1 

MINNKOTA POWER COOPERATIVE, Inc. and 

SQUARE BUTTE ELECTRIC COOPERATIVE 

FOLLOWUP RESPONSES TO PRESENTATION and 

NDDH REQUEST FOR ADDITIONAL INFORMATION 

SUPPLEMENTAL NOx BACT ANALYSIS STUDY 

MILTON R. YOUNG STATION UNIT 1 and UNIT 2 

REGARDING SCR ECONOMIC FEASIBILITY 

February 11, 2010

North Dakota Department of Health’s Environmental Health Section, Division of Air Quality has 

requested1

 that Minnkota Power Cooperative Inc. (“Minnkota” or “MPC”) provide additional information 

clarifying the written response submitted December 11, 20092

 that provided detailed and comprehensive 

cost data following the NDDH’s and U.S. EPA’s reviews of the Best Available Control Technology 

(BACT) Analysis Study – Supplemental Reports3

 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). 

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

referenced 2006 NOX BACT Analysis Study4

 of Minnkota’s Unit 1 and Square Butte Electric 

Cooperative’s Unit 2 at the Milton R. Young Station in accordance with the requirements of a Consent 

Decree (CD)5

. Burns & McDonnell also performed the November 2009 Supplemental NOX BACT 

Analysis Study and generated the referenced reports for each MRYS boiler in response to the NDDH’s 

request6

 to see Steps 3 and 4 of the BACT analysis process7 include low-dust and tail end SCR 

alternatives, assuming that they are technically feasible to apply at MRYS as NDDH has recently advised8

. 

Information supplementing the previously-provided detailed breakdown of capital costs and operation and 

maintenance costs for hypothetical applications of low-dust and tail end SCR alternatives, and their 

subsequent presentation to NDDH, are attached. 

 

1

 See Reference number 1, January 11, 2010. 

2

 See Reference number 2, December 11, 2009. 

3

 See Reference number 3, November 12, 2009. 

4

 See Reference number 4, October 2006. 

5

 See Reference number 5, April 24, 2006. 

6

 See Reference number 6, 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 subsequent submittals in response to comments by the NDDH, 

EPA, DOJ, and other parties, including the November 2009 Supplemental NOx BACT Analysis Study reports. 7

 See Reference number 7, October 1990. 

8

 Ibid Reference number 6, 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 subsequent submittals in response to comments by the NDDH, 

EPA, DOJ, and other parties, including the November 2009 Supplemental NOx BACT Analysis Study reports.
 2 

NOx BACT Analysis Study Supplemental Reports: 

NDDH Request #1: How were the SCR reactors sized and the catalyst volume determined and 

what target NOx control efficiency was used to size the catalyst? How was 

the cost of the catalyst determined? 

BMcD Response: 

The same SCR system supplier that is providing the low-dust SCR equipment for the WE Energies South Oak 

Creek project in Wisconsin was asked to provide a budgetary equipment proposal for both low-dust and tail 

end SCR arrangements for each unit at MRYS. A lignite coal analysis (proximate, ultimate, and coal ash) 

and process design basis (boiler fuel heat input rates, excess air percentages, flue gas volumetric flows, 

temperatures and gas species contents) were included with the request. An assumed inlet and outlet NOx 

concentration was also provided, with a nominal 85% reduction from 0.5 lb/mmBtu requested. This SCR 

system supplier sized the SCR reactor, the SCR gas-to-gas heat exchange equipment (SCR GGH), and related 

ductwork. The initial catalyst charge for each reactor was included in the lump-sum equipment price 

proposal. The SCR system supplier did not disclose the specific volume of catalyst to be provided nor the 

specific manufacturer or type of catalyst (i.e. honeycomb, plate, etc.). Due to the proprietary nature of this 

SCR conceptual design and budgetary equipment pricing effort, this work was performed by the SCR system 

supplier with the understanding that it was confidential. Refer to Burns & McDonnell’s response to NDDH 

Request #7 for additional information. 

Two SCR catalyst suppliers provided budgetary replacement catalyst quotes, including catalyst volume, 

catalyst pitch, catalyst type, and arrangement of catalyst modules, based on preliminary process design 

provided by an SCR process design consultant. The design used for these catalyst supplier proposals was 

based on 90% overall NOx reduction across the SCR system. The catalyst suppliers also provided cost 

proposals for the replacement catalyst. One supplier provided a cost of replacement catalysts in terms of 

$/m3

. Due to the proprietary nature of this SCR reactor sizing and budgetary catalyst pricing effort, this work 

was performed by the SCR catalyst suppliers with the understanding that it was confidential. Refer to Burns 

& McDonnell’s response to NDDH Request #7 for additional information. 

NDDH Request #2: Anhydrous ammonia appears to be a less expensive reagent than urea for 

the SCR system due to local availability. A justification must be supplied 

for electing urea over anhydrous ammonia. 

BMcD Response: 

Aqueous urea solution was selected because of health and safety issues related to the use of ammonia, 

including site constraints involving over-the-road transport, on-site unloading and storage. MRYS does not 
 3 

have rail access, and is adjacent to a lake used for condenser cooling water and process water supplies. 

Public access to the lake is allowed. Anhydrous ammonia and aqueous ammonia are classified as hazardous 

chemicals per Clean Air Act Section 112 (r). This requires extensive emergency planning. Transport and 

handling of ammonia is restricted by the United States Department of Homeland Security and the Department 

of Transportation through the Rail Security Act. The U.S. EPA has determined that a toxic radius of a spill to 

be between 5 and 7 miles for anhydrous ammonia and 1 to 2 miles for aqueous ammonia9

. 

