Appendix A: EPA’s evaluation of cost of Flue Gas Desulfurization (FGD) controls Nebraska Public Power District (NPPD) Geral d Gentlemen Station (GGS), Units 1 and 2

The following is an analysis of the cost effectiveness of the GGS BART analysis for dry scrubbers. Although we did not review the GGS BART analysis for wet scrubbers, we note that many of the same issues we discuss herein may apply to that analysis as well. We also note that with regard to the efficiency of wet scrubbers, “SO 2 removals of 95% are common and removals as high as 98% can be attained.” 1 This is a much higher efficiency than Nebraska assumed for
the GGS in its BART analysis.

Based on EPA’s re

- evaluation of Nebraska’s cost estimates, we do not consider GGS’s cost calculation for dry scrubbers to be cost prohibitive. However, we noticed some errors in that cost analysis, and believe it is appropriate to correct them. In so doing, it should be noted that this review is not intended to be comprehensive, and is only intended to address some of the more significant errors. There are several more cost items (e.g., 10% profit, 5% general and administrative, lab or, levelized outage cost, etc.) we may possibly address in a future analysis. In addition, we were hampered by the absence of some information that would have resulted in a more comprehensive analysis, such as the vendor quotes GGS apparently relied upon for its capital costs, and most design information (e.g., water, lime, electricity). Lastly, we note that in a BART analysis, the cost effectiveness in terms of annualized cost divided by tons of SO 2 removed ($/ton) must be balanced against the projected v isibility benefit. However, Nebraska assessed the visibility benefit of the installation of dry scrubbers assuming a SO 2 reduction to 0.10 lbs/MMBtu. As we discuss below, greater levels of control are achievable. Consequently, we believe it is likely th at the visibility benefit, if properly assessed, would be greater than what
Nebraska has modeled.

1. Engineering Procurement and Construction

GGS assumes an Engineering Procurement and Construction (EPC) fee of 20% of the total cost, but does not provide any discussion or explanation for this cost. The EPC fee for Units 1 and 2, and the auxiliary power do calculate to 20% of the total cost. However, the EPC fee for the common facilities, calculated on the basis of 20% of their total costs, calculates to $25,478,000, not $30,754,000 which is what GGS calculates. This unexplained deviation is carried through to the EPC calculation of $100, 367,000 for the total station. This could be a result of a note in the common facilities estimate (pdf26) that states “S EE AUX POWER EST” for an electrical cost. However, all electrical costs appear to be already included in the auxiliary power and fans costs. Adjusting the EPC fee to be 20% of total project would result in the total EPC fee to be $95,092,000 as opposed t o GGS' s calculation of $100,367,000.

Nevertheless, this fee is high in comparison to other BART analyses we have seen such as the Oklahoma Gas and Electric Sooner and Muskogee BART analyses, also performed by GGS’s contractor, Sargent and Lundy (S&L). In that cost analyses, S&L estimated engineering

1 Wet Flue Gas Desulfurization Technology Evaluation, Project Number 11311

- 000, Prepared For National Lime Association, January 2003, Prepared By Sargent and Lundy, page 13.and procurement, an "indirect capital cost," as 6.5% of the total direct costs 2 , which if applied here, would result in a much lower figure. In addition, the Control Cost Manual 3 estimates engineering and pr ocurement as 10% of the purchased equipment cost (as opposed to the total cost GGS employs), which would also result in a much lower figure. Although not supplied, GGS indicates in its BART analysis that all the major equipment items are based on vendor

q uotes. 4 Vendor proposals typically contain engineering and procurement costs associated with the equipment that is supplied. We have no reason to conclude that is not the case here, but invite GGS to provide documentation to the contrary, should it believ e this to be in error. The following items are identified by GGS as being supported by vendor quotes (retaining GGS’s designations and numbering for these items) in Appendix A to its BART analysis:

1. Lime Handling common to both Units

2. Lime Preparatio n per Unit

3. Absorber Area per Unit

4. Recycle Area per Unit

5. Baghouse Ash Handling System common to both Units

16. Baghouse Modifications per Unit

26. New booster ID fans

- All

The above items, therefore, should not be a part of the EPC calculation. Sim ilarly, the following items are identified by GGS as not being supported by vendor quotes and would be expected to be a part of the EPC calculation:

