**SCR Workbook Explanation based upon**  **OAQPS Control Cost Manual Section 4.2** Given/Assume page explanation New or Retrofit? This tells eqn. 2.39 on the Direct Capital Cost (DCC) page to include an extra cost if this is a retrofit. NGS is a retrofit, and this incurs an extra $7 million cost (cell E17 on the DCC tab) per unit. Generation capacity (MW) is u sually given in MW (Net) because this can be used to estimate lost generation costs due to outages. NGS is 750 MW net SCR by pass included? No

—ty

picall y not necessary. Fuel High Heating Value (Btu/lb) is from SRP’s 4/16/10 report, (Appendix A) Maximum Fuel Consumption Rate (lb/hr) determines the maximum gas flow rate and the size of the SCR reactor. The maximum hourly heat input f

or this boiler occurred in 2006 (from CAM data). (SRP assumed a 7,500 mmBtu/hr maximum heat input.) Average Annual Fuel Consumption (lb) is a factor in the estimation of average annual emissions and was calculated from the 2000

- 2010 average total heat input for this boiler from CAMD and the Fuel High Heating Value. Number of SCR Operating Days is assumed to be year- round for BART

. Plant Capacity

F actor is calculated by

e qn. 2.6 on the “Boiler Calcs” tab (but is sometimes overridden manuall y)

. Uncontrolled NOx Concentration (lb/mmBtu) is the pre - BART average from EPA CAM data ( for 2000

– 2010 in this case, since the combustion controls on Unit #1 were not installed until 2011 )

. LNB + OFA Total Capital Cost is usually taken directly

f rom comp any estimates because the Cost M anual has no method for estimating costs of combustion controls. (If I really doubted a company estimate, I would use EPA’s Cost Tool model to estimate those costs.) LNB + OFA Total Annual Cost is usually taken directl y from company e stimates because the Cost M anual has no method for estimating costs of combustion controls. (If I really doubted a company estimate, I would use EPA’s Cost Tool model to estimate those costs.) LNB outlet = SCR inlet NOx Concentration (lb/mmBtu) is the emission limit proposed in the SRP 8/17/10 report, Table 2

- 1.Required Controlled NOx Concentration (lb/mmBtu) is an **annual average** based upon expected

performance. SRP’s 8/17/10 report, Table 2

- 1, shows that the SCR would be designed to achieve an annual average of 0.05 lb/mmBtu, which is very ty pical for this control technology a pplied to tangential and wall

- fired coal boilers. Acceptable Ammonia Slip (ppm) is ty picall y 2 ppm. Lower slip would require a larger SCR reactor. Fuel Volume Flow Rate (ft3/min/mmBtu/hr) is based upon Table 2.4 in the Cost Manual. Because Table 2.3 in the Cost M anual has a gap between sub

-bituminous and bituminous coals, I set the decision point at the upper end of the sub

-bituminous heat range. This works well for NGS , which SRP says burns bituminous coal. Fuel Sulfur Content (%) is from SRP’s 4/16/10 report, (Appendix A) and affects SCR reactor size (eqn. 2.23 on the “SCR Reactor” tab)

— higher S = more catal ys t needed. Number of SCR reactor chambers is from SRP’s 8/17/10 report and affect s Direct Capital Cost

— more reactor chambers = more cost. SRP’s approach is ty pical. Number of spare catalyst layers is from SRP’s 8/17/10 report and affect reactor size Direct Capital Cost

— more layers = more cost. SRP’s approach is typical. ASR = Actual Stoichiometric Ratio indicates the actual amount of reagent needed to achieve the targeted NO x reduction and is a standard assumption. Stored Ammonia Concentration = 29 .4 % is a standard assumption for SCR using anhydrous ammonia. Reagent Molecular Weight (g/mole) is basic phys ical chemistry for anhydrous ammonia. Reagent Density (lb/ft3 @ 60F) is basic phys ical chemistry for anhydrous ammonia. Reagent Specific Volume (gal/ft3) is basic phys i cal chemistry for anhydrous ammonia. NOx Molecular Weight (g/mole) is molecular weight for NO 2 . Number of Days of Storage for Ammonia = 14 from SRP’s 8/17/10 report and is ty pical. Pressure Drop for SCR Ductwork (H2O") = 3 is a standard assumption and affects electricity consumption by

the SCR (“parasitic load”). Pressure Drop for each Catalyst Layer (H2O") = 1 is a standard assumption and affects electricity consumption by the SCR (“parasitic load”). Temperature at SCR Inlet (degrees F) is from SRP’s 8/17/10 report, Table 2

