Oklahoma Gas & Electric 

Sooner Units 1 & 2, Muskogee Units 4 & 5 

Dry FGD BART Analysis Follow-Up Report 

Prepared by: Sargent & Lundy LLC 

Chicago, Illinois

December 28, 2009 
Oklahoma Gas & Electric December 28, 2009 

BART Analysis Follow-Up Report Project No. 11418-019 

TOC-1 

Table of Contents

Page

Table of Contents 1 

1.0 INTRODUCTION 1 

2.0 2009 COST ESTIMATES AND COST EFFECTIVNESS UPDATE 4 

2.1 2009 Conceptual Capital Cost Estimate 4 

2.2 Methodology for Developing the Conceptual Cost Estimate 5 

2.3 Comparison between 2008 and 2009 Cost Estimates 6 

2.4 Updated Total Annual Costs and Cost Effectiveness 7 

2.4.1 Capital Costs 8 

2.4.2 Operating Costs 9 

2.4.3 2009 Cost Effectiveness 11 

2.5 Comparison of 2009 Capital Costs against Other Published Capital Cost Information 16 

2.5.1 Colorado Department of Public Health and Environment Report 16 

2.5.3 “Update: What’s That Scrubber Going to Cost” article 18 

3.0 BART Report Comparisons 19 

3.1 Comparison of Baseline SO2 Emissions 19 

3.2 Comparison of Modeled Visibility Improvement 20 

4.0 Conclusions 23 
Oklahoma Gas & Electric December 28, 2009 

BART Analysis Follow-Up Report (Rev. 1) Project No. 11418-019 

Page 1 

1.0 INTRODUCTION 

In spring 2008, S&L completed Best Available Retrofit Technology (BART) evaluations for 

Sooner Units 1 & 2, Muskogee Units 4 & 5, and Seminole Units 1, 2, & 3. The BART 

evaluations included an analysis of potentially feasible retrofit emission control technologies to 

control emissions of nitrogen oxide (NOX), sulfur dioxide (SO2), and particulate matter (PM10) 

from each unit. BART evaluations included in the 2008 reports followed the five-step BART 

determination process described in Appendix Y to 40 CFR Part 51 “Guidelines for BART 

Determinations under the Regional Haze Rule.” The five-step BART determination process 

includes: 

Step 1: Identify all available retrofit control technologies; 

Step 2: Eliminate technically infeasible options; 

Step 3: Evaluate the control effectiveness of the remaining control options; 

Step 4: Evaluate impacts and document the results; and 

Step 5: Evaluate visibility impacts. 

Step 4 of the process involves an evaluation of the potential environmental, energy, and economic 

impacts to the facility associated with the installation and operation of the technically feasible 

retrofit control options. To address economic impacts, S&L prepared a cost estimate for each 

technically feasible retrofit control option. To the extent possible, cost estimating methodologies 

described in the Office of Air Quality Planning and Standards Cost Control Manual (“OAQPS 

Cost Manual”) were used to estimate annual costs. Cost estimates were used to evaluate the cost 

effectiveness of each technology in terms of annual dollars per ton of pollutant removed. 

On November 13, 2009, the State of Oklahoma published its draft Regional Haze Implementation 

Plan Revision (“Regional Haze Implementation Plan”). The draft implementation plan required 

OG&E to control SO2 emissions from Sooner Units 1 & 2 and Muskogee Units 3 & 4 with dry 

flue gas desulfurization (DFGD) control systems as BART. In the draft implementation plan, the 

Oklahoma Department of Environmental Quality (DEQ) questioned the cost estimates included in 

OG&E’s 2008 BART evaluation, stating “OG&E’s estimated costs were found to be substantially 

higher than those reported for similar projects.” DEQ based its BART determination on revised 

cost estimates, both capital and operating and maintenance (O&M) costs, as well as a revised cost 

effectiveness evaluation. 
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Specifically, DEQ questioned the following items in the OG&E DFGD cost estimates: 

a) The higher than expected DFGD capital costs when compared to other sources of 

information and the availability of back up information to support the cost estimates. 

b) The high cost effectiveness ($9,625 to $10,843 $/ton) compared to other BART evaluations. 

c) What the 2009 capital costs would be considering costs likely peaked in 2008 around the 

time of the original BART report and have likely fallen since then. 

d) The accuracy of using factors from the EPA Air Pollution Control Cost Manual to develop 

annual operating costs given the large escalation in capital costs over the last few years. 

The economic impact analysis included in the 2008 OG&E BART determinations calculated the 

cost effectiveness of DFGD control technology for Sooner Units 1 & 2 and Muskogee Units 4 & 

5 on a dollar per ton of pollutant removed basis. Annual costs were calculated by adding annual 

operation and maintenance (O&M) costs to the annualized capital cost of a DFGD control 

system. To the extent possible, methodologies described in the OAQPS Cost Manual were used 

to estimate capital and O&M costs. Cost effectiveness ($/ton) of a DFGD was calculated by 

dividing the total annual cost ($/yr) by the reduction in annual emissions (ton/yr). 

 

In addition to comments from DEQ, on December 4, 2009, the U.S. Department of the Interior, 

U.S. Fish and Wildlife Service (FWS), in consultation with the National Park Service (NPS) 

submitted comments to DEQ regarding the draft Regional Haze Implementation Plan. FWS/NPS 

agreed with DEQ that costs presented by OG&E for SO2 control were excessive. To respond to 

DEQ and FWS/NPS questions and concerns, S&L prepared the following: 

a) Updated 2009 Conceptual Capital Cost Estimates

The original 2008 BART report capital cost estimates were study type +/-30% estimates 

based primarily on conceptual cost estimates prepared for similar projects that were scaled 

to account for major differences. The 2009 conceptual capital cost estimates (included 

herein) for all four OG&E coal fired BART-applicable units (i.e., Sooner Units 1 & 2 and 

Muskogee Units 4 & 5) are based on project-specific vendor quotations for certain major 

equipment items and inputs developed by performing preliminary project engineering. The 

2009 conceptual capital cost estimates are in the +/-20% accuracy range. A comparison of 

the revised capital cost estimates against the sources cited by DEQ in the draft Regional 

Haze Implementation Plan is also included. The draft schedule included in Attachment A, 

assumes the Muskogee work will take place after the Sooner work; therefore, the Muskogee 

cost estimate has additional escalation costs included. 
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b) Operating Cost Estimates

Operating costs included in the original 2008 BART report were primarily based on default 

factors taken from the OAQPS Cost Manual and U.S.EPA’s Coal Utility Environmental 

Cost (CUECost) model. Updated operating costs included in this report were developed by 

S&L using OG&E supplied tax, wage, financial, and insurance information, as well as 

industry standards and vendor quotations. 