6. Flues including support steel per Unit

7. Control System Modifications per Unit

8. Rail Yard Extension c ommon to both Units

9. Subsurface and Foundation Work

- All

10. Civil Work

- All

11. Construction Work

- All

12. Pipe Racks common to both Units

13*. Chimney per Unit

2 Appendix A, Revised BART Cost

- Effectiveness Analysis for Flue Gas Desulfuriz ation at Coal

- Fired Electric Generating Units in Oklahoma: Sooner Units 1 & 2 Muskogee Units 4 & 5 Northeastern Units 3 & 4 Final Report,
October 2010.

3 EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/452/B

- 02

- 001, January 2002

4 Dry FGD An d Id Fan & Auxiliary Power Conceptual Design Costs Conceptual Cost Estimate Prepared For Nebraska Public Power District Gerald Gentleman Station, Units 1&2, Project No. 12194

- 001, February 7, 2008. See pdf pages 8

- 12.17. Demolition and Relocation

18. CEMS per Unit

- no change, use existing CEMS in chimney

19

. Water Treatment common to both Units

20. Instrument air compressor and dryer common to both Units

21. Field Painting

– All

22. Performance Testing

- All

23. Construction Support

- All

24. Piping per Unit

25. Installation

- All

27. Electrical

- All

*Note, GGS does not include any items numbered from 14 to 15, inclusive in the above list.

Furthermore, we have no reason to believe that the EPC fee should be 20%, as opposed to the 6.5% employed by S&L in its Oklahoma Gas and Electric (OG&E) BART cost evaluation
f

or the Sooner and Muskogee facilities. Therefore, we have recalculated the EPC fee to be 6.5% of the above items that are not supported by vendor quotes. This calculation appears in line 27 of appendix C to our TSD. We invite GGS to provide clarificatio n as to why the EPC percentage for units 1 and 2 should be higher that its vendor employed for the BART cost estimation for the
OG&E units.

2. Bond Fees

On pdf page 6 of Appendix A, GGS states that indirect costs include bond fees, and on pdf page 7, GGS states they are equal to 2.5% of $200M, which would be $5M. However, GGS does not state what this $200M figure represents. We agree that utilities incur some costs in issuing debt, but this cost is normally imbedded in the interest rate. However, in thi s case we cannot determine whether the interest rate GGS uses in its computations (5.25% nominal)
includes those costs. As we state in our response to comments in our Federal Implementation Plan (FIP) for Oklahoma: 5

In most cases, the issuer of corporate debt does not pay the underwriters directly for their service, but instead sells the bonds to the underwriters at a discount. The underwriters’ compensation comes from the difference between the price they pay for the bonds and the price at which they can sell them. Hence, the debt issuance costs do not represent a cash payment at the time the plant is built, but a small increment in the repayment at maturity, twenty or thirty years in the future. Thus, bond costs are usually

5 Response to Technical Comments fo r Sections E. through H. of the Federal Register Notice for the Oklahoma Regional Haze and Visibility Transp ort Federal Implementation Plan, Docket No. EPA

- R06

- OAR

- 2010

- 0190

, 12/13/2011, page 19.included as part of the cost o f debt, rather than the capital cost of the project.

We also question why the pollution control equipment cannot be financed in part with Pollution Control Bonds, at very low tax

- exempt interest rates

. Therefore, we exclude these costs
from our revised c ost analyses by subtracting $5M from the indirect costs for units 1 and 2 of $47,452,000. This calculation appears in line 31 of appendix C to our TSD. We invite GGS to provide documentation of these costs, which should include a detailed breakdown of th e Capital Recovery Factor (CRF), which itself includes the interest rate.

3. Escalation

GGS incorporates an escalation cost of $120,449,000, which it states on pdf page 7 of Appendix A, was estimated on the basis of 5.0% for Equipment, 7.0% for Material, 4.0% for Labor and 6.0% for Indirects. As we have discussed in our response to comments in our FIP for Oklahoma, 6 the Control Cost Manual employs the overnight cost method, which is the cost of a construction project as if the project is completed overni ght in current dollars. Thus, escalation of current dollars to future dollars is never valid under the Control Cost Manual overnight cost approach. Consequently, we have excluded escalation from our revised cost analysis. This calculation appears in lin e 32 of appendix C to our TSD.