NDDH Request #3: Support must be provided for the catalyst cleaning/replacement outage 

periods. This should include an explanation of the method used to estimate 

the outage time and clarification whether the outage time includes the 

regular outage period. 

BMcD Response: 

Burns & McDonnell and Minnkota queried SCR catalyst suppliers, process design consultants, utility 

construction and maintenance contractors, and utility personnel at U.S. coal-fired plants with operating SCRs 

to provide input into the estimation of time associated with catalyst installation into the empty (spare) layer of 

the reactor, and to remove dirty catalyst and install fresh catalyst in its place. The responses indicated that 

there is a broad range of experiences based on limited amounts of user and vendor data on this issue. The 

range of experience is due to the site-specific conditions and design-specific features of the reactor catalyst 

access doors’ locations and sizes, module arrangement, hoisting equipment, staging areas and platforms, labor 

availability and familiarity. The general lack of data is due to the relative newness of many SCR installations 

currently operating at coal-fired powerplants in the United States that have not accumulated significant 

operating time and so have not required significant numbers of catalyst changeouts. 

Catalyst replacement activities by current coal-fired powerplant users are typically scheduled during major 

boiler outages that are 18-36 months apart. The SCR catalyst changeout is usually not a schedule-critical 

activity during such outages. The catalyst changeout time required depends on how many modules are 

involved, and whether a single shift of personnel or multiple shifts per day are engaged in the work. 

For the hypothetical application of low-dust and tail end SCR technologies at MRYS, most of the catalyst 

changeouts were assumed to coincide with boiler fireside cleaning outages, which are historically 

approximately 4 days in duration, three or four times per year, depending on the boiler involved. Because of 

the use of high pressure water to remove boiler deposits during these cleanings, the air exhausted from the 

boilers through the flue gas ductwork to the chimneys during these times contains moisture and particulate. 

 

9

 See Reference 8. 
 4 

Catalyst vendors have advised that this air stream is not suitable for passing through an SCR reactor filled 

with catalyst. This will require an SCR reactor bypass to be provided for use during these outages. 

Before catalyst changeout operations can begin, the large volume of catalyst and supporting structural steel 

must be cooled down sufficiently to allow personnel to safely enter the reactor to gain access to remove any 

ash accumulations. The means and equipment required to remove the catalyst depends on the specific reactor 

design and module arrangements. The specific time and equipment requirements for catalyst changeouts are 

normally developed after the specific reactor and module details are established. 

The SCR Cost Estimate study assumed that reactor isolation dampers and reactor maintenance bypass 

ductwork dampers would be required to avoid contamination of the catalyst by the air/water/particulate 

stream, and allow the reactors to be cooled while being isolated from the normal flue gas path to the chimney. 

The time estimated for catalyst installation into the empty (spare) layer of the reactor was 16 shifts, which, 

assuming two shifts per day, would be 8 days. The time estimated to remove dirty catalyst and install fresh 

catalyst in its place was 24 shifts, which, assuming two shifts per day, would be 12 days. The time assumed 

for reactor cooldown was previously estimated as 48-60 hours, which would elapse during the first half of the 

boiler cleaning process10. After the fresh catalyst is in place, and the reactor access doors closed, the entire 

volume of fresh and dirty catalyst remaining in the reactor must then be heated to above the moisture 

dewpoint to avoid possible moisture condensation during boiler startup. This would involve use of the 

supplemental catalyst outage heating system, not the flue gas reheat system nor flue gas from the boiler. 

Burns & McDonnell estimated that post catalyst changeout outage time will extend approximately 36-48 

hours until the boilers are ready to begin the startup process to return to service. 

The November 2009 Supplemental NOx BACT Analysis study assumed 1168 total hours and 1126 total 

hours of outage time per year associated with MRYS Unit 1’s hypothetical application of low-dust and tail 

end SCR technologies (Scenario “B”), respectively. This is 980 hours and 938 hours of outage time in 

addition to the 188 hours of outage time per year assumed for advanced separated overfire air alternative. 

Assuming three catalyst layer changeout outages per year for Unit 1, this works out to be approximately 13 

extra days per outage. Unit 2’s Scenario “B” assumed 1415 total hours of outage time for either hypothetical 

application of low-dust and tail end SCR technologies. This is 1234 hours of outage time in addition to the 

181 hours of outage time per year assumed for advanced separated overfire air alternative. Assuming four 

catalyst changeout outages per year for Unit 2, this works out to be approximately 13 extra days per outage. 

 

10 See Reference 9, March 15, 2007, pages 12-14. 
 5 

The November 2009 Supplemental NOx BACT Analysis study assumed 401 total hours and 443 total hours 

of outage time per year associated with MRYS Unit 1’s, and 387 total hours and 428 total hours of outage 

time per year for Unit 2’s, hypothetical application of tail end and low-dust SCR technologies (Scenario “A”), 

respectively. This is 213 or 256 hours of Unit 1 outage time and 206 or 247 hours of Unit 2 outage time in 

addition to the 181 hours of outage time per year assumed for advanced separated overfire air alternative. 

Assuming one catalyst changeout outage every two years for each Unit 1 and Unit 2, this works out to be 

approximately between 8.6 and 10.7 extra days per outage, depending on the boiler and SCR technology 

studied. 