 

c) Updated Cost Effectiveness Estimates

The updated conceptual capital cost and operating cost estimates were used to calculate 

revised cost effectiveness estimates. 

d) Alternative Methods for Calculating Reductions in Annual Emissions and Visibility Impacts

FWS/NPS also questioned the methodology used by OG&E to calculate the amount of 

pollutant removed with DFGD controls. The amount of pollutant removed (tons/year) 

has a direct effect on the cost effectiveness of the pollution control system. To address 

the FWS/NPS comments, emission reductions from each of the OG&E units were 

calculated based on using two different baseline emission rates and three different post 

DFGD emission rates. This was done to show the effect on the cost effectiveness 

calculations, and to “envelope” the cost effectiveness calculations. Cost effectiveness in 

terms of modeled visibility improvements at affected Class I Areas ($/dV) were also 

revised to reflect the updated cost estimates. 

e) Comparison against BART submittals from similar projects 

Results of the OG&E BART cost effectiveness impacts ($/ton and $/dV) are compared 

against impacts reported in other BART evaluations. 
Oklahoma Gas & Electric December 28, 2009 

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2.0 2009 COST ESTIMATES AND COST EFFECTIVNESS UPDATE 

2.1 2009 CONCEPTUAL CAPITAL COST ESTIMATE 

The 2009 conceptual capital cost estimate and supporting information for all four OG&E coalfired BART-applicable units are included in Attachment A. Table 1 provides a summary of the 

Sooner and Muskogee 2009 conceptual capital cost estimates. Cost estimates were prepared for 

each generating station, and divided evenly between the generating units. 

Table 1 

2009 Capital Cost Estimates 

Item Sooner Unit 1 or Unit 2 

2009 Cost Estimate 

Muskogee Unit 4 or Unit 5 

2009 Cost Estimate 

Direct Costs $162,651,000 $167,572,100 

Indirect Costs $24,045,000 $24,801,000 

Escalation $23,301,000 $31,638,600 

Sales Tax $0 $0 

Contingency $29,337,000 $31,552,100 

AFUDC & Bond Costs $52,960,000 $61,629,800 

TOTAL CAPITAL COST $292,294,000 $317,193,600 

Cost Per kw (gross) $514 $555 

The conceptual cost estimates provided in Attachment A take into account the retrofit difficulty 

that can be expected from the existing site configurations. In degree of difficulty, the retrofits at 

Sooner and Muskogee could be described as average. 

At Sooner, the new DFGD locations are relatively clear but Unit 1 is tightly bounded on the east 

side by two coal conveyors that supply both units and on the west by high voltage ductbank, ash 

piping, and circulating water piping. This existing equipment creates a narrow construction 

corridor for installing the DFGD equipment. As a result, the Sooner DFGD has a long narrow 

configuration with relatively long ductwork runs. There is also some ash piping and supports 

near the existing chimney and ID fans that would have to be relocated to accommodate the new 

ductwork. The existing storm sewer system in the new DFGD area would have to be completely 

removed and reinstalled to accommodate the new equipment foundations. A main east-west 

underground piping run also goes through the new DFGD area and would have to be relocated. 

These site-specific retrofit challenges, including equipment relocations, have been taken into 

consideration in the Sooner conceptual cost estimate. 
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At Muskogee, the new DFGD locations are also relatively clear except for a coal conveyor 

running in the east-west direction that supplies both units. This conveyor is only 330’ north of 

the Unit 4 and 5 chimneys and results in the new baghouses and ID booster fans being located 

north of the conveyor. Thus the new ductwork is required to straddle the conveyor and associated 

access road which creates longer than normal ductwork runs and piperacks. Another retrofit 

difficulty is the proximity of the existing ID fans to the chimney. In their current location, it’s not 

possible to modify the ID fan outlet ductwork to supply the new SDAs. As a result, the ID fans 

will have to be relocated during the tie-in outage as indicated on the Muskogee GA drawings. 

Like Sooner, the existing storm sewer system in the DFGD area would also have to be completely 

removed and reinstalled to accommodate the new equipment foundations. These equipment 

relocations have been taken into consideration in the Muskogee conceptual cost estimate. 

2.2 METHODOLOGY FOR DEVELOPING THE CONCEPTUAL COST ESTIMATE 

S&L developed the 2009 capital cost estimates using the following methodology: 

• Plant design data were used to develop datasheets to specify the dry FGD, baghouse, and ID 

booster fan operating conditions. The datasheets were issued to various manufacturers to 

obtain budgetary quotations. Costs obtained from these quotations were used to derive the 

pricing used in the capital cost estimate. The cost development for the spray dryer absorbers 

and baghouse used in the estimate is described in Attachment A. 

• A general arrangement (GA) drawing was developed using the information received in the 

budgetary quotations. The GA drawing was used to estimate the major installation 

quantities for the project including ductwork, structural steel, foundations, relocations, 

cable, and pipelines. 

• A motor list was assembled and used to develop the auxiliary power system sizing and 

quantities. 

• Mass balances were prepared and used to size the flue gas, material handling, material 

storage, and piping systems. 

• A schedule was developed to estimate escalation and AFUDC costs. It was assumed the 

new DFGDs would come on line at six month intervals with the last unit being completed at 

Muskogee near the end of 2015. 

• Range estimating techniques were used to identify the appropriate amount of contingency to 

obtain a 95% confidence level. The contingency level was approximately 14%. 

• A design and cost basis document was prepared to document the major assumptions and 

inputs for developing the cost estimate. 
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• Labor cost estimates were developed using Oklahoma area wage rates, installation 

quantities, and installation rates taken from the S&L database. 

This methodology provides a conceptual capital cost estimate with accuracy in the range of 

±20%. This methodology provides a better estimate of the capital costs associated with installing 

DFGD control systems, and a more accurate estimate of the actual costs that OG&E would incur 

to install DFGD at the Sooner and Muskogee Stations. 

2.3 COMPARISON BETWEEN 2008 AND 2009 COST ESTIMATES 

A comparison of the 2008 and 2009 cost estimates for the Sooner and Muskogee Stations is 

provided in Table 2. 