4. Contingency

GGC incorporates a contingency cost of $148,745,000, which it states on pdf page 7 of Appendix A, was estimated at 20% of equipment, mater ial, labor and indirect costs. No information was provided to j usti fy the need for this rate. As we note earlier, GGS states that the lime handling and preparation, the absorber area, the recycle area, the baghouse ash handling system, the baghouse modifications, and the booster id fans are all supported by vendor quotes. Thus we would expect that the need for contingencies for these cost items would be minimized. As we discuss in our response to comments in our FIP for Oklahoma, 7

Under the overnight cost estimating method in the Cost Control Manual, contingency has a s pecific definition: "A contingency factor should be reserved (and applied to) only those items that could incur a reasonable but unanticipated increase but are not directly related to the demolition, fabrication, and installation of the system. For exampl e, a hundred year flood may postpone delivery of materials, but their arrival at the job site is not a problem unique to a retrofit situation." 8

The Control Cost Manual definition for the equipment included in the Manual that is most similar to the propose d controls is a wet scrubber for acid gases (similar to the spray dryer absorber) and a baghouse (included in a spray dryer absorber system). In both of these cases, the

6 Ibid , page 14

- 15, and elsewhere.

7 Ibid, page 20.

8 Con trol Cost Manual, Sec. 2.5.4, p. 2

- 30.Control Cost Manual specifies the contingency as 3% of the purchased equipment cost. 9 Therefore, we revised our cost analysis to incorporate a contingency of 3% of the purchased equipment cost. This calculation appears in line 34 of appendix C to our TSD.

5. Allowance for Funds Used During Construction

GGS incorporates an Allowance for Funds Used During Construction (AFUDC) cost of $83,302,000, in the “Other Cost” category

, which it states on pdf page 7 of Appendix A as being estimated to be 5% from 2009. As we discuss in our response to comments in our FIP for Oklahoma, 10

AFUDC is the cost of capital that is incurred to finance the project during the construction period. The overnight cost method is the cost of a construction project if no interest is incurred during construction, as if the project is completed overnight. Thus, AFUDC is never valid under the Control Cost Manual overnight cost approach. Neither is AFUDC a “site specific design or other condition[s] 11 ” that can be considered under the
RHR and the Control Cost Manual.

Therefore, we exclude these costs from our revised cos t analyses by subtracting $83,302,000 from the other costs category

. This calculation appears in line 35 of appendix C to our TSD.

6. Capital Recovery Factor

GGS does not include its calculation of a Capital Recovery Factor (CRF), which is necessary to calculate annualized (levelized) costs. However, using its real interest rate of 5.25% (which we adopt, but on which we form no opinion here), and its amortization life of 20 years, we can duplicate GGS’s capital cost of $80,875,000, using a CRF we calcula te of approximately
0.08195. 12 See line 40 of appendix C . However, applying the same formula to the levelized capital cost to GGS’s case in which the fan is sized to accommodate only the dry scrubber, should yield a figure of $80,444,000, instead of the $ 80,013,000 GGS calculates.

Nevertheless, we take issue with GGS’s assumption of a 20 year amortization life, which equates to an assumption that the dry scrubber has an operational life of only 20 years. As we discuss in our response to comments in our F IP for Oklahoma, 13 the annualization period should equal the projected service life of the equipment:

In the section of the Control Cost Manual on the capital recovery factor, the subject of this comment, control equipment lifetime is clearly defined
as the entire life of the control. For example, on page 2

- 19, the Control

9 Control Cost Manual, Section 5.2, Post

- Combustion Controls, Chapter 1: Wet Scrubbers for Acid Gas, Table 1.3 and Section 6, Chapter 1: Baghouses and Filters, Table 1.9.

10 Ibid, pages 15

- 19.

11 70 FR 39166.

12 CRF =(0.0525*(1.0525^20))/(1.0525^20

- 1) = 0.08195. Levelized Capital Cost = CRF*Total Capital Cost.