The catalyst changeout outage times assumed in the November 2009 Supplemental NOx BACT Analysis 

study for MRYS Unit 1 and the similar study for MRYS Unit 2 are expected to be extensions to the boiler 

cleaning outages. Note that the estimated annual number of days for catalyst changeout outages is in addition 

to outage times included in the Advanced Separated Overfire Air alternative, which is also relative to baseline 

operation which include downtime for boiler cleanings. We believe the outage durations and frequency are 

reasonable assumptions to use for the purposes of showing possible economic outcomes that could result 

from the hypothetical application of low-dust and tail end SCR technologies at MRYS. 

NDDH Request #4: The indirect capital costs associated with the project appear to be high. A 

detailed explanation of the estimation method must be supplied. 

BMcD Response: 

Burns & McDonnell used standard estimating practices to estimate direct, installation, and indirect capital 

costs for MRYS Unit 1’s and Unit 2’s hypothetical application of low-dust and tail end SCR technologies. 

To establish the context of estimated indirect costs, we note that several major assumptions were used by 

Burns & McDonnell in developing the capital cost estimates of the hypothetical applications of low-dust and 

tail end SCRs at Milton R. Young Station. These assumptions include the following: 

• A multiple (parallel prime) contracting approach was selected (as opposed to single “turnkey” or 

Engineer-Procure-Construct contract). Although this approach may increase the project execution 

risk to the Owner, the execution risk is considered manageable. This contracting approach was 

recommended because it allows early award of major equipment procurements to allow detailed 

design engineering to proceed expeditiously to meet the project schedule, and offers the greatest 

flexibility for the Owner (Minnkota) to be involved in key decisions regarding design. 

• Project will be executed to achieve completion in 2016 for Unit 2 and 2017 for Unit 1. It was 

assumed that the project will be executed with skilled workforce resources sufficient to meet the 

target project execution schedule while minimizing overtime. No additional overtime is included to 

accommodate a compressed work schedule. 
 6 

Indirect Costs: 

• Escalation based on historical data and Burns & McDonnell experience was assumed to average 5% 

per year for equipment, 9% per year for materials and 5% per year for labor. See additional general 

description of escalation included below. 

• Contingency was calculated at 20% overall (10% for pricing and 10% for scope). Contingency was 

applied to Total Direct Capital Costs plus Indirect Capital Costs such as Engineering and Field 

Support, Construction Management and related indirects, Startup Expenses, and Cost Escalation 

during Project Execution. Owner Contingency was estimated at 7%. See additional general 

description of contingency included below. 

• A performance bond is included for all subcontract work at the rate of 1.5% of the estimated project 

contract costs. 

• Sales tax on construction consumables is included. No other tax is included. 

• Owner will provide a builder’s risk policy for the project. Cost for this is included in the estimate of 

Owner’s costs. 

• Interest During Construction (IDC) is included in the Owner’s costs at 6% per year, assuming project 

execution-based monthly expenditures. 

Escalation: 

An estimate for escalation of project costs has been included in the capital cost estimate. Escalation of 

construction labor, materials, and indirects was estimated based on historical data and Burns & McDonnell 

experience. 

Escalation of construction labor was estimated to be approximately 5% annually throughout the project. This 

estimate of escalation was based on the average increase in craft labor costs for the United States combined 

with known union labor contract costs in the next few years. The average annual escalation of union 

contracts for skilled and common labor rates over the last ten years in North Dakota has been approximately 

5.0% per year. 

Escalation of equipment and materials is included in the project estimate at a rate of 5% per year for 

equipment and 9% per year for materials. Since January 2004, steel pricing experienced rapid escalation 

equating to a nearly a 100% increase in rebar and structural steel costs, then dropped in late 2008 and early 

2009. Within the past 6 months, steel prices have again started to rise. Pipe and electrical commodities have 

also seen a high overall escalation during this time, followed by a decline in late 2008. Due to this volatility, 

equipment and material suppliers have been providing pricing with short bid validity. 
 7 

Contingency: 

This project involves a significant amount of retrofit work in the existing plant. The SCR Cost Estimate 

study did not perform a thorough review of existing conditions and interfaces with the new work. It is 

anticipated that the scope of work will increase as unknown conditions are discovered during project 

execution. A contingency of 20% of the overall project costs is included in the project cost. Of this 20%, 

10% covers accuracy of the pricing of the equipment and materials (commodities), and 10% covers omissions 

from the defined project scope. This contingency is not intended to cover changes in the general project 

scope (i.e. addition of buildings, addition of redundant equipment, addition of systems, etc.) nor major shifts 

in market conditions that could result in significant increases in contractor margins, major shortages of 

qualified labor, significant increases in escalation, or major changes in the cost of money (interest rate on 

loans). 

In addition to the project contingency, an additional owner contingency is included to cover owner general 

project scope additions. Based upon the amount of preliminary design and project definition completed, a 

7% scope contingency to cover such potential changes is included. However, this contingency level 

depends on the probability of additional scope and is typically determined by the Owner (Minnkota). 

NDDH Request #5: Support must be supplied for the cost of natural gas and electricity. 