 

Table 2 

Sooner Unit 1 or Unit 2 

2008 and 2009 Capital Cost Estimate Comparison(1)

Sooner Unit 1 or Unit 2 Muskogee Unit 4 or Unit 5 

Item 2008 Cost 

Estimate 

2009 Cost 

Estimate 

2008 Cost 

Estimate 

2009 Cost 

Estimate 

Total Costs ($) $390,406,000 $292,294,000 $373,106,000 $317,193,600 

Cost per kw-gross ($/kw) $686 $514 $652 $555 

Cost Difference (%) Base -25% Base -15% 

Contingency ($) $56,598,000 $29,337,000 $54,089,000 $31,552,100 

(1) Total Costs for DFGD summarized in this table are divided equally between the two units at each station. 

Total Costs for DFGD at the Sooner Station will be $584,588,000, and total costs at the Muskogee Station 

will be $634,387,200. 

Major factors contributing to the reduction of costs from 2008 to 2009 include: 

a) Direct Costs

The 2008 estimate was prepared when the demand for DFGD systems was high and costs 

were near their peak. It is estimated that major equipment costs have dropped 

approximately 15% to 20% since this time. 

b) Contingency Costs

The 2009 estimate was based on vendor quotations for major equipment and preliminary 

engineering to develop quantities. As a result of this additional cost certainty, the 

contingency factor in the 2009 estimate (14%) is approximately 6% lower than the 2008 

estimate. The difference in contingency amounts between the two estimates is illustrated in 

Table 2-2. 
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c) Escalation Costs

The estimate of future escalation is lower in 2009 than it was in early 2008 when prices had 

been rapidly increasing over the previous three years. The difference in overall project 

escalation factors is about 10%. 

The cumulative effect of changes in the above three cost items, with all other things being equal, 

would be about a 20% to 30% reduction in pricing from 2008 to 2009. The actual decrease was 

about 25% which falls into this range. We believe this validates the capital costs provided in the 

2008 estimate. 

2.4 UPDATED TOTAL ANNUAL COSTS AND COST EFFECTIVENESS 

In general, total annual costs are the sum of the capital recovery costs and annual O&M costs. 

Cost effectiveness of a pollution control system is calculated by dividing the total annual cost of 

the control system ($/year) by the total annual quantity of pollutant removed by the system 

(tons/year); where: 

- Annual Cost (Reference Year $/year) = Annualized Capital Costs + Annual Operating 

Costs; 

- Annualized Capital Costs (Reference Year $/year) = Total Capital Requirement x Capital 

Recovery Factor; 

- Total Capital Requirement (Reference Year $) = All capitalized expenses as of the 

commercial operating date, including direct costs, indirect costs, and allowance for funds 

used during construction (AFUDC); 

- Capital Recovery Factor = The factor that converts the Total Capital Requirement into 

equal annual costs over the depreciable life of the asset, accounting for OG&E returns on 

debt and equity and income taxes, expressed in real terms (i.e., inflation removed); and 

- Annual Operating Costs (Reference Year $/year) = Variable O&M Costs + Fixed O&M 

Costs + Indirect Operating Costs. 

The following sections describe the derivation of these components of the cost estimate. 
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BART Analysis Follow-Up Report (Rev. 1) Project No. 11418-019 

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2.4.1 Capital Costs

Conceptual capital costs for the DFGD control projects at each OG&E station were calculated 

using the methodology described in Section 2.2. The total capital requirement (TCR) is the 

sum of direct costs, indirect costs, contingency, escalation, and allowance for funds used 

during construction. Direct costs include equipment, material, labor, spare parts, special 

tools, consumables, and freight. Indirect costs include engineering, procurement, 

construction management, start-up, commissioning, operator training, and owner's costs. 

Escalation and AFUDC were calculated from the estimated distribution of cash flows during 

the construction period and OG&E's before-tax weighted average cost of capital of 

8.66%/year. The 37-day tie-in outage for each unit is assumed to be coordinated with the 

normal 5-week scheduled outage such that incremental replacement cost is negligible. 

The TCR for each unit is summarized in Tables B-1 through B-4 in Attachment B. 

Capital Recovery Factor 

The capital recovery factor converts the TCR into equal annual costs over the depreciable life 

of the asset, accounting for OG&E returns on debt and equity and income taxes, expressed in 

real terms (i.e., inflation removed). These are also referred to as levelized capital charges. 

Property taxes and insurance are sometimes included with the capital charges, but are 

classified in this analysis as part of the Indirect Operating Costs to be consistent with the 

BART reports. The economic parameters used to derive the levelized capital charges are 

summarized in Table 3. 

Table 3 

Economic Parameters to Derive Levelized Capital Charges 

Commercial Operation Date (Reference Year) 

 Sooner 2014 

 Muskogee 2015 

Depreciable Life 20 years 

Inflation Rate 2.50%/year 

Effective Income Tax Rate – Federal and State 38.12% 

Common Equity Fraction 0.557 

Debt Fraction 0.443 

Return on Common Equity 

 Nominal 10.75%/year 

 Real 8.05%/year 

Return on Debt 

 Nominal 6.03%/year 
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 Real 3.44%/year 

Discount Rate (after-tax cost of capital) 

 Nominal 7.64%/year 

 Real 5.43%/year 

Tax Depreciation 20-year 

straight line 

Levelized Capital Charges (real) 10.36%/year 

Based upon the above parameters, the real levelized capital charge rate (capital recovery 

factor) is 10.36%/year. The derivation of this value is shown in Table B-5 in Attachment B. 

The TCR multiplied by 10.36% thus determines the Annualized Capital Costs.

2.4.2 Operating Costs

Annual operating costs for the DFGD system consist of variable O&M costs, fixed O&M 

costs, and indirect operating costs. The derivation of each cost component is described 

below. 

Variable O&M

 

Variable O&M costs are items that generally vary in proportion to the plant capacity factor. 

These consist of lime reagent costs, water costs, FGD waste disposal costs, bag and cage 

replacement costs, ash disposal costs, and auxiliary power costs, which were derived as 

follows: 

- Lime Reagent. Based on material balances for the average fuel composition and 90% 

capacity factor. The first-year delivered cost of lime is $118.80/ton for Sooner and 

$105.53/ton for Muskogee based on budgetary lime quotations received for truck 

delivery. 