13 Response to Technical Comments for Sections E. through H. of the Federal Register Notice for the Oklahoma Regional Haze and Visibility Transport Federal Implementation Plan, Docket No. EPA

- R06

- OAR

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, 12/13/2011, pages 36

- 39

.Cost Manual states: “For each alternative: calculate a discounting factor each year over the life of the equipment ....” and on page 2

- 21: “In essence, annualization involves establishing an annual "payment" sufficient to finance the investment for its entire life , using the formula...[CFR]...where PMT is the equivalent uniform payment amount
over the life of the control , n, at an interest rate, i.” 14 The variable n in the CRF equation used to annualized total capital investment is thus the actual life of the control, as we used in our revised cost analysis, and not the economic life as argued in this comment.

While Table 2.3 in the Control Cost Manual does mention an "economic life," the t ext proceeding the table defines "economic life" as "useful life." 15 The term "useful life" as used in the Control [Cost] Manual is the same as the actual service life, at the end of wh ich the equipment is replaced. See, for example, page
2

- 18: “While pay back considers both projects to be equal, the second project would actually cost more over the ten year period because it would have to be replaced at the end of its useful life.” See also page 2

- 20: “So, instead of paying up front for all the future cost s of installation, maintenance, and operation of a pollution control device (NPV analysis), what if the payment could be equalized (in constant net present value dollars) over the life of the control ?” 16 Thus, under the Control [Cost] Manual definition, eq uipment is replaced at the end of its useful life and is synonymous with service life or equipment life.

In addition, in our response to comments referenced above, we reviewed information we presented in our proposal in which we demonstrate that the

serv ice life of a dry scrubber is easily 30 years. GGS has not offered to execute
an enforceable commitmen t to shut down after 20 years. Thus, we adopt a dry scrubber service life here of 30 years in our calculation of the CRF, which equates to approximately 0.06691. 17 We use this CRF in our recalculation of GGS’s levelized costs. This calculation appears in line 40 of a p p e n d i x C to our TSD.

7. Operation and Maintenance

GGS employs a levelized fixed O&M cost of $7,812,000 and a levelized variable O&M

co st of $19,994,000. Although GGS does not document the individual cost items contained in the fixed O&M cost, we can duplicate the fixed O&M cost by using the information contained in the financial model cases 13 and 14 on pdf 4 and 5.

However, we cann ot duplicate the levelized variable O&M cost. GGS states on page 16 of its BART analysis, 18 that variable O&M costs include, “ the cost of consumables, including reagent (lime or limestone), by

- product management, bag replacement for the baghouse, water

co nsumption, and auxiliary power requirements. Auxiliary power costs reflect the additional

14 Control Cost Manual, pp. 2

- 19, 2

- 21, emphasis added.

15 Control Cost Manual, p. 26.

16 Control Cost Manual, pp. 2

- 18, 2

- 20.

17 CRF=(0.0525*(1.0525^ 3 0))/(1.0525^ 3 0

- 1) = 0.0 6691.

18 REVISED Best Available Retrofit Technology (BART) Analysis for Units 1 & 2 Gerald Gentleman Station, Sutherland, Nebraska, February, 2008.power requirements associated with operation of the new FGD control system, including operation of any new ID fans as well as the power requirements for the absorber pumps, reagent handling, reagent preparation, and by

- product handling.” Adding the individual costs for these
items from the financial model cases 13 and 14 does not result in the variable O&M cost GGS lists on pdf page 3 of Appendix A.

There are no c alculations provided to support the lime, water and waste disposal costs. Furthermore, we note that the financial model cases 13 and 14 list the annualized tons of SO
x removed to be 40,426 for unit 1 and 41,003 for unit 2. Because as we discuss below, ea ch one of
these unit reductions exceeds the total historical SO 2 emission of both units 1 and 2 together, we have reason to doubt the validity of the O&M costs that were apparently based on these reductions. Therefore, although we adopt these O&M costs in our analysis, we invite GGS to provide documentation for them. Furthermore, because these costs were calculated based on an assumed 20 year amortization period (20 year scrubber service life), as discussed above, they must be adjusted to a more reasonabl e 30 year period. We note that GGS uses the same CRF of approximately 0.08195 in model cases 13 and 14. Therefore, we adjust the levelized capital, outage, and O&M costs by multiplying GGS’s figures by the ratio of our CRF to their CRF. 19

This calculatio n appears in lines 47

- 51 of a p p e n d i x C to our TSD.