BMcD Response: 

Burns & McDonnell used estimated long-term average natural gas unit cost for the economics of 

conventional and fuel-lean gas reburn alternatives’ annual operating costs included in the 2006 NOx BACT 

Analysis Study reports for MRYS Unit 1 and Unit 2. The annual cost of auxiliary power consumed by air 

pollution control equipment and the value of electric generator output not able to be sold (“lost”) due to 

inability to produce electricity during outages related to the air pollution control equipment associated with 

particular control alternatives were also calculated. The long-term average unit costs for natural gas and 

electricity were provided by Minnkota. Burns & McDonnell’s recent review of the forecast power industry’s 

natural gas unit cost forecasts from 2006 confirm that the number used in the original NOx BACT Analysis 

Study calculations and reports submitted in October 2006 are reasonable, given the uncertainty and variability 

that is common with such forecasts. 

In the November 2009 Supplemental NOx BACT Analysis study reports, Burns & McDonnell assumed the 

economics of hypothetical application of low-dust and tail end SCR technologies at MRYS should be also 

based on the same unit costs used for the 2006 NOx BACT Analysis study reports. 
 8 

NDDH Request #6: More details, including calculations, must be supplied to justify the 

pressure drops and parasitic loads associated with the SCR configurations. 

BMcD Response: 

Burns & McDonnell used estimated flue gas pressure drops provided by the SCR supplier for the SCR 

reactor, and gas-to-gas heat exchangers (GGH), in the development of new induced draft booster fans’ 

performance requirements and the alternatives’ economics of hypothetical application of low-dust and tail 

end SCR technologies at MRYS for Unit 1 and Unit 2 in the November 2009 Supplemental NOx BACT 

Analysis study reports. The estimated flue gas pressure drops of the flue gas ductwork, which would be 

incurred upstream and downstream of the low-dust and tail end SCR reactors and GGHs, were calculated 

using a proprietary spreadsheet. 

For low dust SCR cases, new ductwork would be connected downstream of the existing induced draft fans’ 

outlets and a new booster fan for each reactor would follow the GGH outlet after the SCR reactor, 

discharging to the existing flue gas desulfurization (FGD) system absorber inlet duct11. 

In tail end SCR cases, new duct connections downstream of the existing induced draft fans’ outlets would 

divert flue gas before the FGD absorbers’ inlet ducts, through the hot side of the FGD GGH then back to the 

FGD absorber inlet duct. Additional duct connections downstream of the existing FGD absorbers’ outlet 

ducts would reroute flue gas through the cold side of the FGD GGH, then to the cold side of the main (SCR) 

GGH upstream of the flue gas reheat section in the SCR reactor. After the reactor, flue gas would pass 

through the hot side of the main (SCR) GGH, continue to the new induced draft booster fans, and be 

discharged back to new duct connections near the existing inlets to the chimneys12. 

Horsepower required to drive the fans to produce pressure needed to overcome the cumulative ductwork and 

SCR equipment pressure losses for full load (maximum continuous rating) and “test block” flue gas flows 

was calculated from budgetary booster fan equipment quotes, which included preliminary pressure rise versus 

flow and mechanical efficiency curves, from two fan vendors. The horsepower required for the volumetric 

gas flow and pressure rise was then converted into electrical kilovolt-amperes (kVA) and kilowatts (kW) in 

order to calculate auxiliary power loads. An annual average load factor was applied, which was then 

multiplied by the assumed hours of annual operation to determine the annual megawatt-hours (MW-h) of 

consumed auxiliary power due to the SCRs’ induced draft booster fans. 

 

11 See attached sketch for low-dust SCR equipment and ductwork conceptual arrangement. 12 See attached sketch for tail end SCR equipment and ductwork conceptual arrangement. 
 9 

The parasitic loads associated with the SCR alternatives studied were determined by identifying known 

power-consuming auxiliary equipment serving the new air pollution control equipment. Estimates of design 

horsepower or kVA, based on vendor quotes or similar projects where information is available, were 

generated. Conversion to kW along with application of an annual average load factor resulted in estimated 

average annual auxiliary power loads, which were summed together to establish the total parasitic load. 

Annual megawatt-hours (MW-h) of consumed auxiliary power due to the various SCR cases studied were 

calculated by multiplying the total parasitic load by the assumed hours of annual operation. 

The table below provides the results of these calculations. 

Pressure Drop and Fan Power Calculation Results 

Parameter U1 LD U1 TE U2 LD U2 TE 

FGD GGH (hot side) pressure drop, in. w.g. -- 2.7 -- 1.87 

FGD GGH (cold side) pressure drop, in. w.g. -- 2.7 -- 1.87 

SCR GGH (cold side) pressure drop, in. w.g. 2.3 2.7 1.74 1.98 

SCR reactor/catalyst press. drop, in. w.g. 2.0 2.0 2.0 2.0 

SCR GGH (hot side) pressure drop, in. w.g. 2.3 2.7 1.74 1.98 

SCR flue gas ducts/dampers/connections 

pressure drop, in. w.g. 

5.4 6.2 4.5 6.3 

Booster Fan Static Pressure Rise 

/ Total Pressure1

 (Inches W.G.) 

12.0 / 

13.51 

19.0 / 

21.33 

10.0 / 

11.50 

16.0 / 

18.23 

Booster Fan Motor Horsepower2 5000 7000 3500 5000 

Load kVA / Demand kVA3 5000 /4500 7000 /6300 3500 /3150 5000 /4500 

Quantity of Fans, capacity per fan, each case One (1) x 100% Two (2) x 50% 

1- Booster fan static pressure rise is the sum of the duct and SCR equipment pressure drops. Total fan pressure 

includes fan static pressure rise plus additional pressure rise required to overcome pressure drops within the fan 

equipment. These numbers do not include additional fan capacity (margin) above the amount required for full load 

(maximum continuous rating or MCR) operation, which allows for factors that reduce actual performance over 

sustained periods of running. Static pressure rise and Total pressure numbers are preliminary; final design may 

require values higher or lower than those shown. 