- Water. Based on 205,256 lb/hr at full load at Sooner, 219,839 lb/hr at full load at 

Muskogee, and 90% capacity factor. The first-year cost of water is $0.49/1000 gallons at 

Sooner and $2.57/1000 gallons at Muskogee. Water unit costs are based on information 

received from OG&E. The Muskogee water cost includes the cost of purchasing water. 

Sooner does not have any water purchase costs. 

- FGD Waste Disposal. Based on material balances for the average fuel composition and 

90% capacity factor. The first year cost of on-site disposal is $39.60/ton at Sooner and 

$40.59/ton at Muskogee. Disposal cost only includes FGD by-products and does not 

include fly ash. 
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- Bag and Cage Replacement. Based on the exhaust gas flow through the baghouse, air-tocloth ratio of 3.5 for pulse jet baghouse, 4% contingency for bag cleaning, and 3-year bag 

life. The first year bag cost (including fabric and hangers) is $3.22/ft2

 at Sooner and 

$3.31/ft2 at Muskogee. 

- Ash Disposal. Assumed no increase in ash disposal with the fabric filter due to the 

existing ESP remaining in service. 

- Auxiliary Power Cost. Based on auxiliary power calculations and 90% capacity factor. 

The first year auxiliary power cost is $83.83/MWh at Sooner and $85.92/MWh at 

Muskogee. 

Fixed O&M

Fixed O&M costs are recurring annual costs that are generally independent of the plant 

capacity factor. These consist of operating labor, supervisor labor, maintenance materials, 

and maintenance labor, which were derived as follows: 

- Operating Labor. Based on three shifts/day 365 days/year. The first year labor rate 

(salary plus benefits) is $57.33/hour at Sooner and $58.76/hour at Muskogee. 

- Supervisory Labor. This was based on 15% of operating labor, according to the EPA 

Control Cost Manual, page 2-31. S&L determined that the EPA approach provides a 

reasonable estimate for this cost item. 

- Maintenance Materials. This was based on 0.6% of the total plant investment, based on 

Sargent & Lundy’s experience on other FGD projects. 

- Maintenance Labor. This was based on 110% of operating labor, according to the EPA 

Control Cost Manual, page 2-31. S&L determined that the EPA approach provides a 

reasonable estimate for this cost item. 

Indirect Operating Costs

Indirect operating costs are recurring annual costs for the FGD system that are not part of the 

direct O&M. These consist of property taxes, insurance, and administration, which were 

derived as follows: 
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- Property Taxes. Calculated as 0.60 % of total capital investment at Sooner and 0.85% of 

total capital investment at Muskogee, according to OG&E property tax rates. These rates 

are significantly lower than those used in the EPA Air Pollution Control Cost Manual 6th 

Ed., page 2-34. 

- Insurance. Calculated as 0.0105 % of total capital investment at both Sooner and 

Muskogee, according to OG&E insurance rates. These rates are significantly lower than 

those used in the EPA Air Pollution Control Cost Manual 6th Ed., page 2-34. 

- Administration. These are calculated as 20% of the fixed O&M based on Sargent & 

Lundy’s experience on other projects. This results in significantly lower costs compared 

to those obtained using the methodology described in the EPA Air Pollution Control Cost 

Manual 6th Ed., page 2-34. 

Total Annual Operating Costs

The total annual operating costs for each unit are calculated in Tables B-1 through B-4 in 

Attachment B and are approximately $29 to $32/kw per year. These costs compare favorably 

with industry O&M data for existing coal plants, and are within the normal range of expected 

O&M costs for dry FGD systems. The annual operating cost of approximately $29 to $32/kw 

is significantly lower than the $68/kw calculated in the 2008 BART report which was derived 

using OAQPS Cost Manual and CUECost default factors, and is lower than the $43 to 

$47/kw estimated by the DEQ in the draft Regional Haze Implementation Plan. 

2.4.3 2009 Cost Effectiveness

Total annual DFGD costs for each unit are summarized in Table 4. Detailed cost calculations 

are shown in Tables B-1 through B-4 in Attachment B. Total annual costs are divided by the 

annual tons of SO2 removed to calculate average control technology cost effectiveness. 

Annual emission reductions associated with DFGD control systems are summarized in Table 

5 using the same basis as the September 2009 OG&E BART update. The SO2 control 

efficiency for each unit is summarized in Table 6 

Table 4 

DFGD Total Annual Cost Summary 

Unit Capital Recovery 

($/year) 

Annual O&M 

($/year) 

Total Annual Cost 

($/year) 

Muskogee 4 $32,861,300 $18,438,900 $51,300,200 

Muskogee 5 $32,861,300 $18,438,900 $51,300,200 

Sooner 1 $30,281,800 $16,550,500 $46,832,300 

Sooner 2 $30,281,800 $16,550,500 $46,832,300 
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Table 5 

BART Annual SO2 Emission Reductions with Dry FGD

Unit 

Baseline Annual 

SO2 Emissions (1)

(tpy) 

Projected PostControl Annual 

Emissions (2)

(tpy) 

Annual Emission 

Reductions 

(tpy) 

Muskogee 4 9,113 2,160 6,953 

Muskogee 5 9,006 2,160 6,846 

Sooner 1 9,394 2,017 7,377 

Sooner 2 8,570 2,017 6,553 

(1) In this table baseline SO2 emissions are calculated as the average actual SO2 emission rate during the 

baseline years of 2004 – 2006. 

(2) In this table projected post-control SO2 emissions are calculated based on a controlled SO2 emission 

rate of 0.10 lb/mmBtu and a 90% capacity factor. 

Table 6 

Average Cost Effectiveness 

Unit Annual Cost 

($/year) 

SO2 Removed 

(tons/year) 

Average Cost 

Effectiveness 

($/ton) 

Muskogee 4 $51,300,200 6,953 $7,378 

Muskogee 5 $51,300,200 6,846 $7,493 

Sooner 1 $46,832,300 7,377 $6,348 

Sooner 2 $46,832,300 6,553 $7,147 

Cost effectiveness is a function of both the cost of a control system and the annual tons of 

pollutant removed. With respect to tons removed, various bases can be used to calculate both the 

baseline emission rate and the post-project controlled emission rate. Varying either the baseline 

calculation or the projected emissions calculation will result in a different cost effectiveness 

value. 