Later, we discuss how we further adjusted GGS’s levelized variable O&M cost to
account for the smaller amount of SO 2 removed, due to our adjusted SO 2 baseline.

8. SO 2 Emission Baseline

On page 15 of its BART analysis, GGS calculates its SO 2 emission baseline based on applying what it states is a 24 hour maximum emission rate of 0.749 lbs/MMBtu (2001

- 2003) to a maximum heat input of 15,175.5 MMBtu/hr, based on a 100% capacity factor. This results in a emissions baseline of 49,785 tons/yr. 20 We believe this calculation does not appropriately represent GGS’s SO 2 emission baseline, and is in fact too high.

The Regional Haze Rule provides the following regarding the calculation of the BART
emissions basel ine:

The baseline emissions rate should represent a realistic depiction of anticipated annual emissions for the source. In general, for the existing sources subject to BART, you will estimate the anticipated annual emissions based upon actual emissions f rom a baseline period. When you project that future operating parameters (e.g., limited hours of operation or capacity utilization, type of fuel, raw materials or product mix or type) will differ from past practice, and if this projection has a deciding ef fect in the BART determination, then you must make these parameters or assumptions into enforceable limitations. In the absence of enforceable limitations, you calculate baseline emissions based upon continuation of past practice.

19 EPA’s levelized costs = GGS’s levelized costs * (0.06691/0.08195).

20 (0.749 lbs/MMBtu) * (15,175 MMBt u/hr) * (8,760 hrs/yr) * (ton/2,000 lbs) = 49,785 tons/yr.We see no indications that the GGS’s future operating practices are proj ected to deviate from the past. Therefore, similar to our action with regard to the emission baseline of the Four Corners Power Plant, 21 we adjust GGS’s SO 2 emission baseline to better reflect its historical
emissions. GGS states on page 2 of its BART analysis that it used a baseline period of 2001

- 2003, which was the baseline emission rate period for BART modeling in Nebraska. We have
downloaded emissions data for GGS from our Clean Air Markets web site 22 and have calculated the average total station SO 2 emissions for GGS Units 1 and 2 to be 31,513 tons/yr for the three year period of 2001

- 2003. We note that based on GGS’s stated nameplate capacity of Units 1 and 2 (665 and 700 MW, respectively), we calculate capacity factors for Units 1 and 2 to range from 89% to 94% and 77% to 85%, respectively, from 2001

- 2003. Our analysis assumes this historic usage is not significantly altered in the future. A s ummary of this data appears in

a ppendix B to our TSD.

9. SO 2 Emissions Reduction

On page 15 of its BART analysis, GGS calculates that as a result of the installation of dry scrubbers at both units 1 and 2, its SO 2 emission baseline of 49,785 tons/yr would be reduced to 9,970 tons/yr, resulting in a reduction of 39,815 tons of SO 2 annually. This assumes an
uncontrolled SO 2 emission rate of 0.749 lbs/MMBtu and a controlled SO 2 emission rate of 0.15 lbs/MMBtu, which equates to a scrubber efficiency of approximately 80%. Because, as noted above, we propose to find the SO 2 emission baseline of 49,785 tons/yr to be too high, we must correspondingly adjust the projected emission reduction.