- 1 and has a major affect upon reactor size via eqn. 2.24 on the “SCR Reactor” tab. The “ideal” temperature is around 730 F, but deviations from this ideal can be handled b y a larger reactor chamber, up to a point

-- the optimum temperatures for the SCR process range from 480 °F to 800 °F.Equipment Life (years) is ty picall y assumed by

the Cost Manual to be 20 years for SCR. Annual Interest Rate is assumed to be 7% by the Cost Manual ; SRP used 9.8% in its 8/17/10 report; this increased the Total Annual Cost of SCR by 16%. In flation Since 1998: The Cost Manual is based upon 1998 $. EPA R9 has requested that NGS costs be expressed in 2010 $ to correspond to SRP’s 8/17/10 report. EPA re commends use of the Chemical Engineering Plant Cost Index (CEPCI) to make such an adjustment. Inthis case, those costs in eqn. 2.36 on the “DCC” tab that are based upon the 1998 data were adjusted by the 556.2/389.5 ratio of the CEPCI 2010/1998 indices. Catalyst Cost, Initial ($/ft3) = $7,000/m 3 is from an SRP e

-mail of 8/20/08 and is consistent with the range of catal ys t costs we have seen for other proposed SCR installations , and slightly higher than industry

data 1 (possibly

b ecause the SRP catal ys t is a low

- oxidation catal ys t). SRP’s $8.000/m 3 estimate in its 8/17/10 report exceeds all estimates we have seen in the continental US. SCR Direct Capital Cost (DCC) is the basis for estimates of Total Capital Investment (TCI) as calculated by

the Cost Manual (and by many consultants). Inthe Cost Manual approach, TCI always = 141% of the DCC. (See cell M17 of the “ICC & TCI” tab. ) The “Adjusted Company SCR Direct Capital Cost (DCC)” is an attempt to use company cost estimates to derive DCC based upon EPA guidance as to what is a legitimate DCC. Inthis case, I started with the “Company

SCR Total Capital Investment (TCI),” (cell C49), added an “Adjustment for Common costs” (cell C50) that SRP had attributed entirel y to Unit #3 but are shared by all three units, and subtracted an “Adjustment for included Indirect Capital Costs” (cell C51) and an “Adjustment for included “Owner's costs” (cell C52) which are not allowed by the Cost Manual. (Please see the appropriate tabs for a breakdown of these “adjustments.”) The result should be DCC as defined b y the Cost Manual. Lost generation (weeks) is from SRP’s 8/17/10 report which assumes that SCR tie

- in would occur during a normal major outage. If the tie

- in occurs during a minor outage, add two more weeks. This cost be comes part of the TCI. In clude Allowance for Funds Allocated During Construction (AFUDC) ? Although the Cost M anual does not allow inclusion of AFUDC, according to Larry S orrels of EPA, “ I agree with including AFUDC in a capital cost estimate if this is already included in the base case as per a utility c ommission decision. Otherwise, I do not agree with its inclusion. ” 2 The value presented by S RP is the result of an anal ys is by B arry Drost (SRP) of how to apply L arry ’s advice. Depending upon the decision, this cost **may** become part of the TCI. Override Cost Manual TCC? ($/kW)

. This is the most critical decision point. I have found that a straight

- forward application of the Cost Manual almost always produces an estimate of DCC

1 “ CURRENT CAPITAL COST AND COST

- EFFECTIVENESS OF POWER PLANT EMISSIONS CONTROL TECHNOLOGIES” Prepared by J. Edward Cichanowicz for Utility Air Regulatory Group January 2010 2 7/21/2010 e