To account for this variability, the cost effectiveness of DFGD controls at Sooner and Muskogee 

were calculated using various baseline and projected SO2 emission rates. Emission rates were 

chosen to “envelope” the cost effectiveness of the DFGD control systems. For example, baseline 

SO2 emissions were based on the actual average SO2 emission rate during the 2004-2006 baseline 

period, as well as the highest annual SO2 emissions during the baseline period. Projected SO2

emissions were calculated using the presumptive SO2 emission rate of 0.15 lb/mmBtu, as well 

controlled SO2 emission rates of 0.10 and 0.08 lb/mmBtu. Finally, capacity factors of either 90% 

(which is more representative of actual operations) or 100% (which represents potential emissions 

but would represent actual operations) were also used. 
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Although annual O&M costs will vary depending on the controlled SO2 emission rate (i.e., lower 

post-project SO2 emission rates will have a higher annual variable O&M cost), for this analysis 

total annual costs were held constant. Cost effectiveness calculations for two alternative 

scenarios are summarized in Tables 5a & 6a and 5b & 6b. 

Table 5a 

BART Annual SO2 Emission Reductions with Dry FGD 

(Scenario 2)

Unit 

Baseline Annual 

SO2 Emissions (1)

(tpy) 

Projected PostControl Annual 

Emissions (2)

(tpy) 

Annual Emission 

Reductions 

(tpy) 

Muskogee 4 9,775 3,600 6,175 

Muskogee 5 10,224 3,600 6,624 

Sooner 1 10,189 3,361 6,828 

Sooner 2 8,746 3,361 5,385 

(1) In this table baseline SO2 emissions reflect the highest annual SO2 emission rate during the baseline 

years of 2004 – 2006. 

(2) In this table projected post-control SO2 emissions are calculated based on a controlled SO2 emission 

rate of 0.15 lb/mmBtu (the presumptive BART emission rate) and a 100% capacity factor.

Table 6a 

Average Cost Effectiveness 

(Scenario 2) 

Unit Annual Cost 

($/year) 

SO2 Removed 

(tons/year) 

Average Cost 

Effectiveness 

($/ton) 

Muskogee 4 $51,300,200 6,175 $8,308 

Muskogee 5 $51,300,200 6,624 $7,745 

Sooner 1 $46,832,300 6,828 $6,859 

Sooner 2 $46,832,300 5,385 $8,697 
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Table 5b 

BART Annual SO2 Emission Reductions with Dry FGD 

(Scenario 3)

Unit 

Baseline Annual 

SO2 Emissions (1)

(tpy) 

Projected PostControl Annual 

Emissions (2)

(tpy) 

Annual Emission 

Reductions 

(tpy) 

Muskogee 4 9,775 1,920 7,855 

Muskogee 5 10,224 1,920 8,304 

Sooner 1 10,189 1,793 8,396 

Sooner 2 8,746 1,793 6,953 

(1) In this table baseline SO2 emissions reflect the highest annual SO2 emission rate during the baseline 

years of 2004 – 2006. 

(2) In this table projected post-control SO2 emissions are calculated based on a controlled SO2 emission 

rate of 0.08 lb/mmBtu and a 100% capacity factor. A controlled SO2 emission rate of 0.08 lb/mmBtu 

represents the lowest SO2 emission rate that could reasonably be expected to be achieved on a large 

subbituminous coal-fired unit with a retrofit DFGD control system. 

Table 6b 

Average Cost Effectiveness 

(Scenario 3) 

Unit Annual Cost 

($/year) 

SO2 Removed 

(tons/year) 

Average Cost 

Effectiveness 

($/ton) 

Muskogee 4 $51,300,200 7,855 $6,531 

Muskogee 5 $51,300,200 8,304 $6,178 

Sooner 1 $46,832,300 8,396 $5,578 

Sooner 2 $46,832,300 6,953 $6,736 

Cost effectiveness varies depending on the baseline and controlled SO2 emission rates used in the 

evaluation. Under all scenarios, DFGD cost effectiveness on the OG&E units is greater than 

$5,550/ton. Based on the BART presumptive level of 0.15 lb/mmBtu, and assuming a 100% 

capacity factor, cost effectiveness of DFGD on the Muskogee and Sooner units would be in the 

range of $6,859 to $8,697/ton (see, Table 6a). Cost effective values calculated using the BART 

presumptive level should be used to compare cost effective at other BART applicable sources. 

In addition to calculating cost effectiveness on a $/ton basis, with respect to regional haze 

impacts, cost effectiveness can be calculated as a function of annual costs and modeled visibility 

improvements at the affected Class I Areas. Modeled visibility improvements will be a function 

of the proximity of the unit to the Class I Area, baseline and controlled emissions, and the 

pollutant being controlled. Table 7 provides a summary of the modeled reduction in visibility 

impairment (measured in deciview- dv) resulting from DFGD controls on the Muskogee and 

Sooner generating units. The cost effectiveness of DFGD controls as a function of modeled 
Oklahoma Gas & Electric December 28, 2009 

BART Analysis Follow-Up Report (Rev. 1) Project No. 11418-019 

Page 15 

reductions in visibility impairment (using two different impact criteria) is provided in Tables 8 

and 8a. 

Table 7 

Modeled Visibility Improvement at the Class I Areas (dv) 

Class I Area Muskogee 

Units 4 & 5 

Sooner Units 

1 & 2 

Wichita Mountains National Wildlife 

Refuge 

1.275 0.51 

Caney Creek Wilderness Area 0.804 0.32 

Upper Buffalo Wilderness Area 1.11 0.44 

Hercules-Glades Wilderness Area 1.028 1.17 

Total 4.217 2.44 

Table 8 

Average Cost Effectiveness ($/dv) 

Unit Annual Cost 

($/year) 

Modeled Visibility 

Improvement(1)

(dv) 

Average Cost 

Effectiveness 

($/dv) 

Muskogee 4 & 5 $102,600,400 1.275 $80,470,902 

Sooner 1 & 2 $93,664,600 1.17 $80,055,214 

(1) The modeled reduction in visibility impairment used in this table represents the highest single modeled 

reduction at a single Class I Area. 

Table 8a 

Average Cost Effectiveness ($/dv) 

Unit Annual Cost 

($/year) 

Modeled Visibility 

Improvement(1)

(dv) 

Average Cost 

Effectiveness 

($/dv) 

Muskogee 4 & 5 $102,600,400 4.217 $24,330,187 

Sooner 1 & 2 $93,664,600 2.44 $38,387,131 

(1) The modeled reduction in visibility impairment used in this table represents the cumulative reduction 

of all Class I Areas. 

