Appendix B. NPS Comments on Milton R. Young Station (MRYS) Unit #1 Tail-End Selective Catalytic Reduction (TESCR) Costs

As discussed in Appendix B, recent industry li terature suggests that most SCR retrofits can be accomplished at a Total Capital Investment (TCI) under $200/kW, with the average cost at about $185/kW. We have found that the OAQPS Control Cost Manual (Cost Manual) tends to produce much lower esti mates for TCI. In order to allow one to “adjust” the Cost Manual approach to produce TCI estimates more comparable to the industry literature, we have added “extra 1 retrofit” factors to adjust both the Direct Capital Cost (DCC) and the Indirect Capital Cost. These extra retrofit factors also allow
us to account for unusual retrofit situations. In this case, we assumed extra retrofit factors that yielded a TCI of $185/kW for the addi tion of SCR (with bypass, or $179/kW without bypass). Because this is consistent with the in dustry estimates, we believe this to be a reasonable estimate of TCI for the SCR portion of this project. Following is a detailed
discussion of selected individual elements of the cost analysis.

Baseline Emissions

The EPA New Source Review Workshop Manual (NSR Manual) states that “...baseline emissions are essentially uncontrolled emissions, calculated using realistic upper boundary operating assumptions .” (emphasis added) The enclosed document “NPS Comments on Milton R. Young Station (MRYS) Baseline Emissions” describes our rationale for determining the following “upper boundary baseline emissions” for MRYS #1 instead of the average valu es used by Minnkota and NDDH:

• Heat input = 3,200 mmBtu/hr stated in NDDH BART analyses. NDDH used 2,728 in its BACT analysis which appears to represent a historic two-year average and not a historic annual upper bound.

• Utilization = 100% from NDDH underlying assumpti ons in their BART analyses and resulting Title V permit. Instead, NDDH used 96.4% in its BACT analysis which appears to represent a historic tw o-year average and not a historic annual upper bound.

• Uncontrolled NOx Concentration (lb/mmBtu) = 0.86 because this is consistent with the MRYS #1 Title V permit and MRYS Unit 1’s highest annual NO X mass emissions averaged 0.866 lb/mmBtu in 1995 and NDDH used 0.86 lb/mmBtu in its BART analysis. NDDH used 0.840 lb /mmBtu in its BACT analysis which appears to represent a historic two-year average and not a historic annual upper
bound.

1 The Cost Manual approach already includes an estimate for additional retrofit costs.Given Information, Assumptions, and Direct Capital Costs

We applied the Cost Manual approach to MRYS #1 to estimate the cost of adding SCR but did not include any estimates for the associated reheat systems because that
information was not made available to us. 2 Following is a discussion and comparison of specific combustion control (Advanced Separated Over-Fire Air = ASOFA) plus
stand-alone tail-end SCR (TESCR) cost items that warrant explanation:

• ASOFA Annualized Capital Cost = $403,719 based upon $4,277,000 DCC amortized over a 20-year life @ 7% interest (Cost Manual).

• ASOFA Annual O&M Cost (not levelized) = $65,776 cal culated from company BACT analysis minus the $1,631,000 lost generation cost 3 and adjusted to 100% availability.

• ASOFA Total Annual Cost = $469,494 . NDDH estimated $2,489,000/yr. The differences are primarily due to the uns upported cost of lost generation and the application of an improp er levelization factor.

• Fuel Sulfur Content was held at the pre-scrubbed value but would effectively
decrease for a TESCR and yield a smaller SCR.

• 29% Ammonia Solution Cost ($/lb) wa s taken from the BART analyses conducted by PacifiCorp in Wyoming b ecause Minnkota chose urea as the SCR reagent, primarily for safety reasons. However, according to the Institute of Clean Air Companies, 4 “With the proper controls, amm onia use is safe and routine.”

• Catalyst Cost ($/m 3 ) = $3,000 was taken from the BART analyses conducted by PacifiCorp in Wyoming because the Minnkota/Burns & McDonnell estimate of $7,500/m 3 was much higher than the $3,000 - $6,000/m 3 we typically see from
other consultants.

• Operating Life of Catalyst (hours) = 16,000 which appears to be the consensus estimate from the catalyst vendors.