2- Motor horsepower is greater than fan mechanical horsepower, and is based on available size larger than “Test 

Block” horsepower. Mechanical horsepower takes into account fan mechanical efficiency at the stated operating 

condition. Fans are sized based on mechanical efficiency and additional capacity (margin) above the MCR 

condition, referred to as “Test Block”. The test block flow margin is 15% per fan, the test block pressure rise 

margin is 32.25% (1.15^2) above MCR values stated above. Test block fan mechanical efficiency is approximately 

0.8. Fan Mechanical Horsepower = flue gas volumetric flow (actual cubic feet per minute) multiplied by pressure 

rise in inches w.g. divided by (6536 x efficiency). Fan efficiency varies with flow and pressure rise; values based 

on estimates/vendor quotes for full load (maximum continuous rating or MCR) conditions. 

3- Horsepower (motor rating) is approximately equal to Connected Load kVA; Connected Load kVA x Estimated 

Annual Average Demand factor = Demand Load kVA. 

Hypothetical applications of low-dust and tail end SCR technologies included estimates of auxiliary electrical 

power usage. It is important to note that some alternatives identified between 88 and 109 electricityconsuming items supplying or serving each SCR reactor system. Several pieces of auxiliary equipment with 
 10 

significant electrical power loads were included. These are: sootblowing air compressors with dryers; 

instrument/service air compressors with dryers; seal air fans for SCR reactor inlet and outlet flue gas isolation 

dampers; SCR flue gas reheat burner combustion air fans; drive gearboxes for rotary gas/gas heat exchangers; 

urea-to-ammonia dilution air/combustion air fans; auxiliary equipment service building 

ventilation/heating/lighting; and urea feed pumps. The instrument/service air and sootblowing air 

compressors are significant but necessary to supply dry compressed air used by equipment dedicated to 

control, maintain, and provide catalyst cleaning media for the SCR systems. 

NDDH Request #7: All vendor correspondence related to SCR reactor sizing, catalyst volume, 

NOx control efficiency, catalyst cost, catalyst replacement schedule, and 

catalyst guarantees should be provided. This includes the original requests 

submitted to vendors and analyst [catalyst] suppliers by Minnkota and its 

consultants. This must also include the description of the gas stream that 

was supplied to the vendors. 

BMcD Response: 

Information responsive to this request by Minnkota, Burns & McDonnell and the SCR system supplier and 

SCR process design consultant, catalyst vendors, and flue gas particulate characterization consultant is being 

submitted (see Enclosures). Documents that include information considered as “trade secrets” per the 

NDDH’s Air Pollution Control rules are being submitted and marked “confidential” (see Enclosures). 

Minnkota developed agreements with the catalyst suppliers and flue gas particulate characterization 

consultant engaged in this effort, and has a general services agreement with Burns & McDonnell, which 

covers work done by the SCR system supplier and SCR process design consultant. Information provided 

under Enclosure C is considered non-confidential, and includes information for which no claim is being made 

for confidentiality, along with an index and summary of the information submitted which is suitable for 

release to the public. Enclosure D includes documents claimed to contain trade secrets which are requested to 

be treated as confidential, along with an affidavit stating how and why the information fulfills the conditions 

of confidentiality per the NDDH’s Air Pollution Control rules describing this confidentiality procedure. 

NDDH Request #8: Data must be provided for the temperature gradient of the regenerative 

heat exchanger to justify the reheat calculations. This must be provided 

for the both LDSCR and TESCR. The 600oF temperature for the reheated 

flue gas must be justified. 
 11 

BMcD Response: 

The preliminary design temperatures for the hypothetical applications of low-dust and tail end SCR 

technologies shown in the table below were calculated by the SCR process consultant. The temperature data 

tabulated below for the Unit 1 low dust (LD) case include corrections identified by the SCR process 

consultant as described further in the response to NDDH Request #11.b. The SCR system supplier, which 

provided pricing of SCR equipment, including GGHs for low-dust and tail end SCRs, did not provide 

estimates of the GGHs’ process performance. 

SCR Process Design Temperatures 

Parameter U1 LD U1 TE U2 LD U2 TE 

FGD GGH (hot side) inlet temperature, oF -- 335 -- 331 

FGD GGH (hot side) outlet / FGD Absorber 

Inlet temperature, oF 

-- (1) -- (1) 

FGD GGH (cold side) inlet/ FGD Absorber 

Outlet temperature, oF 

-- 142 -- 143 

FGD GGH (cold side) outlet temperature, oF -- 150 -- 151 

SCR GGH (cold side) inlet temperature, oF 335 150 331 151 

SCR GGH (cold side) outlet temperature, oF 535 520 535 520 

Flue Gas Reheat Burner outlet / SCR Ammonia 

Injection Grid/Reactor inlet temperature, oF 

580 563 580 563 

SCR GGH (hot side) outlet temperature, oF 380 199 380 197 

FGD Absorber Outlet temperature, oF 142 142 143 143 

1- The temperature of the FGD GGH hot side outlet (discharges to FGD Absorber Inlet) was not provided by the SCR 

process consultant. It would be less than 330oF. 

