NPS Comments on NDDH Best Available Control Technology Determination 

For Control of Nitrogen Oxides for M.R. Young Station Units 1 and 2 

May 10, 2010 

Background 

Minnkota Power Cooperative, Inc. (Minnkota) operates the Milton R. Young Station (MRYS) 

near Center, North Dakota. MRYS is a steam electric generating plant with two units. Unit #1 is 

a Babcock & Wilcox (B&W) cyclone-type coal-fired boiler burning lignite coal, serving a 

turbine generator with a nameplate rating of 257 MW. Particulate control is provided by a 

Research-Cottrell Electrostatic Precipitator rated at approximately 99% control. Unit #1 has no 

sulfur dioxide (SO2) control system and exhausts to a 300 foot tall stack. Unit # 2 is a B&W 

cyclone-fired unit burning lignite coal, with a turbine-generator nameplate rating of 477 MW. 

Particulate control for Unit #2 is provided by a Wheelabrator-Lurgi precipitator rated at 

approximately 99% control. Unit #2 has a Combustion Equipment Associates wet flue gas 

desulfurization (FGD) system (modified by Combustion Engineering) that treats approximately 

78% of the flue gas with the remaining flue gas by-passed for stack gas reheat. The FGD system 

achieves approximately 75% SO2 removal and exhausts to a 550 foot tall stack. Unit #1 began 

commercial operation on November 20, 1970 and Unit #2 on May 11, 1977. 

On 17 June 2002, Minnkota received a Notice of Violation (NOV) from EPA stating that 

Minnkota allegedly violated the Prevention of Significant Deterioration (PSD) regulations. The 

NOV was issued pursuant to Section 113 of the Clean Air Act. The alleged violation was caused 

by modifications to both Unit #1 and #2 at MRYS which allegedly resulted in a potential 

increase of SO2, NOX and PM. Without an admission of liability, Minnkota entered into a 

settlement in the form of a Consent Decree (CD) with the EPA and the North Dakota Department 

of Health (NDDH) to resolve the issues. The CD requires that Minnkota install a level of control 

for SO2, NOX

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and PM on both Unit #1 and #2 at MRYS, equivalent to Best Available Control 

Technology (BACT).2 

Best Available Control Technology (BACT) Review 

EPA’s New Source Review Workshop Manual (NSR Manual) outlines five basic steps that are to 

be followed in this BACT analysis. These basic steps for such a BACT analysis are summarized 

as follows: 

Step 1 – Identify All Control Technologies 

Step 2 – Eliminate Technically Infeasible Options 

Step 3 – Rank Remaining Control Technologies by Control Effectiveness 

Step 4 – Evaluate Most Effective Controls and Document Results 

Step 5 – Select BACT

Following are our comments on application of the five steps by Minnkota and NDDH. 

                                                           

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 The Consent Decree requires Minnkota and Square Butte to perform a “NOX Top-Down Best Available Control 

Technology (BACT) Analysis” to describe the emission limits for NOX that will be required at Units #1 and #2, 

expressed as a 30-Day Rolling Average NOX Emission Rate. 2

 The effect of the CD on the Best Available Retrofit Technology (BART) analysis and the requirement to install 

BACT-level controls are discussed later in the report. 
Step 1 – Identify All Control Technologies 

NDDH identified Low-Dust Selective Catalytic Reduction (LDSCR) and Tail-End Selective 

Catalytic Reduction (TESCR) as technically-feasible options. While we agree with those 

selections, we believe that NDDH should have considered Regenerative Selective Catalytic 

Reduction (RSCR) which is currently available from Babcock Power and in operation on large 

biomass boilers. RSCR has the potential to significantly reduce reheat expenses versus the 

approach evaluated by NDDH. 

Step 2 – Eliminate Technically Infeasible Options 

Minnkota rejected the use of steam to reheat the gas stream ahead of either SCR approach on the 

basis that it would reduce plant output. This is not an issue of technical feasibility—instead, 

Minnkota and NDDH must evaluate the economic feasibility of steam reheat. 

Step 3 – Rank Remaining Control Technologies by Control Effectiveness 

NDDH adequately evaluated the effectiveness of both LDSCR and TESCR. 

Step 4 – Evaluate Most Effective Controls and Document Results 

As discussed in our Appendix A, “NPS Comments on Milton R. Young Station (MRYS) 

Baseline Emissions,” we believe that Minnkota and NDDH have underestimated the amount of 

NOX that would be reduced by the SCR options. For example, NDDH has estimated baseline 

emissions by using historic average emission data instead of upper-bound emission data as 

directed by the NSR Manual. NDDH compounded this error by comparing its cost-effectiveness 

results for lower emission rates and utilization to other permits3

 that were based upon 

assumptions of maximum allowable emissions at 100% utilization. The effect of this approach 

by NDDH is to bias the cost-effectiveness analysis toward higher values than would have been 

derived had NDDH used the same approach as was used for the permits it used for comparison. 