• Natural gas unit cost ($/mcf) = $5 based upon current prices according to EIA.

• Natural gas for reheat (mcf) = 460,090 mcf (from Minnkota) and does not include NG to vaporize urea because ammoni a is used in this scenario.

2 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.

3 Minnkota estimated that retrofitting of ASOFA would result in 181 hr/yr of lost operating time due to maintenance of ASOFA, and that Unit 2 operation would drop to 8,048 hr/yr as a result. Minnkota installed ASOFA on Unit #2 in 2007 and availability increased from the pre-ASOFA 89% (7,792 hr/yr) average to the post-ASOFA 95% (8,256hr/yr).

4 May 2009 Institute of Clean Air Companies white paper titled “Selective Catalytic Reduction (SCR)
Control of NO

x Emissions from Fossil Fuel-F ired Electric Power Plants” Can Ammonia Be Handled Safely?

Yes. Concern over the handling of ammonia was initially raised as a problem with SCR technology applications due to the transportation and storage of a hazardous gas under pre ssure. However, large quantities of ammonia already are used for a variety of applications with an excellent overall safety record. (In 2006, 17 billion pounds of ammonia were produced in the U.S.) These applications include the
manufacture of fertilizers and a variety of other chemicals, as well as refrigeration. With the proper controls, ammonia use is safe and routine.

2• Volcatalyst = 634 m 3 for one reactor. The Cost Manual approach results in the reactor having four layers of catalyst plus one spare layer. Minnkota estimated three layers plus one spare with catalyst volume at 633 m 3

.

• Direct Capital Cost (DCC), A = $14 m illion before adjustments and $29 million with adjustments. Minnkota estimates DCC = $127 million for SCR plus ASOFA and the associated reheat equipment. Subtracting the $4 million
DCC cost of AS OFA results in DCC = $123 million for SCR plus the associated reheat equipment. We would like to see the separate cost estimates developed by Minnkota for the SCR as well as the reheat system so that we could directly compare our SCR cost estimate.

Total Capital Investment

The next portion of our cost analysis will assume that Minnkota has prope rly estimated its Direct Capital Costs for SCR plus the as sociated reheat equipment. We will also assume that the ratios of Indirect Capital Co sts (ICC) to Direct Capital Costs (DCC) used by the Cost Manual for stand-alone SCR also apply to the complete SCR plus reheat “package” evaluated by Minnkota. 5 Our SCR-only costs are estimated on the “ICC” tab
of the associated Excel workbook. Our eval uation of the Minnkota SCR+reheat system costs are shown on the “ICC (2)” tab.

• Total Indirect Installation Costs (TIIC), B = $9 million; this is 30% of DCC (because of our extra retrof it factor—instead, the Cost Manual estimates TIIC = 20% of DCC.) Minnkota estimates TIIC = $45 million for SCR plus associated equipment; this is 37% of Minnkota’s $123 million DCC and appears excessive when compared to the 20% ratio used by the Cost Manual. A more appropriate value for TIIC would be $25 million.

• Project Contingency, C = $9 million; this is 29% of (DCC+TIIC). (The Cost
manual estimates TIIC = 18% of (DCC+TIIC).) Minnkota estimates Project Contingency = $20 million for SCR plus associated equipment; this is 16% of (DCC = $127 million + adjusted TIIC = 25 million). A more appropriate value for Project Contingency would be $22 million.

• Total Plant Cost (TPC), D = $46 million = our estimate is 159% of the DCC upon which it is based. However, the Cost Manua l ratio (without extra retrofit factors)
is TPC = 138% of DCC. Minnkota estimates TPC = $188 million for SCR plus associated equipment; this is 153 % of DCC and appears excessive. A more appropriate value for TPC would be $170 million.

• Allowance for Funds During Construction (AFDC), E = $0. Minnkota estimates AFDC = $27 million for SCR plus associ ated equipment; this is not allowed by the Cost Manual.

