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 usually given in MW (Net) because this can be used to estimate 

lost generation costs due to outages. NGS is 750 MW net

SCR bypass included? No—typically 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 for 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 Factor is calculated by eqn. 2.6 on the “Boiler Calcs” tab (but is sometimes overridden manually).

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 from company estimates because the 

Cost Manual 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 directly from company estimates because the 

Cost Manual 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 typical for this control technology applied to 

tangential and wall-fired coal boilers.

Acceptable Ammonia Slip (ppm) is typically 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 Manual 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 catalyst needed.

Number of SCR reactor chambers is from SRP’s 8/17/10 report and affects Direct Capital Cost—

more reactor chambers = more cost. SRP’s approach is typical.

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 NOx 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 physical chemistry for anhydrous ammonia.

Reagent Density (lb/ft3 @ 60F) is basic physical chemistry for anhydrous ammonia.

Reagent Specific Volume (gal/ft3) is basic physical chemistry for anhydrous ammonia.

NOx Molecular Weight (g/mole) is molecular weight for NO2.

Number of Days of Storage for Ammonia = 14 from SRP’s 8/17/10 report and is typical.

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 by 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 typically 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%.

Inflation 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 recommends use of the 

Chemical Engineering Plant Cost Index (CEPCI) to make such an adjustment. In this 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/m3is from an SRP e-mail of 8/20/08 and is consistent with 

the range of catalyst costs we have seen for other proposed SCR installations, and slightly higher 

than industry data1(possibly because the SRP catalyst is a low-oxidation catalyst). SRP’s 

$8.000/m3estimate 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). In the 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. In this 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 entirely 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 by 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 becomes part of the TCI.

Include Allowance for Funds Allocated During Construction (AFUDC)? Although the Cost 

Manual does not allow inclusion of AFUDC, according to Larry Sorrels 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 commission decision. Otherwise, I do not agree with its inclusion.”

2

The value presented 

by SRP is the result of an analysis by Barry Drost (SRP) of how to apply Larry’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 Shepherd
(and its corresponding Total Capital Investment = TCI) that is well below IPM and industry 

data3—which I use as the basis for my decision-making described below:

1. In this cell C40 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 L24 of the 

“ICC & TCI” page along with any lost generation costs. The value in cell L24 will 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 TCI into cell C40 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 linking cell C40 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 C40 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, IPM would 

estimate $170/kW and $127.5 million TCI (“ICC & TCI” page cell L20).

4. The approach used by EPA Region 8 in its analysis of SCR costs for EGUs at the Leland 

Olds and MR Young power plants in ND is a hybrid in which the DCC provided by the 

source is adjusted and then multiplied by 141% to estimate the TCI. This “Adjusted 

Company SCR Direct Capital Cost (DCC)” in “Given/Assume” cell C37 is automatically 

carried to cell O4 of the “ICC & TCI” page and multiplied by 141% (cell M17 of the 

“ICC & TCI” page) and the resulting TCI appears in cells M20 and M21 in the “ICC & 

TCI” page. To use this approach, link cell C40 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” TCI was $168/kW (which was essentially the same as the IPM 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, 

respectively.

Catalyst Cost, Replacement ($/ft3) is the same as “Catalyst 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 Group
Operating Life of Catalyst (hours) = 40,000 is from SRP’s e-mail of 8/20/08 to EPA; typical 

catalyst life is assumed to be 24,000 hours.

Natural gas unit cost ($/mcf) is not relevant to NGS.

Of the other tabs, the most 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 TCI estimating option #4 (described above) is 

$21 million/yr and $3,400/ton; total annual cost and cost effectiveness of combustion controls 

and SCR are $22 million/yr and $2,100/ton, respectively.