Using the same emissions data described above from the three year averaging period of
2001

- 2003, we have calculated the three y ear average annual SO 2 emissions for units 1 and 2 of
the GGS to be 0.565 lbs/MMBtu. 23 Reducing this to a controlled SO 2 emissions level of 0.15 lbs/MMBtu results in a scrubber efficiency of approximately 73.5%. Applying this level of control to our adju sted GGS SO 2 emission baseline of 31,513 tons/yr would reduce it to 8,366 tons/yr, resulting in a reduction of 23,147 tons of SO 2 annually. Applying the same approximate 80% level of reduction GGS assumes to our adjusted GGS SO 2 emission baseline of 31,51 3 tons/yr would reduce it to 6,311 tons/yr, resulting in a reduction of 25,202 tons of SO 2 annually. 24 However, as we have demonstrated in our Oklahoma FIP decision, which also involved the cost effectiveness calculation of dry scrubbers on boilers burning a similar Powder River Basin coal, dry scrubbers are capable of much greater control efficiencies than the 80%
level that GGS assumes. 25 We see no reason to believe that the GGS is not capable of the same level of control. Therefore, for the purpose of c alculating the cost effectiveness of dry scrubbers at the GGS, we have assumed the same SO 2 emission limit of 0.06 lbs/MMBtu, which results in a scrubber efficiency of approximately 89.4%. Applying this level of control to our adjusted

21 74 FR 44321.

22 http://camddataandmaps.epa.gov/gdm/index.cfm?fuseaction=emissions.wizard

23 See Attachment B to our TSD. Based on adding the station total pounds of SO 2 emissions from 2001

- 2003 and dividing by the station total heat input from 2001

- 2003.

24 (39,815/49,785)*31,513 = 25,202.

25 Response to Technical Comments for Sections E. through H. of the Federal Register Notice for the Oklahoma Regional Haze and Visibility Transport Federal Im plementation Plan, Docket No. EPA

- R06

- OAR

- 2010

- 0190

, 12/13/2011, Section II.

, Comments Relating to Our SO2 BART Emission Limit , and elsewhere.GGS baseline of 31, 513 tons/yr would reduce it to 3,347 tons/yr, resulting in a reduction of 28,166 tons of SO 2 annually.

In order to calculate the cost effectiveness in terms of the annualized cost (total levelized capital, outage, and O&M cost) divided by the tonnage of SO 2 reduced, we must further adjust GGS’s calculation of the variable O&M cost, to account for the reduced mass of SO 2 that would be treated by the scrubber due to the reduction in the SO 2 baseline. In other words, we assume
GGS instructed its vendors to cost a dry scrubber system capable of removing 39,815 tons of
SO 2 , which as stated above, it indicates in its BART report would be the tonnage reduced from its baseline. This would require an amount of lime and water sufficient to treat this mass of SO 2 , with a commens urat e cost for waste disposal. Because we have reduced the GGS SO 2 baseline to a more realistic value, under all the treatment scenarios discussed above, the mass of SO 2 reduced would be much less that t he 39,815 tons/yr GGS assumed. There fore, as the variable O&M costs include the cost of lime, water, and waste disposal costs, we believe it is reasonable

to r educe those costs accordingly. However, GGS has not disclosed its d esign criteria for these
items. Therefore, we approximate the re duction in the variable O&M costs in the treatment scenarios discussed above, by multiplying GGS’s variable O&M costs by the ratio of the corresponding EPA SO 2 reduction divided by GGS’s SO 2 reduction. 26 Should GGS believe this approach is overly conservat ive, we invite it to provide the proper design criteria to enable this adjustment to be made more accurately.

10. Cost Effectiveness

We calculate the cost effectiveness for these various scenarios in a p p e n d i x C to our TSD.
These results are summarized here:

Range of GGS Dry Scrubber Cost Effectiveness
SO 2 Baseline Uncontrolled
SO 2 Emission
Level (lbs/MMBtu) Controlled
SO 2 Emission

Level (lbs/MMBtu) Percent
Reduction SO 2 Emission
Reduction (tons) Cost
Effectiveness ($/ton)

GGS 49,785 0.749 0.15 80% 3 9,815 2,726
EPA 31,513 0.565 0.15 73.5% 23,147 2,310
EPA 31,513 0.565 0.11 80% 25,202 2,156
EPA 31,513 0.565 0.06 89.4% 28,166 1,972

We find that the cost effectiveness of SO 2 scrubbers for units 1 and 2 of the GGS facility should range between $1,972 /ton and $2,310/ton.

26 For example, baseline = 31,513, SO 2 emission limit = 0.15, reduction = 23,147 tons SO2: Variable O&M = GGS

va riable O&M*(23,147/39,815).