As can be seen in the table above, the flue gas is reheated by natural gas to either 580oF for low-dust SCR 

cases or 563oF for tail end SCR cases. Natural gas heat input rates used in the November 2009 Supplemental 

NOx BACT Analysis study reports assumed these flue gas temperatures. These preliminary process design 

temperatures have not been confirmed pending final design by the gas/gas heat exchanger manufacturer. The 

catalyst vendors recommended that the catalyst be designed for (able to withstand continuous exposure to) 

600oF service operating temperature. The capacity of the reheat burner equipment was not specifically 

provided by the SCR system supplier, but was expected to be capable of raising the flue gas up to the 

recommended service temperature. 
 12 

NDDH Request #9: A comparison of the SCR costs at M.R.Young Station versus PSE&G 

Mercer Station and We Energies Oak Creek Station should be provided or 

an explanation why such a comparison is not possible or inappropriate. 

We recognize that each plant has unique characteristics and there will be 

some design differences from plant-to-plant, but those differences should 

not necessarily dismiss making general comparison of costs unless there are 

unique or extenuating circumstances which would preclude a general cost 

comparison. 

BMcD Response: 

A BACT analysis is performed on a case-by-case, site-specific basis. It is inappropriate to compare the 

capital costs associated with the low-dust SCR installation at Mercer Station, or at South Oak Creek Station, 

against those developed for the hypothetical applications of low-dust and tail end SCR technologies at 

MRYS. Site conditions, boiler firing type, type and characteristics of fuels burned and resulting flue gas 

emissions and ash produced, and the limited amount of NOx reduction required for those referenced low-dust 

SCR cases that were not required to represent BACT, make the comparison not relevant to MRYS. 

NDDH Request #10: Provide additional clarification and technical justification regarding 

Minnkota’s determination that the units at MRYS are boiler limited and 

cannot generate additional steam for flue gas reheating purposes. 

BMcD Response: 

The steam turbine-generators at MRYS have a given output (gross megawatts) based on steam pressures, 

temperatures and flow rates related to the boilers. Removing high pressure/high temperature steam to use for 

flue gas reheating will directly cause a reduction in electrical output. This output reduction cannot be 

compensated for by increased boiler steam generation without unreasonable consequences. The boilers 

generate steam based upon their fuel heat input (firing) rates and capacities to absorb the heat created from 

the fuel combustion. The efficiency of converting fuel heat to steam to megawatts (heat rate or Btu per gross 

kilowatt) is limited by many factors. Fuel characteristics and boiler capacity are factors that impact heat rate 

(efficiency) that are not easily changed in the positive direction. The current fuel quality coming from the 

adjacent mine is not within the original design parameters of the boilers. 

Because of the firing type (cyclone) and characteristics of North Dakota lignite burned and resulting flue gas 

emissions and ash produced at MRYS, the amount of fouling of the heat-absorbing surfaces within the boiler 

system is severe. These fouling conditions cause high exit flue gas temperatures that eventually reach the 

maximum limit recommended for maintaining the integrity of the air preheaters. This is indicated by the 
 13 

time-temperature graphs previously provided13 and repeated below. The rate of boiler surface fouling 

increases significantly as more coal is fired, especially at maximum sustainable firing rates. 

Due to the sticky character of the ash deposits, an “arsenal” of sootblower and water lance equipment is 

employed by Minnkota in an attempt to reduce the rate of fouling accumulations during boiler operations and 

remove these deposits during frequent boiler outages. These boiler cleaning outages occur every three to four 

months depending on the specific unit and the fuel quality delivered during the period. If the firing rate is 

increased to generate more steam for other heating purposes, the frequency of the cleaning outages must be 

increased. If the accumulated deposits are not removed, the frequency of the cleaning outages must be 

increased or the firing rates must be reduced and thus reduce the steam and electrical output of the boilers and 

steam turbine-generators. There is not “excess steam available for flue gas reheating” that would allow 

Minnkota to avoid reduced annual power generation.

 

13 See Reference number 11, April 18, 2007, pages 13-17. 

MR Young Unit 1 PSH Outlet Temperatures

820

840

860

880

900

920

940

960

980

0 20 40 60 80 100 120

Days

Temperature (degrees F)

2/26/02-5/14/02

5/17/02-6/11/02

6/16/02-10/6/02

10/15/02-11/09/02

11/11/02-2/19/03

2/23/03-3/31/03
 14 

MR Young Unit 2 Economizer Outlet Temperatures

750

770

790

810

830

850

870

890

0 20 40 60 80 100 120

Operating Days

Temperature (degrees F)

1/1/02-2/13/02

2/19/02-6/7/02

6/11/02-6/27/02

7/4/02-9/9/02

9/16/02-10/16/02

10/21/02-11/19/02

11/23/02-1/16/03

2/17/03-3/31/03
 15 

NDDH Request #11: There appear to be several discrepancies in the documents that must 

be addressed including: 

a. The catalyst volume for Unit 2 (p. 4-23) is listed as 256 m3

 per reactor or 512 m3 per 

layer. This is 4-5 times more than Unit 1 yet Unit 2 is not twice as large. Please verify 

the Unit 2 catalyst volume. 

At page 4-23, the words “per reactor” should be deleted from the sentence describing Unit 2’s 

catalyst volume. This will be shown on an “Errata Sheet” attached to this document. 

