MINNKOTA POWER COOPERATIVE, Inc. and

SQUARE BUTTE ELECTRIC COOPERATIVE

RESPONSES TO NDDH REQUEST

NOx BACT ANALYSIS STUDY

MILTON R. YOUNG STATION UNIT I and UNIT 2

REGARDING SCR ECONOMIC FEASIBILITY

December II, 2009

Revised February 2010 (refer to page 13 for Index of Revisions)

North Dakota Department of Health's Environmental Health Section, Division ofAir Quality has

requested' that Minnkota Power Cooperative Inc. ("Minnkota" or "MPC") provide more detailed

and comprehensive cost data following their reviews ofthe Best Available Control Technology

(BACT) Analysis Study - Supplemental reports2 submitted on November 12, 2009 for control of

nitrogen oxides (NOx) emissions from existing Unit 1 and Unit 2 at Milton R. Young Station

("MRYS"). A detailed breakdown of capital costs and operation and maintenance costs for

hypothetical applications oflow-dust and tail end SCR alternatives, assuming that they are

technically feasible to apply at MRYS as NDDH has recently advised), are attached. Responses

to the use ofsteam from the main boilers for reheat ofthe flue gas are provided. A comparison

of control costs from relevant recent BACT Determinations versus the estimated control costs of

hypothetical applications oflow-dust and tail end SCR technologies at MRYS included with the

November 2009 Supplemental Reports is also provided.

Bums & McDonnell (B&McD) was retained by MPC as an independent consultant to perform

the referenced NOx BACT Analysis Study4 ofMinnkota's Unit 1 and Square Butte Electric

Cooperative's Unit 2 at the Milton R. Young Station (MRYS) in accordance with the

requirements of a Consent Decree (CDi. The November 2009 NOx BACT Analysis Study

Supplemental Reports were generated in response to the NDDH's request6 to see Steps 3 and

1 See Reference number I, November 25, 2009.

2 See Reference number 2, November 12, 2009.

J See Reference number 3, July 15,2009. SCR technology is considered technically infeasible by Minnkota for application

at MRYS per the October 2006 NOx BACT Analysis Study report and subsequentsubmittals in response to comments by the

NDDH, EPA, DOJ, and other parties, including the November 2009 Snpplemental NOx BACT Analysis Study reports.

4 See Reference number 4, October 2006.

5 See Reference number 5, April 24, 2006.

6 Ibid Reference number3, July 15,2009. SCR technology is considered technically infeasible by Minnkota for application

at MRYS per the October 2006 NOx BACT Analysis Study report and subsequentsubmittals in response to comments by the

NDDH, EPA, DOJ, and other parties, iucluding the November 2009 Supplemental NOx BACT Analysis Study reports.
4 ofthe BACT analysis process

7 be performed and include low-dust and tail end SCR

alternatives.

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

Maintenance Cost Summary:

NDDH Request: "A detailed breakdown of capital 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 page 4-16" of the November 2009 NOx BACT Analysis Study

Supplemental reports are intended to represent the major components (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 direct match to each of the bulleted items included in the reports. Thus

it is not possible to provide a cost breakdown in that format. In lieu of a breakout directly

corresponding to the bulleted items, Burns & McDonnell has modified our cost estimate

spreadsheets for the four "shared facilities" as well as the four "stand alone" hypothetical

applications of SCR technologies analyzed, to reflect the cost tabulation format used in the "SCR

Chapter" ofthe "EPA Air Pollution Control Cost Manual- Sixth Edition" (Section 4.2; Chapter

2).

Please see the attached "Shared Facilities Total Capital Investment" and "Stand Alone Total

Capital Investment" cost estimate tables that follow the outline of Table 2.5 in the SCR Chapter

of EPA's Control Cost Manual9 for these hypothetical applications ofSCR technologies

analyzed. Note that this SCR Chapter ofthe EPA Control Cost Manual is intended for

estimating costs of high dust SCRs, as it states on page 2-41 that "costs for the tail-end

arrangement, however, cannot be estimated from this report because they are significantly higher

7 See Reference number 8, October 1990.

, Ibid Reference number 1, November 25, 2009.

9 Ibid Reference number 9, 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 Chapter of

the Control Cost Manual also states that "the cost methodology is valid for a low-dust SCR

system because the cost reductions are expected to be within the range of uncertainty 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 Supplemental NOx BACT reports

for MRYS because ofthe flue gas reheating required.

