outputcapacity is limitedby the steam energy production capacity ofeach boiler("boiler limited"), there is not "free capacity margin" available to offset the megawatt losses. Minnkotaalso 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 support the decision to selectnatural gas firing and reject the use of steam for flue gas reheating involving hypothetical applications oflow-dustandtail end SCR technologies at MRYS:

• Minnkota's previous experience with the use ofstcam for Unit 2's flue gas desulfurization system absorberoutlet flue gas reheat (for stackplume buoyancy) was not positive and the technique was abandoned in favor ofreheat via scrubberflue gas bypass. The ConsentDecree does not allow Minnkota to continue the use ofunscrubbed flue gas for reheating the stack gas 15



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

• High pressure/high temperature steam piping is expensive to procure and install, and requires special design to accommodate thermal growth and significantweight and

IS Ibid Reference number 5, April 24, 2006.



### 6

### dynamic loads withoutoverstress. There was insufficienttime available during the SCR cost estimate study to perform acomprehensive analysis ofpotential hanger supports, pipe sizing and routing from the main steam source to the multiple points ofuse and return ofcondensate to theboilerplant.

e 

### The deposits removed during cleaning ofthe in-duct steam coils fouled by particulate, aerosols, and ash products emitted fi·om theboilers and also removed from the gas-gas heat exchangerupstream ofthe flue gas reheaterwill be entrained in the flue gas stream entering the SCR reactor. This will require a "large particle ash screen" thatcreates more pressure drop than the direct-fired duct burner.

7

### Comparison ofAverage and Incremental Control Costs for MRYS NOx 

### BACT (forlowdust and tail end SCR alternatives) versus recentBACT determinations:
NDDH Request: "It 

### should be documented that the costs ofSCR at the M.R. Young Station are significantly beyond the range ofrecent costs normally associated with BACT for coal-fired powerplants (or BACT control costs in general) for the control ofnitrogen oxides (NSRManual ChapterB, Section IV.D.2.C)."

BMcD Response:
A review ofavailable information on "costs normally associated with BACT" for control ofNOx emissions from coal-fired powerplants indicates that very little documentation is published. Althoughboth the EPA's RACT BACT LAERClearinghouse (RBLC) [http://cfpub.epa.gov/rblc/htm/b102.cfm] and the EPA's "National Coal-Fired Utility Projects Spreadsheet" [available via http://www.epa.gov/ttn/catc/products.html#misc] include an assigned database field for enny of"Control Cost Effectiveness" in units of$/ton, neitherofthese sources contains much information. The assigned field where the data should be 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 "Response to Public Comments" for the Draft PSD Permit for Deseret Power Electric Cooperative's proposed 110 MW waste coal fired unit additionto 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 all pollutants) in which control cost effectiveness datawere identified in recentpermit actions involving BACT.

Burns & 

### McDonnell reviewed the cases identified by EPA Region 8 intheirresponse for the Deseret BACTcase to determine ifany data on "the cost associated with BACT" was available for cases involving NOx control for coal-firedboilers. Ofthe 13 cases for all pollutants identifiedby EPA Region 8, only one case involved the rejection ofthe "top" NOx control

16 See Reference number 10, pages 29-33.



### 8

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

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

Burns & 

### McDonnell was able to identify only two othercases, both also in North Dakota, in which the pennitrecord shows that the "top" NOx control technology for a coal-firedboilerwas rejected as having an excessive "control cost effectiveness". The relevantdata for these cases is tabulatedbelow, and compared to similarinformation as stated in the Supplemental NOx BACT reports prepared for MRYS Units I and 2.

9

### Previous Coal-Fired Boiler NOx BACT Determiuations Based on Cost Effectiveness

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 Agency NO MOU Oascoyne SCR $7545/ton $2926/ton 

### SNCR NO South South SCR $7640Iton $1690/ton 

### SNCR Heart Heart Coal LLC NO ORE Spiritwood SCR $7640/ton 

### $1843/ton 

### SNCR

As shown in the table above, for coal-firedboilers the "average cost effectiveness ofBACT for NOx" as established inprevious permitactions ranges from $1690/ton 

### to $2926/ton. 

### By comparison, the estimated cost 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 thc control costofthe technology established as BACT using the "top down" process.