For Unit 2, the total initial volume was 768 cubic meters for three layers, or 256 cubic meters per 

layer, based on catalyst vendor input. Subsequent installation of 342 cubic meters for the fourth layer 

was assumed, also based on catalyst vendor input. Total initial volume plus first fill of spare layer 

equaling 1110 cubic meters is for two SCR reactors for each case studied for Unit 2. The correct 

catalyst volumes were used in the annual operating and maintenance cost calculations that are a 

portion of the levelized total annual costs for NOx control alternatives provided in the referenced 

November 2009 Supplemental NOx BACT Analysis study reports. 

The conceptual design of Unit 1 Low-Dust SCR Reactor, and Tail End SCR Reactor as provided by 

the catalyst supplier included in each layer a total of 104 catalyst modules (8 x 13 arrangement). 

There is one SCR reactor for each case studied for Unit 1. The conceptual design of Unit 2 Low-Dust 

SCR Reactor, and Tail End SCR Reactor included in each layer a total of 91 catalyst modules per 

reactor (7 x 13 arrangement). There are two SCR reactors for each case studied for Unit 2. 

b. The reheat for Unit 2 for TESCR is listed as 48.11 MMBtu/hr per reactor and for 

LDSCR is 45.55 MMBtu/hr per reactor. The differential between TESCR and LDSCR 

is much less than for Unit 1 (60.3 MMBtu/hr and 31 MMBtu/hr). 

Please explain this difference. 

The preliminary process design calculations were reviewed for the hypothetical applications of lowdust and tail end SCR technologies for Unit 1 and Unit 2. It was determined from this review that the 

temperature rise for the Unit 1 LDSCR flue gas reheat system was incorrectly assumed to be 25 

degrees F instead of 25 degrees C (equivalent to 45 degrees F). The corrected 45 degrees F 

temperature rise for the Unit 1 LDSCR flue gas reheat system is shown in the table included with the 

response to NDDH Request #8. The correct natural gas heat input rate for Unit 1’s low-dust SCR 

cases is 54.5 MMBtu/hr (instead of 31 MMBtu/hr). 
 16 

The discovery of the underestimate of Unit 1’s low-dust SCR flue gas reheat fuel requires revision to 

the MRYS Unit 1 November 2009 Supplemental NOx BACT Analysis study report for “Scenario A” 

and “Scenario B” cases. A revised version of the referenced November 2009 MRYS Unit 1 

Supplemental NOx BACT Analysis Study report document and the December 2009 response 

document is being submitted with the corrected numbers and recalculated control costs (see 

Enclosures). The flue gas reheat fuel rates and costs assumed for the hypothetical applications of 

Unit 1’s tail end and Unit 2’s low-dust and tail end SCR alternatives included in the November 2009 

Supplemental NOx BACT Analysis study reports will not change. 

The temperature rise for the Unit 1 TESCR, Unit 2 LDSCR, and Unit 2 TESCR flue gas reheat 

systems are also shown in the table included with the response to NDDH Request #8. These are all 

preliminary numbers that would require confirmation after final cold-side outlet design temperatures 

are established by the FGD and SCR gas/gas heat exchanger manufacturer. 

c. The capital costs for the “stand alone” SCR (p.3 of attachments to December 11, 2009 

submittal) do not total correctly. Please check the numbers and revise the documents 

as necessary. 

The numbers for “Pricing Contingency” shown in the table that provided “Estimates of Total Capital 

Investment for Low Dust and Tail End Selective Catalytic Reduction Alternatives Best Available 

Control Technology – Supplemental Analysis Stand Alone” cases submitted on December 11, 2009 

were incorrect. They should match the “Scope Contingency” numbers above the “Pricing 

Contingency” line in the table. A revised version of the referenced document is being submitted 

containing the table with corrected data (see Enclosures). 

d. The flue gas reheat burners and fans appear to be included in both “SCR system 

equipment” and “Auxiliaries” cost estimates (see p.4 of attachments to December 11, 

2009 submittal, footnotes 1 and 3). Please check this and revise the documents as 

necessary. 

There are two systems of natural gas-fired burners associated with each alternative studied for 

hypothetical application of low-dust and tail end SCR technologies in the November 2009 

Supplemental NOx BACT Analysis study reports. The “flue gas reheat burner equipment” is 

correctly included as part of the “Purchased Capital Equipment SCR System Equipment” item (1) (a) 

under “Direct Capital Costs” denoted by footnote number1 in both tables of “Estimates of Total 

Capital Investment” for “Shared Facilities” and “Stand Alone” as submitted on December 11, 2009. 

Item (1) (b) “Auxiliaries/Balance of Plant” of both tables has footnote number 3. This footnote 
 17 

should be revised to read as follows: “Includes service air and sootblower air compressors, induced 

draft booster fan(s) and dampers, urea-to-ammonia conversion flue gas reheat equipment 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”. A revised version of the 

referenced document with the corrected footnotes is being submitted (see Enclosures). 

. 
 18 

REFERENCES 

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

Quality letter from Terry L. O’Clair, P.E. to John Graves, Minnkota Power Cooperative, 

Re: SCR Cost Estimate, January 11, 2010. 

2. Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative Responses to 

NDDH Request NOx BACT Analysis Study Milton R. Young Station Unit 1 and Unit 2 

Regarding SCR Economic Feasibility, December 2009, submitted by Minnkota to North 

Dakota Department of Health on December 11, 2009. 

3. NOX Best Available Control Technology Analysis Study – Supplemental Report for Milton 

R. Young Station Unit 1 for 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 Electric Cooperative, 

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

November 12, 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 included with the “BART DETERMINATION STUDY for 

Milton R. Young Station Unit 1 and 2 Minnkota Power Cooperative, Inc.” Final Report, 

October 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.1:06-CV-034, filed April 24, 2006. 