Also see attached tables of estimated "Shared Facilities Total Annual Costs" and "Stand Alone

Total Annual Costs" that include the items described in pages 2-44 through 2-49 of the SCR

Chapter of EPA's Control Cost Manual!2 for an SCR application. As previously mentioned, the

equations in the SCR Cost Manual's cost methodology were not used for estimating annual costs

of electrical power consumption, reagent usage, and catalyst replacements. Note that budgetaty

vendor quotes were the primary source of information used to calculate these estimated annual

costs of the hypothetical applications of SCR technologies analyzed.

Use of Steam from the main boilers for reheat of flue gas (for low-dust and tail end SCR

alternatives):

NDDH Request: 'The use ofsteam from the main boilers for the flue gas reheat should also be

addressed. "

BMcD Response:

Natural gas-fired flue gas reheat is shown in the SCR Chapter of EPA's Control Cost Manual for

an SCR application ofa tail end SCR examplelJ, so the use ofsuch reheat systems is not unique

to Minnkota's study. MPC selected natural gas firing and rejected the use ofsteam for flue gas

reheating for the evaluation of hypothetical applications of low-dust and tail end SCR

technologies at MRYS. For the SCR cost estimate study by Burns & McDonnell, it was

necessary to establish the scope conceptual design basis for estimating the costs associated with

installation and operation and maintenance ofthe hypothetical applications oflow-dust and tail

10 Ibid Reference number 9, Section 4.2, Chapter 2, page 2-41, January 2002.

11 Ibid Reference number 9, Section 4.2, Chapter 2, page 2-41, January 2002.

"Ibid Reference number 9, Section 4.2, Chapter 2, pages 2-44 - 2-49, January 2002.

13 Ibid Reference number 9, Section 4.2, Chapter 2, page 2-21, January 2002.

3
end SCR technologies. Minnkota's selection of natural gas-fired flue gas reheating for these

conceptual designs and cost estimates was made in order to avoid additional loss of unit

electrical energy generation output capacity.

A preliminalY high level conceptual review ofthe MRYS Unit I steam cycle was done by

Minnkota to investigate the feasibility of using steam to achieve the estimated heat duty (was

31.1 but is now 54.5 million BTU/hI' to raise flue gas temperature from ~"'F--535°F to 580°F for

one reactor) required for the hypothetical application oflow dust SCR technology. This

preliminalY review indicated that using steam for this service appeared to be feasible but would

result in a unit electrical output capacity derate of 4 5 M\'i 7 to 9 MW. This is because the hightemperature/high-pressure main steam extracted li'om the boiler for flue gas reheat system would

not pass through any stages ofthe high/intermediate/low pressure steam turbines, so less net

electrical energy would be produced.

The value oflost electrical generating capacity was not calculated, but the steady-state long term

operation impact is believed to be approximately 90% or more 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 at MRYS.

The preliminary concept assumed that main boiler steam (high pressure, high temperature,

around 1000°F, 2500 psig) would be diverted from the steam turbine's inlet piping, and be

routed for supply to the flue gas heating system. This would involve the heating steam supplied

being condensed using heating coils inserted into the flue gas ductwork. The condensate liquid

would then be retumed to the boiler feedwater treatment system for reuse. The 7 to 9 MW (was

4-5 MW) Unit I derate for a hypothetical application of low-dust SCR technology does not

include additional downtime due to tube leaks or other maintenance issues associated with the

flue gas reheat steam system. Higher induced draft booster fan discharge pressure requirement

for pressure drop is not included. Use ofsteam for cleaning the in-duct steam coils' exterior

surfaces or the gas-to-gas heat exchanger online during operation using soot blowing is also not

included in this estimate ofthe potential unit derate. The time required to modify the main steam

14 Ibid Reference 2, page 4-27.

4
piping and other steam turbine and boiler feedwater treatment system components in the steam

eycle power generation and balance-of-plant systems and boiler flue gas systems to

accommodate sueh suggested ehauges would be lengthy. The duration of an outage to

implement such modifieations, and value oflost eleetrieal generating eapaeity, would be

signifieant.