Based on the cost effectiveness calculations summarized above, taking into considered modeled 

visibility improvements at all of the affected Class I areas, the cost effectiveness of DFGD on 

Sooner Units 1 & 2 will be in the range of $38,387,000/dv, and the cost effectiveness of DFGD 

on Muskogee Units 4 & 5 will be in the range of $24,330,000/dv. 
Oklahoma Gas & Electric December 28, 2009 

BART Analysis Follow-Up Report (Rev. 1) Project No. 11418-019 

Page 16 

2.5 COMPARISON OF 2009 CAPITAL COSTS AGAINST OTHER PUBLISHED 

CAPITAL COST INFORMATION 

Appendix 6-4 of the November 13, 2009 Oklahoma draft Regional Haze Implementation Plan 

Revision includes DEQ’s BART analysis for each OG&E BART applicable unit. In each of the 

OG&E BART determinations, DEQ revised the cost estimates for retrofit DFGD control systems, 

including revisions to the capital costs and annual O&M costs. Although DEQ stated that, in 

general, the cost estimating methodology used by OG&E “followed guidance provided in the 

EPA Air Pollution Cost Control Manual,” DEQ concluded, based on a review of other BART 

submittals, that OG&E’s costs were substantially higher than those reported for similar projects. 

(Draft Regional Haze Implementation Plan, Appendix 6-4, page cliii). DEQ proceeded to revise 

the capital costs and O&M costs based on cost information provided in the following 

publications: (1) a Colorado Department of Public Health and Environment report titled 

“Summary of Research and Potential Control Options, Emission Reductions and Costs for 

Reducing SO2 and NOx from Existing Major Colorado Point Sources”; (2) a March 1, 2009 

article in Power, on online industry magazine, titled “Update: What’s That Scrubber Going to 

Cost” written by George W. Sharp of American Electric Power; and (3) a report prepared by 

Sargent & Lundy for the National Lime Association titled “Flue Gas Desulfurization Technology 

Evaluation, Dry Lime vs. Wet Limestone FGD” dated March 2007. 

In its comments to DEQ regarding the draft Regional Haze Implementation Plan FWS/NPS 

agreed with DEQ that costs presented by OG&E for SO2 control were excessive. In addition, 

FWS/NPS provided an alternative lower cost analysis using capital costs “taken from the 2007 

Flue Gas Desulfurization Technology Evaluation, Dry Lime vs. Wet Limestone FGD, prepared 

for National Lime Association.” 

We address each of the referenced documents below. 

2.5.1 Colorado Department of Public Health and Environment Report

The Colorado Department of Public Health and Environment report included unit capital 

costs for retrofit dry scrubbers on 500 MW units burning PRB coal. The report was prepared 

by BBC Research and Consulting, and relied on cost data in a 2003 report prepared by 

Sargent & Lundy titled “Economics of Lime and Limestone for Control of Sulfur Dioxide” 

(the 2003 National Lime Report). As discussed in more detail below, capital costs included 

in the 2003 National Lime Report were intended to provide a comparison between lime-based 

and limestone-based scrubbing technologies, and were not intended to be used as the basis for 

a project-specific capital cost estimate. 
Oklahoma Gas & Electric December 28, 2009 

BART Analysis Follow-Up Report (Rev. 1) Project No. 11418-019 

Page 17 

2.5.2 2007 National Lime Association Report

Both DEQ and FWS reference the 2007 National Lime Report prepared by Sargent & Lundy 

as a basis for their capital cost revisions. In fact, the FWS’s alternative capital costs were 

based on numbers provided in the 2007 National Lime Report. However, the National Lime 

report was only intended to provide a comparative cost effectiveness evaluation of wet 

limestone-based FGD control systems and dry lime-based control systems. The report was 

not intended to provide an evaluation of total capital requirements for either type of control 

technology and was not intended to serve as the basis for a capital cost estimate. The 2007 

report clearly states:1

 

FGD prices have seen a minimum of 25% inflation in the past year. 

Some recent contracts have been signed at prices over 300% higher than 

the market of 5 years ago. The costs [in this report] have been prepared 

on a consistent, uniform basis and show a level that some buyers 

achieved in mid-2006. Sargent & Lundy cautions the reader that the 

costs provided herein are not indicative of any cost you may actually 

achieve. However, we believe the costs are valid for comparative 

purposes. These costs should not be used for any of these purposes; 

• Planning the cost of a FGD project 

• Budget requests or allocations 

• Solicitation of pollution control bonds 

In today’s market place, it is impossible to determine capital cost of an 

FGD system until the contract is signed with the supplier. 

Capital costs in both the 2003 and 2007 National Lime Reports were developed for 

comparative purposes only. Furthermore, costs in the 2007 report were based on 2006 dollars 

and did not include escalation, which can add approximately 10% to 20% to the project cost. 

Nor do the reports take into consideration any site-specific retrofit challenges. Capital costs 

in the National Lime Reports were presented on a consistent basis for comparative purposes 

only. Cost estimates using the methodology described in Section 2.1 of this report provide a 

more accurate accounting of actual costs that will be incurred by OG&E to install and operate 

dry FGD control systems at the Sooner and Muskogee generating stations. 

 

1

 See, Sargent & Lundy, “Flue Gas Desulfurization Technology Evaluation, Dry Lime vs. Wet Limestone 

FGD,” prepared for the National Lime Association, March 2007, page 2 (emphasis in the original). 
Oklahoma Gas & Electric December 28, 2009 

BART Analysis Follow-Up Report (Rev. 1) Project No. 11418-019 

Page 18 

2.5.3 “Update: What’s That Scrubber Going to Cost” article 

DEQ also used capital cost estimates summarized in a March 1, 2009 article in “Power” an 

online industry magazine to adjust the capital costs for DFGD retrofit projects at the OG&E 

stations. The Power article provided a survey of FGD projects at large electric utility 

generating stations during the period of December 2007 through June 2008. The article 

summarized the average total installed costs of FGD control systems as reported by the 

survey respondents, noting that the reported costs “were expected to have wide variation, 

principally because of the peculiarities that exist at each project site, the retrofit project 

complexity, and the timing differences between projects.” Therefore, assigning a projectspecific cost based on information summarized in the article would not be correct without 

taking into consideration project specific details. 

