NPS Comments on NDDH Best Available Control Technology Determination For Control of Nitrogen Oxides fo r M.R. Young Station Units 1 and 2 May 10, 2010

Background

Minnkota Power Cooperative, Inc. (Minnkota) ope rates the Milton R. Young Station (MRYS) near Center, North Dakota. MRYS is a steam elec tric generating plant with two units. Unit #1 is a Babcock & Wilcox (B&W) cyclone-type coal-f ired 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 (SO 2 ) 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-L urgi precipitator rated at approximately 99% control. Unit #2 has a Co mbustion Equipment Associates wet flue gas desulfurization (FGD) system (modified by Combus tion Engineering) that treats approximately 78% of the flue gas with the remaining flue ga s by-passed for stack gas reheat. The FGD system achieves approximately 75% SO 2 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 Si gnificant Deterioration (PSD) regulations. The NOV was issued pursuant to Section 113 of the Cl ean Air Act. The alleged violation was caused by modifications to both Unit #1 and #2 at MRYS which alle gedly resulted in a potential increase of SO 2 , NO X 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 SO 2 , NO X 1 and PM on both Unit #1 and #2 at MRYS, e quivalent to Best Available Control Technology (BACT). 2

Best Available Control Technology (BACT) Review

EPA’s New Source Review Workshop Manual (NSR Ma nual) 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 T echnologies by Control Effectiveness Step 4 – Evaluate Most Effectiv e Controls and Document Results Step 5 – Select BACT Following are our comments on application of the five steps by Minnkota and NDDH.

1 The Consent Decree requires Minnkota and Square Butte to perform a “NO X Top-Down Best Available Control Technology (BACT) Analysis” to desc ribe the emission limits for NO X that will be required at Units #1 and #2, expressed as a 30-Day Rolling Average NO X Emission Rate.

2 The effect of the CD on the Best Av ailable 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 Catalyti c Reduction (LDSCR) and Tail-End Selective Catalytic Reduction (TESCR) as technically-feas ible options. While we agree with those selections, we believe that NDDH should have considered Rege nerative Selective Catalytic Reduction (RSCR) which is currently available from Babcock Power and in operation on large biomass boilers. RSCR has the potential to signi ficantly 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 ou tput. This is not an issue of technical feasibility—instead, Minnkota and NDDH must evaluate the ec onomic feasibility of steam reheat.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness NDDH adequately evaluated the eff ectiveness of both LDSCR and TESCR.

Step 4 – Evaluate Most Effective Controls and Document Results As discussed in our Appendix A, “NPS Co mments on Milton R. Young Station (MRYS) Baseline Emissions,” we believe that Minnkota and NDDH have underestimated the amount of
NO X 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 th is error by comparing its cost-effectiveness
results for lower emission rates and utilization to other permits 3 that were based upon assumptions of maximum allowable emissions at 100% utilization. The eff ect 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 Reduc tion (TESCR) Costs,” we believe that Minnkota
and NDDH have overestimated the costs of TES CR. 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 an d additional costs would be incurred. However, it was not possible from the information provided to determ ine how much this additional equipment would cost. Therefore, we compared the estimates presen ted 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-spec ific costs included in the information we are requesting.

2can be applied for estimating annual operating costs and we found several differences between the Cost Manual approach and the Minnkota es timates. For example, Minnkota incorrectly included major costs for “Allowance for Funds During Construction,” “Escalation” and “Owner’s Costs”, and added a “levelization” fact or 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 ta ble 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 $37,234,930
Incremental Cost-Effectiv eness ($/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

34 Step 5 – Select BACT

NDDH has correctly noted that BACT determinations are typi cally 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 reason able 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 wa s accepted. Of the sources listed by NDDH in its Table 9, only for PGE Boardman ($3,096/ton), Bi g 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 ND DH and by NPS that, for the 12 sources where SCR
was selected as BACT or BA RT, Average Annual Costs ranged from $825/ton - $4,262/ton, and for ten of those 12 SCR determinations, Averag e 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 thos e SCRs accepted as BACT or BART, LDSCR and TESCR are economically feasible at MRYS and should be determined to be BACT.

5 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 D ecree (CD) that requires the MRYS to install BACT-level controls for NO X , SO 2 , and PM. Thus, the BART analysis was reduced to an evaluation of the BACT-level control technologies and emission reductions sp ecified 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.