10

### Control Cost Data 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 Technolo!!v as BACT MRYS Unit I Low- $3,586/ton 

### $1,265/ton MRYS Unit I Dust orTail End SCR to SNCRwith ASOFA with ASOFA $5,969/ton 

### MRYS Unit 2 Low- $3,859/ton $1,240/ton 

### MRYS Unit2 DustorTail End SCR to SNCR with ASOFA withASOFA $6,597/ton



### In the case ofMRYS Units I and 2, and taking the range ofcontrol costs for SCR(TESCR and LDSCR) with ASOFA as presented in the Supplemental NOx BACT reports (shown above), the ratio between the costofthe technology proposed forrejection on acostbasis to the cost ofthe technology proposed as BACT for the MRYS units is quite similarto that seen in previous permit actions. For Unit 1, the costratio ranges from 2.8 to 4.7. ForUnit 2, the costratio ranges from 3.1 to 5.3. Thus itappears thatthe samerationale thatwas used to reject SCRtechnology as being "excessively costly on a $/ton 

### control costbasis" in the case ofthese otherthree North Dakota BACTdeterminations should also apply to the case ofMRYS.

II

### REFERENCES

1. North Dakota DepartmentofHealth, Environmental Health Section, Division ofAir Quality letterby Terry L. 

### O'Clair, P.E. to John Graves, Minnkota PowerCooperative, Re: BACTCostEstimate, datedNovember 25, 2009.
2. 

### NO

### xBestAvailable Control Technology Analysis Study

- Supplemental Report for Milton R. Young Station Unit 

### 1 for Minnkota PowerCooperative, Inc., November, 2009; and a separate NO

### x BACT Analysis Study

- Supplemental Report for Milton 

### R. Young Station Unit 2 for Minnkota PowerCooperative, Inc. and Square Butte Eleetrie Cooperative, November 2009, submitted

### by Minnkota to North Dakota Department ofHealth on November 12, 2009.
3. 

### North Dakota Department ofHealth, Environmental Health Section, Division ofAir Quality letterby Terry 

### L. O'Clair, P.E. to John Graves, Minnkota Power Cooperative, Re: Milton R. Young Station BACTDetermination, dated July 15,2009, andRe: Request/or 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 for Milton R. Young Station Unit 2 Square Butte Electric Cooperative", October 2006, submitted to EPA Region 8 and EPA Office of Regulatory Enforcement, and ineluded with the "BART DETERMINAnON STUDY for Milton R. Young Station Unit I 

### and 2 Minnkota PowerCooperative, Inc." Final Report, Oetober2006 submittedby Minnkota to North DakotaDepartmentofHealth.
5. ConsentDecree filed in the United States DistrictCourtForThe DistrictOfNorth Dakota, United States OfAmerica and State OfNorth Dakota, Plaintiffs, v. Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, Defendants, Civil Action No.l:06-CV-034, filed April 24, 2006.

6. 

### ERG Memorandnm to EPA Region 8 

### and EPA Office ofRegulatOlY Enforcement, Review andCritique of the Burns & 

### McDonnellNOxBACTAnalysisforthe Milton R. Young Station OperatedbyMinnlwta Power(October2(06), written by Roger Christman, Eastern Research Group, Inc., January 8, 2007, faxcd byNorth Dakota DepartmentofHealth to Minnkota, Janumy 9, 2007.
7. EPA Region 

### 8PreliminGlyAnalysis of Burns & 

### McDonnellBACTAnalysis ForNitrogen Oxide atMilton R. Young Station, Units J

### and2

### JanuGl)'8, 

### 2007faxed by North Dakota Department ofHealth to Minnkota, Janumy 9, 2007.
8. 

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

### EPA AirPollution Control Cost Manual- Sixth Edition (EPA/452/B-02-00l), Janumy 2002.
10. Re;ponse to Public Comments on DraftAirPollution ControlPrevention o/Signi{Icant Deterioration (PSD) Permit to Construct[PermitNo. PSD-OU-0002-04.00}, U.S. EPA Region 8, August 30, 2007.

12

### ATTACHMENTS

I. 