A similar preliminmy high level eoneeptual review ofthe MRYS Unit 2's steam eycle to

investigate the feasibility of using steam to aehieve the estimated heat duty (2 reactors, 48.1

MMBTUlhr each to raise flue gas temperature from 535°F to 580°F) required for a hypothetieal

application oflow-dust SCR technology was not performed. Although sizing was not evaluated

for MRYS Unit 2, using a sealing factor (4-5 MW times the ratio of 96.2 divided by 31.1

MMBTU/hr heat duty values 477 M\V aiviaed by 257 MW nameplate eapaeity fatings) to

estimate Unit 2's derate compared with Unit I's estimated derate could be applied for an

approximation. This would yield a potential Unit 2 electrical generating output capacity derate

on the order of magnitude of 8 10 M\V 12.4 to 15.5 MW for a hypothetieal application oflowdust SCR technology. Similar impaets and issues as described for Unit 1 would be expected for

Unit 2.

A similar preliminary high level conceptual review ofthe MRYS Unit I's steam cycle to

investigate the feasibility of using steam to achieve the estimated heat duty (I reactor, 60.3

MMBTU/hr eaeh to raise flue gas temperature from 520°F to 563°F) required for a hypothetical

application oftail end SCR technology was not performed. Although sizing was not evaluated

for this case, using a scaling factor (ratio of 60.3 divided by 31.1 heat duties) to estimate Unit I's

derate compared with Unit 1's estimated derate for a hypothetical application oflow-dust SCR

technology could be applied for an approximation. This would yield a potential Unit I eleetrical

generating output capacity derate on the order of magnitude of 8 to 10 MW for a hypothetical

applieation oftail end SCR teehnology. Similar impaets and issues as previously described for

Unit 1 would be expeeted.

A similar preliminary high level conceptual review of the MRYS Unit 2's steam cycle to

investigate the feasibility of using steam to aehieve the estimated heat duty (2 reactors, 50.8

5
MMBTU/hr each to raise flue gas temperature from 520°F to 563"F) required for a hypothetical

application oftail end SCR technology was not performed. Although sizing was not evaluated

for MRYS Unit 2, using a scaling factor (ratio of 101.6 divided by 31.1 heat duties) to estimate

Unit 2's derate compared with Unit l's estimated derate could be applicd for an approximation.

This would yield a potential Unit 2 electrical generating output capacity derate on the order of

magnitude of 13 to 16 MW for a hypothetical application oftail end SCR technology. Similar

impacts and issues as described for Unit I would be expected for Unit 2.

These estimates of lost electrical generation outputs come from boiler main steam usage, larger

induced draft fan power requirements, and potential additional downtime associated with the flue

gas reheating systems. Because the MRYS units' electrical energy generation output capacity is

limited by the steam energy production capacity of each boiler ("boiler limited"), there is not

"free capacity margin" available to offset the megawatt losses. Minnkota also cannot increase

boiler hourly heat inputs (coal firing rates) in order to compensate for the decrease in output

because the increased emissions from higher firing rates are not permitted.

Additional arguments that support the decision to select natural gas firing and reject the use of

steam for flue gas reheating involving hypothetical applications oflow-dust and tail end SCR

technologies at MRYS:

• Minnkota's previous experience with the use ofstcam for Unit 2's flue gas

desulfurization system absorber outlet flue gas reheat (for stack plume buoyancy) was not

positive and the technique was abandoned in favor ofreheat via scrubber flue gas bypass.

The Consent Decree does not allow Minnkota to continue the use of unscrubbed 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 insufficient time available during the SCR cost estimate

study to perform a comprehensive analysis of potential 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 significant weight and

IS Ibid Reference number 5, April 24, 2006.

6
dynamic loads without overstress. There was insufficient time available during the SCR

cost estimate study to perform a comprehensive analysis of potential hanger supports,

pipe sizing and routing from the main steam source to the multiple points of use and

return of condensate to the boiler plant.

e The deposits removed during cleaning ofthe in-duct steam coils fouled by particulate,

aerosols, and ash products emitted fi·om the boilers and also removed from the gas-gas

heat exchanger upstream ofthe flue gas reheater will be entrained in the flue gas stream

entering the SCR reactor. This will require a "large particle ash screen" that creates more

pressure drop than the direct-fired duct burner.

7
Comparison of Average and Incremental Control Costs for MRYS NOx BACT (for lowdust and tail end SCR alternatives) versus recent BACT determinations:

NDDH Request: "It should be documented that the costs of SCR at the M.R. Young Station are

significantly beyond the range ofrecent costs normally associated with BACT for coal-fired

power plants (or BACT control costs in general) for the control of nitrogen oxides (NSR Manual

Chapter B, Section IV.D.2.C)."