As discussed in our Appendix B, “NPS Comments on Milton R. Young Station (MRYS) Unit #1 

(and Unit #2) Tail-End Selective Catalytic Reduction (TESCR) Costs,” we believe that Minnkota 

and NDDH have overestimated the costs of TESCR. We applied the EPA OAQPS Control Cost 

Manual (Cost Manual) approach to MRYS to estimate the cost of adding SCRs but did not 

include any estimates for the associated reheat systems because that information was not made 

available to us.4

Because some method must be applied to reheat the gases leaving the wet scrubber, additional 

equipment would be required and additional costs would be incurred. However, it was not 

possible from the information provided to determine how much this additional equipment would 

cost. Therefore, we compared the estimates presented by Minnkota to the ratios used by the Cost 

Manual to relate capital and some operating costs, to Total Direct Capital Cost. The Cost Manual 

                                                           

3

 For example, the analyses and resulting permit limits for WYGEN 3 and Dry Fork permits cited by NDDH were 

based upon maximum allowable emissions at 100% utilization.

4

 We are requesting information that will allow us to evaluate the costs of each major component and will then be 

able to apply our SCR-only cost estimates to the SCR-specific costs included in the information we are requesting.

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can be applied for estimating annual operating costs and we found several differences between 

the Cost Manual approach and the Minnkota estimates. For example, Minnkota incorrectly 

included major costs for “Allowance for Funds During Construction,” “Escalation” and 

“Owner’s Costs”, and added a “levelization” factor to the “Total Annual Cost”, which are not 

allowed by the Cost Manual. Our estimates for the costs of installing and operating ASOFA plus 

TESCR with reheat systems are shown in the table below and explained in detail in the 

enclosures. 

Operating company Basin Electric Power

Facility Milton R. Young

Unit #1 #2 

Rating (MW Gross) 257 477

Rating (mmBtu/hr) 3,200 6,300 

Current Emissions (tpy) 12,054 23,731 

Current Emission Rate (lb/mmBtu) 0.86 0.86 

ASOFA 

New Emission Rate (lb/mmBtu) 0.513 0.489 

New Emissions (tpy) 7,190 13,493 

Capital Cost $4,277,000 $10,008,000 

Capital Cost ($/kW) $17 $21 

O&M Cost $65,776 $159,744 

Total Annual Cost $469,494 $1,104,429 

Cost-Effectiveness ($/ton) $97 $108 

TESCR 

Emissions Reduction (tpy) 6,503 12,141 

Capital Cost $180,206,747 $266,981,971 

Capital Cost ($/kW) $701 $560 

O&M Cost $7,383,763 $12,033,720 

Total Annual Cost $24,394,005 $37,234,930 

Incremental Cost-Effectiveness ($/ton) $3,751 $3,067 

ASOFA+TESCR 

Control Efficiency 94% 94%

New Emission Rate (lb/mmBtu) 0.049 0.049 

New Emissions (tpy) 687 1,352 

Emissions Reduction (tpy) 11,367 22,379 

Capital Cost $184,483,747 $276,989,971 

Capital Cost ($/kW) $718 581 

O&M Cost $7,449,539 $12,193,465 

Total Annual Cost $24,863,500 $38,339,358 

Average Cost-Effectiveness ($/ton) $2,187 $1,713 

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Step 5 – Select BACT 

NDDH has correctly noted that BACT determinations are typically based upon comparisons to 

other BACT determinations for similar sources, and that cost data on SCR determinations are 

relatively sparse because such cost analyses are seldom conducted for this top level of control. 

Of the BACT determinations summarized by NDDH in its Table 8, we have sufficient data on 

only the Dry Fork and WYGEN 3 projects. In those two cases, the Wyoming Department of 

Environmental Quality (WY DEQ) determined that Average Annual Costs of $1,511/ton and 

$4,037/ton, respectively, were reasonable for the combinations of combustion controls plus SCR. 

WY DEQ also determined that Incremental costs of $10,303 and $11,102, respectively, were 

reasonable for the SCR scenarios. 

NDDH has also included cost data on several Best Available Retrofit Technology (BART) 

determinations.5

 However, because BACT is usually based upon evaluations of control 

technologies that have been accepted, we believe that NDDH should have primarily considered 

those BART determinations in which SCR was accepted. Of the sources listed by NDDH in its 

Table 9, only for PGE Boardman ($3,096/ton), Big Stone #1 ($825/ton), Boswell Energy Center 

#3 ($3,201/ton), and Healy #1 ($3,374/ton) was SCR determined to represent BART. In addition 

to those sources, SCR has been determined to be BART at Jim Bridger #3 & #4 ($4,262/ton 

each) and Naughton #3 ($2,830/ton) in Wyoming. 

It can be seen from the data presented by NDDH and by NPS that, for the 12 sources where SCR 

was selected as BACT or BART, Average Annual Costs ranged from $825/ton - $4,262/ton, and 

for ten of those 12 SCR determinations, Average Annual Costs equaled or exceeded the Average 

Annual Costs we estimated for addition of SCR on both units at MRYS. We therefore conclude 

that, when compared to the costs of those SCRs accepted as BACT or BART, LDSCR and 

TESCR are economically feasible at MRYS and should be determined to be BACT. 

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 MRYS Units #1 and #2 were determined to be subject to BART by the NDDH. However, prior to the completion 

of the BART analysis, Minnkota entered into a Consent Decree (CD) that requires the MRYS to install BACT-level 

controls for NOX, SO2, and PM. Thus, the BART analysis was reduced to an evaluation of the BACT-level control 

technologies and emission reductions specified by the CD. Because BACT and BART analyses have similar steps, 

the only remaining step for recommending BART was to perform a visibility impairment impact analysis and 

discern if there was an acceptable impact reduction. NPS submitted comments to NDDH on BART in October of 

2009.