Furthermore, the 2009 OG&E conceptual capital costs of $514/kw (Sooner) and $555/kw 

(Muskogee) are reasonably close to the $359 to $471/kw taken from this article. The article 

reported that the 2008 cost surveys were 28% higher than those reported in the 2007 survey 

with an average of $359/kw for 600 to 900 MW plant range and $471/kw for 300 to 599 MW 

range. Note that these values are averages and include units with wide ranges of in-service 

dates. In fact, 55% of the units in the survey were expected to be in operation by 2009 

whereas the OG&E units are not expected to be in operation until 2014 and 2015. The 55% 

of the units in operation by 2009 would have had their major equipment purchased prior to 

the 28% run up in pricing in 2008 from late 2006 and prior to the 22% run up in pricing from 

2006 to 2007 referenced in the same article. The OG&E units would be subject to these 

escalated costs and future escalation. 

In addition, the OG&E units would also require a higher level of contingency since the 

projects are still in the early study phase. As a result, units going into service in the near 

future would be expected to be below the average cost while units going into service at later 

dates would be expected to be above the average cost. The article only provides an average 

cost and does not provide any information on the cost distribution about the average. A wide 

distribution is expected as indicated at the bottom of page 65 of the Power article, where it 

states that “average total installed costs reported by the survey respondents were expected to 

have wide variation” based partially on the “timing differences between projects.” Because 

of the expected wide variation in project costs, this report can be used to illustrate recent 

industry cost trends but should not be used to estimate the cost of specific units that will not 

go into service for another 5 to 7 years. Again, it is believed that the methodology described 

in Section 2.1 will provide more accurate results for a specific project than the cited article. 
Oklahoma Gas & Electric December 28, 2009 

BART Analysis Follow-Up Report (Rev. 1) Project No. 11418-019 

Page 19 

3.0 BART Report Comparisons 

The cost effectiveness of a pollution control system is a function of the total annual cost of the 

system (taking into consideration capital recovery and annual O&M) and the amount of pollutant 

removed by the control system (tons per year). With respect to regional haze impacts, cost 

effectiveness can also be measured as a function of total annual costs divided by the modeled 

improvement in visibility at the nearby Class I Areas. This measure of cost effectiveness is 

reported in total annual dollars per deciview change in visibility impairment ($/dv). Thus, in 

addition to costs, two site-specific factors that impact cost effectiveness are the quantity of 

pollutant removed and the reduction in modeled visibility impairment. 

3.1 COMPARISON OF BASELINE SO2 EMISSIONS 

Table 9 provides a summary of the baseline SO2 emission rates included in several BART 

evaluations. A more detailed comparison of some of the costs and cost effectiveness calculations 

included in various BART determinations is included in Attachment C. 

Table 9 

Comparison of Baseline SO2 Emissions at Several BART Units 

Station 

Baseline SO2

Emission Rate 

(lb/mmBtu) 

Baseline SO2

Emissions 

(tpy) 

Muskogee Unit 4 0.507 9,113 

Muskogee Unit 5 0.514 9,006 

Sooner Unit 1 0.509 9,394 

Sooner Unit 2 0.516 8,570 

NPPD Gerald Gentleman Unit 1 0.749 24,254 

NPPD Gerald Gentleman Unit 2 0.749 25,531 

White Bluff Unit 1 0.915 31,806 

White Bluff Unit 2 0.854 32,510 

Boardman Unit 1 0.614 14,902 

Northeastern Unit 3 0.900 16,000 

Northeastern Unit 4 0.900 16,000 

Naughton Unit 1 1.180 8,624 

Naughton Unit 2 1.180 11,187 

OPPD Nebraska City Unit 1 0.815 24,191 
Oklahoma Gas & Electric December 28, 2009 

BART Analysis Follow-Up Report (Rev. 1) Project No. 11418-019 

Page 20 

Of the units listed in Table 9, the OG&E units have the lowest baseline SO2 emission rates, and 

among the lowest baseline annual SO2 emissions (tpy). Baseline emissions have a direct effect on 

the cost effectiveness of a pollution control system, as shown below: 

Cost Effectiveness = Total Annual Costs / (Baseline Emissions – Projected Emissions) 

Assuming total annual costs and projected emissions are similar, cost effectiveness will be a 

function of the baseline emissions. This holds true for units firing subbituminous coals with 

baseline SO2 emission rates in the range of 0.5 lb/mmBtu to approximately 2.0 lb/mmBtu because 

removal efficiencies achievable with DFGD control will vary based on inlet SO2 loading. In 

general, DFGD control systems are capable of achieving higher removal efficiencies on units 

with higher inlet SO2 loading.2

 DFGD control systems will be more cost effective on units with 

higher baseline SO2 emissions because the control system will be capable of achieving higher 

removal efficiencies and remove more tons of SO2 per year for similar costs. Conversely, DFGD 

will be less cost effective, on a $/ton basis, on units with lower SO2 baseline emissions. The 

difference in baseline SO2 emissions summarized above accounts for some of the variability seen 

in the BART cost effectiveness calculations. On the basis of the baseline emission rates alone, 

with all other factors being equal, the cost effectiveness of the OG&E units would be about 55% 

to 185% higher than the other units listed in Table 9. 

3.2 COMPARISON OF MODELED VISIBILITY IMPROVEMENT 

Finally, with respect to regional haze impacts, cost effectiveness can also be calculated as a 

function of modeled improvements in visibility at the Class I areas. This cost effectiveness 

measurement can be presented by dividing the total annual costs by the degree of visibility 

improvement at an individual Class I area, or by dividing total annual costs by the sum of 

visibility improvement across all affected Class I areas. Using either approach, control 

technologies installed on units with higher baseline emissions and located nearer a Class I area 

will be more cost effective. 

In its comments to DEQ, FWS/NPS argued that cost effectiveness should “consider both the 

degree of visibility improvement in a given Class I area as well as the cumulative effects of 

 

2

 Removal efficiencies achievable with DFGD will be a function of several unit-specific process 

parameters. Process parameters affecting removal efficiency include: inlet and outlet flue gas 

temperatures; reactant stoichiometric ratio; how close the DFGD is operated to saturation conditions; the 

amount of solids product recycled to the atomizer, and the inlet SO2 concentration. Chemical and physical 

limitations including flue gas temperature, Ca/S stoichiometry, approach to saturation, mixing and reaction 

time limit the control efficiency of the DFGD control systems. 
Oklahoma Gas & Electric December 28, 2009 

BART Analysis Follow-Up Report (Rev. 1) Project No. 11418-019 

Page 21 

improving visibility across all of the Class I areas affected.”3 FWS/NPS reasoned that “[i]t is not 

appropriate to use the same metric to evaluate the effects of reducing emission from a BART 

source that impacts only one Class I area as for a BART source that impacts multiple Class I 

areas.”4

 Taking the cumulative impact approach, cost effectiveness will also be a function of the 

number of Class I areas affected by an individual BART applicable unit. Controls would be more 

cost-effective on units in near proximity to a Class I area, as well as units located within 300 km 

of a number of Class I areas. Figure 1 shows the location of the Class I areas in the U.S. 