BMcD Response:

A review of available information on "costs normally associated with BACT" for control ofNOx

emissions from coal-fired power plants indicates that very little documentation is published.

Although both the EPA's RACT BACT LAER Clearinghouse (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,

neither ofthese sources contains much information. The assigned field where the data should be

entered is blank in the vast majority of cases entered in these databases.

This dearth of data on BACT cost effectiveness was encountered by 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 addition to the Bonanza Power

Plant16 In seeking to defend the cost basis for its rejection of a control technology as BACT,

EPA Region 8 was able to identify only 13 cases (total for all pollutants) in which control cost

effectiveness data were identified in recent permit actions involving BACT.

Burns & McDonnell reviewed the cases identified by EPA Region 8 in their response for the

Deseret BACT case to determine if any data on "the cost associated with BACT" was available

for cases involving NOx control for coal-fired boilers. Ofthe 13 cases for all pollutants

identified by 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 what was identified as "excessive cost". This was the case of

MDU's proposed Gascoyne project in North Dakota. The inability of EPA Region 8 to identify

more cases in which the permit record clearly establishes the level of NOx control costs

illustrates the difficulty ofthis task.

Burns & McDonnell was able to identify only two other cases, both also in North Dakota, in

which the pennit record shows that the "top" NOx control technology for a coal-fired boiler was

rejected as having an excessive "control cost effectiveness". The relevant data for these cases is

tabulated below, and compared to similar information 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-fired boilers the "average cost effectiveness of BACT for

NOx" as established in previous permit actions ranges from $ 1690/ton to $2926/ton. By

comparison, the estimated cost for NOx 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 cost ofthe

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 of Technology BACT

"Top" Recommended

Technolo!!v as BACT

MRYS Unit I Low- $3,586/ton $1,265/ton MRYS Unit I

Dust or Tail End SCR to SNCR with ASOFA

with ASOFA $5,969/ton

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

Dust or Tail End SCR to SNCR with ASOFA

with ASOFA $6,597/ton

In the case of MRYS Units I and 2, and taking the range of control costs for SCR (TESCR and

LDSCR) with ASOFA as presented in the Supplemental NOx BACT reports (shown above), the

ratio between the cost ofthe technology proposed for rejection on a cost basis to the cost ofthe

technology proposed as BACT for the MRYS units is quite similar to that seen in previous permit

actions. For Unit 1, the cost ratio ranges from 2.8 to 4.7. For Unit 2, the cost ratio ranges from 3.1

to 5.3. Thus it appears that the same rationale that was used to reject SCR technology as being

"excessively costly on a $/ton control cost basis" in the case ofthese other three North Dakota

BACT determinations should also apply to the case of MRYS.

II
REFERENCES

1. North Dakota Department of Health, Environmental Health Section, Division of Air

Quality letter by Terry L. O'Clair, P.E. to John Graves, Minnkota Power Cooperative, Re:

BACT Cost Estimate, dated November 25, 2009.

2. NOx Best Available Control Technology Analysis Study - Supplemental Report for Milton

R. Young Station Unit 1for Minnkota Power Cooperative, Inc., November, 2009; and a

separate NOx BACT Analysis Study - Supplemental Report for Milton R. Young Station

Unit 2 for Minnkota Power Cooperative, Inc. and Square Butte Eleetrie Cooperative,

November 2009, submitted by Minnkota to North Dakota Department of Health on

November 12, 2009.

3. North Dakota Department of Health, Environmental Health Section, Division of Air

Quality letter by Terry L. O'Clair, P.E. to John Graves, Minnkota Power Cooperative, Re:

Milton R. Young Station BACT Determination, dated July 15,2009, and Re: Request/or

Time Extension, dated August 7, 2009.

4. "BACT Analysis Study for Milton R. Young Station Unit 1 Minnkota Power Cooperative,

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 Power Cooperative, Inc." Final Report,

Oetober 2006 submitted by Minnkota to North Dakota Department of Health.

5. Consent Decree filed in the United States District Court For The District Of North Dakota,

United States Of America and State Of North 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 of RegulatOlY Enforcement, Review

and Critique ofthe Burns & McDonnell NOx BACT Analysisfor the Milton R. Young

Station Operated by Minnlwta Power (October 2(06), written by Roger Christman, Eastern

Research Group, Inc., January 8, 2007, faxcd by North Dakota Department of Health to

Minnkota, Janumy 9, 2007.