• Total Capital Investment (TCI = D+G+H) = $47 million for SCR; this is 163% of the DCC upon which it is based. However, the Cost Manual ra tio (without extra retrofit factors) is TPC = 146% of DCC. Minnkota estimates TCI = $290 million for SCR plus reheat equipment ; this is 236% of DCC. In addition to overestimates and the invalid $27 million for AFDC noted above, Minnkota has

5 Minnkota appears to have used a similar approach.

3included $42 million for “Escalation” and $26 million for “Owner’s Costs” which are not allowed by the Cost Manual. Adjusting for these unsupported costs and applying the Cost Manual 146% ratio to the $123 million DCC, the resulting TCI for TESCR on MRYS #1 becomes $180 million ($701/kW).

Annual Costs & Cost-effectiveness

We believe that the Cost Manual approach is directly applicable and appropriate to
estimate annual costs of the stand-alone SC R (“Ann Cost” tab) and of the entire Minnkota SCR+reheat system (“Ann Cost (2) tab) using the corrected TCI derived above. The following discussion describes the cost estimates in the “A nn Cost (2)” tab.

• Annual Maintenance Cost = 1.5% of TCI (= $47 million). Minnkota has incorrectly assumed 3% of TCI to estimate $7 million. If we assume that Annual Maintenance Cost = 1.5% of the $ 180 million TCI for TESCR derived above,
then we estimate $3 million

.

• Annual Reagent Cost = $1 million for ammonia. Minnkota estimates $3 million
for urea.

• Annual Electricity Cost = $0.5 million. Minnkota estimates $6 million, primarily due to “lost generation.”

• Annual Catalyst Cost = $1 million. Minnkota estimates $1 million.

• Annual natural gas Cost = $2 million. Minnkota estimates $4 million, primarily due to use of NG to vaporize urea and a higher unit gas price.

• Direct Annual Cost (DAC) = $7 million a nd is the sum of the individual annual costs using our estimates modified to reflect a TCI of $180 million. (See the “Annual Cost (2)” tab. Minnkota estimated $20 million.

• Indirect Annual Cost = $17 million based a TCI of $180 million.

• Total Annual Cost (TAC) = $25 million for ASOFA+SCR plus reheat equipment based a TCI of $180 milli on (for ASOFA+SCR plus reheat equipment); Minnkota estimates TAC = $44 million and includes an improper
“levlization” factor to escalate cost.

• SCR Cost-effectiveness to remove 6,503 tpy of NO X is = $3,800/ton.

• Total Cost-effectiveness to remove 11,367 tpy of NO X is = $2,200/ton. NDDH estimates $4,615/ton

Results & Conclusions

Based upon the approach recommended by the Cost Manual, our estimate for the cost of adding only the ASOFA and SCR components of a Tail-End SCR (TESCR) system to MRYS #1 is a Total Capital Investment of $52 million ($201/kW) and a Total Annual Cost of $8 million. Using upper bound emissi on estimates, as recommended by the NSR Manual, combined with NDDH estimates of controlled emissions, we estimate that
ASOFA + TESCR could reduce NO X emissions by 11,367 tpy ( 6,503 tpy by the SCR alone). The Average Cost-Effectiveness fo r the ASOFA + TESCR system would be $700/ton and addition of the TESCR ha s a cost-effectiveness of $1,200/ton.

45 Because some method must be applied to re heat the gases leaving the wet scrubber, additional equipment would be required and additional costs would be incurred. It was not possible from the information provided to determine how much this additional equipment cost. Therefore, we compared the estimates presented by Minnkota to the ratios used by the Cost Manual to relate capit al and some operating costs to Total Direct Capital Cost. Minnkota incorrectly include d major costs for “Allowance for Funds During Construction,” “Escalation” and “Own er’s Costs” which are not allowed by the Cost Manual. Adjusting for these unsupporte d costs, the result ing Total Capital Investment for TESCR on MRYS #1 becomes $180 million ($701/kW) versus the Minnkota estimate of $295 million.

The Cost Manual can be applied for estimatio n of annual operating costs and we found
several differences between the Cost Manua l approach and the Minnkota estimates. Our
corrected Direct Annual Cost estimate is $7 million versus the Minnkota estimate of $20 million; the major differences are costs for “Lost Generation” and “Maintenance.” Our estimated Total Annual Cost (TAC) is $25 million. Minnkota estimates TAC = $44 million. Our estimate of the Average Cost-Effectiveness for the complete ASOFA + TESCR + reheat system would be $2,200/ton and addition of the TESCR has a costeffectiveness of $3,800/ton.