6. 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 for 

Time Extension, dated August 7, 2009. 

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

Nonattainment Area Permitting, Draft October 1990 (The “NSR Manual”). 

8. Technical Information (brochure) FT-9200-AP involving anhydrous and aqueous ammonia 

versus urea for SCRs available from Fuel Tech’s website www.ftek.com, dated November 

17, 2008. 

9. Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative Responses to 

EPA Comments NOx BACT Analysis Study Milton R. Young Station Unit 1 and Unit 2 

Regarding SCR Technical Feasibility, March 15, 2007. [with regard to two documents: 

ERG Memorandum to EPA Region 8 and EPA Office of Regulatory Enforcement, Review 

and Critique of the Burns & McDonnell NOX BACT Analysis for the Milton R. Young 

Station Operated by Minnkota Power (October 2006), written by Roger Christman, Eastern 

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

Minnkota, January 9, 2007. EPA Region 8 Preliminary Analysis of Burns & McDonnell 
 19 

BACT Analysis For Nitrogen Oxide at Milton R. Young Station, Units 1 and 2 January 8, 

2007 faxed by North Dakota Department of Health to Minnkota, January 9, 2007.] 

10. Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative Responses to 

NDDH and EPA Comments Regarding SCR Technical Feasibility and Non-SCR Concerns, 

Milton R. Young Station Unit 1 and Unit 2 NOx BACT Analysis Study, April 18, 2007. 

[with regard to two documents: 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 Determination Milton R. Young Station, dated February 1, 

2007, with enclosure from United States Environmental Protection Agency Region 8, letter 

to Terry O’Clair, North Dakota Department of Health Division of Air Quality, Re: 

Transmittal of EPA Non-SCR concerns and additional information required for Minnkota 

BACT Analysis Study, dated January 26, 2007.] 

ATTACHMENTS 

1. Conceptual design sketch, for hypothetical application of Low Dust SCR technology to 

MRYS Unit 1 and Unit 2, Burns & McDonnell, 2009. 

2. Conceptual design sketch, for hypothetical application of Tail End SCR technology to MRYS 

Unit 1 and Unit 2, Burns & McDonnell, 2009. 

3. ERRATA Sheet: 

a. Corrections to Reference number 3 of this document “NOX Best Available Control 

Technology Analysis Study – Supplemental Report for Milton R. Young Station Unit 2, 

Minnkota Power Cooperative, Inc. Operating Agent for Square Butte Electric 

Cooperative, Owner” November, 2009; (February, 2010). 
 20 

ENCLOSURES: 

A. Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative Responses to 

NDDH Request NOx BACT Analysis Study Milton R. Young Station Unit 1 and Unit 2 

Regarding SCR Economic Feasibility, December 2009, submitted by Minnkota to North 

Dakota Department of Health on December 11, 2009, revised February, 2010. 

B. NOX Best Available Control Technology Analysis Study – Supplemental Report for Milton 

R. Young Station Unit 1 for Minnkota Power Cooperative, Inc., November, 2009, submitted 

by Minnkota to North Dakota Department of Health on November 12, 2009, revised 

February, 2010. 

C. Non-confidential information related to response to NDDH Request #7 of this document 

(Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative Followup 

Responses to Presentation and NDDH Request for Additional Information, Supplemental 

NOx BACT Analysis Study, Milton R. Young Station Unit 1 and Unit 2 Regarding SCR 

Economic Feasibility, February 2010). 

D. Confidential information related to response to NDDH Request #7 of this document 

(Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative Followup 

Responses to Presentation and NDDH Request for Additional Information, Supplemental 

NOx BACT Analysis Study, Milton R. Young Station Unit 1 and Unit 2 Regarding SCR 

Economic Feasibility, February 2010). 
AM

SU

CHIMNEY

FGDSCRUBBER

BOOSTERFAN

SCR G/GHEATER

SCRREACTOR

LOW DUST SC

SKETCH SK - F

(EXISTING)
FGDSCRUBBER

ID FAN

BOOFAN

FGD G/GHEATER

SCR G/GHEATER

SCRREACTOR

AMMONIA INJECTION GRID

SUPPLEMENTAL GAS HEATING

TAIL END SCR

SKETCH SK – 

ESP

(EXISTING)
ERRATA – MRYS Unit 2 Supplemental NOx BACT Analysis Study Report 

(November 2009) 

Minnkota Power Cooperative, Inc. E-1 Burns & McDonnell 

Square Butte Electrical Cooperative 

Unit 2 Supplemental NOx BACT Analysis Study Report November 2009, page 4-23: 

The second sentence of the paragraph should be revised to delete the words “per reactor”: 

SCR catalyst replacements are additive to the general annual hypothetically-applied 

low-dust and tail end SCR equipment maintenance. Catalyst replacement costs are 

based on catalyst vendor quotation of volume of catalyst, estimated to be three layers 

initially (top, middle-upper and middle-lower) at 256 cubic meters per layer per reactor

for two reactors in parallel. A fourth (bottom) layer at 342 cubic meters is expected to 

be required after initial operation of hypothetically-applied full-time tail end or lowdust SCR alternatives, as part of the catalyst replacement program. Catalyst 

replacement costs for the hypothetical application of SCR alternatives were estimated 

for the two different catalyst management scenarios described above.