7. EPA Region 8 PreliminGly Analysis ofBurns & McDonnell BACTAnalysis For Nitrogen

Oxide at Milton R. Young Station, Units J and 2 JanuGl)' 8, 2007 faxed by North Dakota

Department of Health to Minnkota, Janumy 9, 2007.

8. EPA New Source Review Workshop Manual, Prevention of Significant Deterioration and

Nonattainment Area Permitting, Draft Oetobcr 1990 (The "NSR Manual").

9. EPA Air Pollution Control Cost Manual- Sixth Edition (EPA/452/B-02-00l), Janumy

2002.

10. Re;ponse to Public Comments on Draft Air Pollution Control Prevention o/Signi{Icant

Deterioration (PSD) Permit to Construct [Permit No. PSD-OU-0002-04.00}, U.S. EPA

Region 8, August 30, 2007.

12
ATTACHMENTS

I. "Shared Facilities Total Capital Investmcnt" and "Stand Alone Total Capital Invcstmcnt" cost

estimatc tables for Low-Dust and Tail End Selective Catalytic Reduction altematives, as

supporting information regarding Unit I and Unit 2 at Milton R. Young Station, November,

2009, Reference number 2, NOx Best Available Control Technology Analysis StudySupplemental Reports for Minnkota Power Cooperative, Inc., dated December 7, 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 Unit 2 at Milton R. Young Station, November, 2009, Reference number

2, NOx Best Available Control Technology Analysis Study - Supplemcntal Reports for

Minnkota Powcr Cooperative, Inc., dated Deecmber 7,2009.

INDEX OF REVISIONS

Strikethrough indicates text that has been deleted.

Underline indicates text that has been inserted or revised.

The following pages in the February 2010 version include revisions:

Cover Page

Page 4

Page 5

Page I I

Attachment #1, page 2, page 3, and page 4

13
Milton 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 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

2/1112010
Shared Facilities (SF) represents estimated costs if SCR equipment is retrofitted to both boilers concurrently.

This table follows outline of Table 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 of this equipment.

Note 2: Does not include spare catalyst in purchased SCR equipment costs.

Note 3: Includes service air and sootblower air compressors, induced draft booster fan(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 of this 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 of Total 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 higher than anticipated. Note: this does not intend to

cover pricing increases over time, 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 over time.

Note 23: Interest During Construction (or Allowance 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 November 2009 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 I120IO
Milton 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

2/11/2010
Stand Alone (SA) represents estimated costs if SCR equipment is retrofitted to both boilers independently.

This table follows outline of Table 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 of this equipment.

Note 2: Does not include spare catalyst in purchased SCR equipment costs.

Note 3: Includes service air and sootblower air compressors, induced draft booster fan(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 of this 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 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 of Total 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 higher than anticipated. Note: this does not intend to

cover pricing increases over time, 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 over time.

Note 23: Interest During Construction (or Allowance 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 November 2009 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 IIZ0I 0
Milton R. Young Station Unit 1 and Unit 2

Estimates of Total 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 labor for 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

12/1112009
Shared 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 of the formulas provided in the OAQPS 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 of flue 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 of the SCR equipment and

auxiliary equipment related to the SCR systems, not including catalyst replacement costs. Main!. 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 $379.29 per ton in 2006$.

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 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% per year 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 November 2009 NOx BACT Analysis

Study Supplemental Report underestimate the cost per layer due 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 per year (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 lower than "Scenario A" due to fewer

annual hours of operation 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 Power Cooperative, Inc. 2 Burns & McDonnell

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

November 2009 NOx BACT Supplemental Analysis Tables 4-6SF, 4-7SF, 4-8SF, and 4-9SF. The

capital recovery costs of the 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

12/1112009
Milton R. Young Station Unit 1 and Unit 2

Estimates of Total 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 labor for 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 Power Cooperative, Inc. 4 Bums & McDonnell

12/1112009
Stand 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 of the 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 of flue 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 of the 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 $379.29 per ton in 2006$.

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% per year 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 November 2009 NOx BACT Analysis

Study Supplemental Report underestimate the cost per layer due 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 per year (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 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 lower than "Scenario A" due to fewer

annual hours of operation 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 Power Cooperative, Inc. 5 Bums & McDonnell

I2/I 1/2009
These numbers are the same Levelized Total Annualized Costs for Low-Dust and Tail End SCRs in the

November 2009 NOx BACT Supplemental Analysis Tables 4-6SA, 4-7SA, 4-8SA, and 4-9SA. The

capital recovery costs of the 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