### "SharedFacilities Total Capital Investmcnt" and "Stand Alone Total Capital Invcstmcnt" cost estimatc tables for Low-DustandTail End Selective Catalytic Reduction altematives, as supporting information regarding Unit I and Unit2 at Milton R. Young Station, November, 2009, Reference number 2, NOxBestAvailable Control Technology Analysis StudySupplemental Reports for Minnkota PowerCooperative, Inc., dated December7, 2009.
2. "Sharcd Facilities Total Annual Costs" and "Stand Alone Total Annual Costs" tables for Low-Dust and Tail End Selectivc Catalytic Reduction alternatives, as supporting information rcgarding Unit I and Unit2 at Milton R. Young Station, November, 2009, Reference number 2, NOxBestAvailable Control Technology Analysis Study

- Supplemcntal Reports for Minnkota Powcr Cooperative, Inc., dated Deecmber7,2009.



### INDEX OF REVISIONS Strikethrough indicates text that has been deleted. Underline indicates text thathas been inserted orrevised. The following pages in the February 2010 version include revisions:

CoverPage Page 4 Page 5 Page I I Attachment #1, page 2, page 3, and page 4



### 13Milton R. Young Station Unit 1 and Unit 2 Estimates of Total Capital Investmentfor Low Dust and Tail End Selective Catalytic Reduction Alternatives Best Available Control Technology· Supplemental Analysis Revised February 2010 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) Auxiiiaries/Balance of Piant $ 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) Freiaht 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 Continaencv $ 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. 

### Burns & McDonnell 

### 2/1112010Shared 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 air compressors, induced draft boosterfan(s) and dampers, ureato-ammonia conversion flue gas reheat eguipment with natural 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. (Revised February 201 0)
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, i.e. 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 Burns 

### & McDonnell 

### 2/1 I120IOMilton R. Young Station Unit 1 and Unit 2 Estimates of Total Capital Investment for Low Dust and Tail End Selective Catalytic Reduction Alternatives Best Available Control Technology· Supplemental Analysis Revised Februarv 2010 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 Capitai 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) Freiaht 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 (Revised Feb. 2010) $ 8,399,220 $ 14,558,077 $ 9,489,326 $ 16,195,648 Nole 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 If) Paintinq 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) Pricing Contingency (Rev. 2/10) $ 15.436,040 $ 22,988,134 $ 19.529.462 $ 29,593.180 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

Minnkota Power Cooperative, Inc. 

### 3 Burns 

### & McDonnell 

### 2/11/2010Stand 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**II~e** gas reheat eguipment with natural 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. (Revised Februarv 2010)
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 ofall 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, i.e. 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 ofanticipated 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 Power Cooperative, Inc. 4 

### Burns & 

### McDonnell Z/I IIZ0I0Milton 

### 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 Dust U2 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
LEVELIZED TOTAL ANNUALIZED 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



### Minnkota Power Cooperative, Inc. Burns & 

### McDonnell 

### 12/1112009Shared 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 of direct costs, indirect costs, and recoverycredits (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 recoverycosts, 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. Main!. 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, if concentrated 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 everytwo 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 layerdue to assuming regular depth layers instead ofdeep layers recommended by vendor. Note 7: Annual catalyst replacement costs for "Scenario B" are assumed to be based three layers per reactor everyyear (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 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 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 recoveryare the same for Scenario A and Scenario B operations. See Appendix C in the 2006 NOx BACT Analysis Study reports for details. The capital recoveryfactor used to calculate the annual costs is 0.087185. Capital recoverycosts 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.


### MinnkotaPowerCooperative, Inc. 2 Burns 

### & 

### McDonnell 12/11/2009These numbers are the same Levelized Total Annualized Costs for Low-Dust and Tall End SCRs in the November2009 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.



### Minnkota Power Cooperative, Inc. 3 Burns 

### & McDonnell 

### 12/1112009Milton 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



### Minnkota PowerCooperative, Inc. 4 

### Bums & 

### McDonnell 

### 12/1112009Stand Alone (SA) represents estimated costs if SCR equipment is retrofitted to both boilers independently. This table includes values that are identified in the EPA OAOPS 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 OAOPS manual Total Annual Costs consist of direct 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 for ASOFA 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 November 2009 NOx BACT Analysis Study Supplemental Reports for details. Note 4: Annual water costs were not calculated, but may be more than zero, if concentrated 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 OAOPS 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 layerdue to assuming regular depth layers instead of deep layers recommended by vendor. 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 OAOPS 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 labor for 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 PowerCooperative, Inc. 

## 5 Bums & 

### McDonnell 

### I2/I 1/2009These 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.



### Minnkota Power Cooperative, Inc. 6 Burns 

### & 

### McDonnell 

### I2/I 112009