-mail from Larry Sorrels to Don S hepherd(and its corresponding Total Capital Investment = TCI) that is well below IP M and industry

data 3

— which Iuse as the basis for my decision

-making described below: 1. Inthis cell C4 0 on the “Given/Assume” page , one can decide to use the Cost Manual estimate by

entering “No” (and “No” for AFUDC) and the Cost Manual estimate for TCI ($101/kW for NGS#1, including lost generation) will be carried into in cell L2 4 of the “ICC & TCI” page along with any lost generation costs. The value in cell L2 4 wil l also be used by

the “Ann Cost” page to estimate Maintenance costs and Indirect Annual Costs. 2. A second option is to enter the source’ s estimate of TCIinto cell C 4 0 on the “Given/Assume” page if it appears consistent (when converted to $/kW in cell O18 in the “ICC & TCI” page = $202/kW for NGS#1 ) with industry and IPM data and considering the circumstances. The Source’s TCI is thus used by l inking cell C4 0 on the “Given/Assume” page to O18 in the “ICC & TCI” page . If this option is chosen, the AFUDC “switch” in cell C39 on the “Given/Assume” page must be set to “No” to avoid double

- counting because it is assumed that AFUDC is already included in the company estimate. 3. A third option is to enter industry and IPM data into cell C4 0 on the “Given/Assume” page . If this option is chosen, the AFUDC “switch” in cell C39 on the “Given/Assume” page must be set to “No” to avoid double

- counting because it is assumed that AFUDC is already included in Industry and IPM data. For a 750 MW EGU like NGS, IP M would estimate $1 70/kW and $127.5 million TCI( “ICC & TCI” page cell L20). 4. The approach used by EPA Region 8 in its anal ysis of SCR costs for EGUs at the Leland Olds and MR Young power plants in ND is a hy brid in which the DCC provided by the source is adjusted and then multiplied by 1 41% to estimate the TCI. This “Adjusted Company SCR Direct Capital Cost (DCC)” in “Given/Assume” cell C37 is automaticall y carried to cell O4 of the “ICC & TCI” page and multiplied by 1 41% (cell M17 of the “ICC & TCI” page) and the resulting T CIa ppears in cells M20 and M21 in the “ICC & TCI” page. To use this approach, link cell C 40 in the “Given/Assume” page to cell M21 in the “ICC & TCI” page. Inclusion of AFUDC is based upon the situation. For NGS#1, the “basic” TCIwas $168/kW (which was e ssentially the same as the IP M estimate) in cell M21 on the “ICC & TCI” page . Addition of Lost Generation and AFUDC costs increased TCI to $134 million and $179/kW in “ICC & TCI” cells L24 and L25, respectivel y. Catalyst Cost, Replacement ($/ft3) is the same as “Catal ys t Cost, Initial,” unless (cheaper) recycled catalyst is used. Electrical Power Cost ($/kWh) is calculated from SRP’s letter of 7/29/08 to EPA and is probably overestimated. 29 .4 % Ammonia Solution Cost ($/lb) is calculated from SRP’s 8/17/10 report.

3 “OVERVIEW OF INFORMATION ON PROJECTED CONTROL TECHNOLOGY COSTS AND PERFORMANCE AS DEVELOPED FOR EPA’S INTEGRATED PLANNING MODEL (IPM)” October 15, 2010 Prepared by J. Edward Cichanowicz for the Utility Air Regulatory GroupOperating Li fe of Catalyst (hours) = 40,000 is from SRP’s e -mail of 8/20/08 to EPA; ty pical catal ys t life is assumed to be 24,000 hours. Natural gas unit cost ($/mcf) is not relevant to NGS. Of the other tabs, the mo st useful is the final summary “NGS #1 SCR (NPS)” tab that, per EPA guidance, presents the total costs of adding combustion controls and SCR, as well as the incremental cost of adding SCR to the combustion controls. For NGD #1, the incremental annual cost and cost
- effectiveness of adding SCR using TCIe stimating option #4 (described above) is $21 million/y

r and $3,400/ton; total annual cost and cost effectiveness of combustion controls and SCR are $22 million/yr and $2,100/ton, respectively

.