Figure 1 

Class I Areas 

A majority of the Class I areas are located in the western part of the U.S. Simply due to the 

number of Class I areas in the west, it is likely that a BART applicable unit located in the western 

U.S. will be closer to a Class I area, and that emissions from the unit will affect visibility at more 

Class I areas. For example, the Boardman Generating Station located in north central Oregon 

approximately 150 miles east of Portland, is located within 300 km of 14 Class I areas. By 

 

3

 FWS/NPS Comments, page 3. 

4 Id.
Oklahoma Gas & Electric December 28, 2009 

BART Analysis Follow-Up Report (Rev. 1) Project No. 11418-019 

Page 22 

comparison, the Sooner and Muskogee stations are located within 300 km of one and four Class I 

areas, respectively. 

Taking the cumulative impact approach, control technologies will be more cost effectiveness on 

units affecting a number of Class I areas. For example, modeled visibility improvement at each 

Class I areas affected by the Sooner, Muskogee, and Boardman stations are summarized in Table 

10. Assuming the cost of retrofit controls are similar at all three stations, and assuming that each 

station achieves similar emission reductions, DFGD controls would be more cost effective at the 

Boardman Station (on a $/dv basis) simply due to the cumulative improvement in visibility 

improvement. 

Table 10 

Comparison of Baseline SO2 Emissions at Several BART Units 

 Muskogee 

Units 4 & 5 

Sooner Units 

1 & 2 

Boardman 

Unit 1 

1 1.275 0.51 0.777 

2 0.804 0.32 0.439 

3 1.11 0.44 0.802 

4 1.028 1.17 0.544 

5 na na 0.774 

6 na na 0.655 

7 na na 0.659 

8 na na 0.969 

9 na na 0.924 

10 na na 0.614 

11 na na 0.776 

12 na na 0.354 

13 na na 0.681 

14 na na 0.874 

Total 4.217 2.44 9.842 

In its BART analysis submitted to the Oregon Department of Environmental Quality, total capital 

requirements and total annual costs for DFGD were estimated at $247,293,000 and $36,322,000, 

respectively. Using the sum of modeled visibility improvements at all 14 Class I areas, cost 

effectiveness of the DFGD control system would be $3,690,510/dv (e.g., $36,322,000 divided by 

9.842 dv). By comparison, because the OG&E stations are located relatively far from a limited 

number of Class I areas, cost effectiveness at the Sooner and Muskogee stations would be 

$38,387,000/dV and $24,330,000/dv, respectively.5

 

 

5

 Sooner = $93,664,600 ÷ 2.44 dv = $38,387,000/dv 

Muskogee = $102,600,400 ÷ 4.217 dv = $24,330,000/dv 
Oklahoma Gas & Electric December 28, 2009 

BART Analysis Follow-Up Report (Rev. 1) Project No. 11418-019 

Page 23 

4.0 Conclusions 

Sargent & Lundy updated the retrofit DFGD control system cost estimates for the Sooner and 

Muskogee Generating Stations. The 2009 conceptual cost estimate (included in this report) was 

based on project-specific vendor quotations for certain major equipment items and inputs 

developed by performing preliminary project engineering. The 2009 conceptual capital cost 

estimate is in the ±20% accuracy range. Total annual costs associated with the installation of 

DFGD, including capital recovery costs and annual O&M costs were also updated. Annual O&M 

costs were derived from preliminary engineering mass balance calculations and project-specific 

unit costs. The cost estimating methodology used herein to develop both capital and O&M costs 

provides a more accurate estimate of actual costs that OG&E would incur with the installation 

and operation of DFGD on the Sooner and Muskogee units. 

The 2009 conceptual capital cost estimates and supporting information for both generating 

stations are included in Attachment A. Detailed total annual cost summaries, including capital 

recovery, variable O&M, and fixed O&M calculations are included in Attachment B. Based on 

the cost estimates, the total capital requirements for DFGD controls on all four OG&E units will 

be in the range of $1.22 billion dollars. Total annual costs (including capital recovery and O&M) 

will be in the range of $93.6 million/year at Sooner and $102.6 million/year at Muskogee. 

Cost effectiveness of a pollution control system is a function of the total annual cost of the system 

and the quantity of pollutant removed (tons/year). Because of the relatively low baseline SO2

emission rates at both Muskogee and Sooner (see, Table 9), DFGD will be less cost effective on 

these units than on similarly sized units with higher baseline SO2 emissions. Based on expected 

reductions in actual annual SO2 emissions, the cost effectiveness of DFGD on the OG&E units 

will be in the range of $6,348 to $7,493/ton (see, Table 6). 

In addition to calculating cost effectiveness on a $/ton basis, with respect to regional haze 

impacts, cost effectiveness can be calculated as a function of annual costs and modeled visibility 

improvements at the affected Class I Areas. Modeled visibility improvements will be a function 

of the proximity of the unit to the Class I Area, baseline and controlled emissions, and the 

pollutant being controlled. Because the OG&E stations are located relatively far from a limited 

number of Class I areas, DFGD will be less cost effective (on a $/dv basis) on the OG&E units 

than on similarly sized units located closer to a Class I area or within 300 km of several Class I 

areas. Based on modeled visibility improvements, the cost effectiveness at the Sooner and 

Muskogee stations would be $38,387,000/dV and $24,330,000/dv, respectively. 
Oklahoma Gas & Electric December 28, 2009 

BART Analysis Follow-Up Report (Rev. 1) Project No. 11418-019 

Attachment A 

Sooner Units 1 & 2 

Conceptual Cost Estimate 
OG&E

Sooner Units 1&2

DFGD System 

Cost Estimate Account Summary

Date: 12/11/2009

Account Description Cost

Dry FGD System $86,859,600

Fabric Filter $46,335,000

Ash Recycling System - DFGD 

Contractor's Scope $12,072,500

Waste Ash and Fly Ash Handling 

System $14,265,600

Flue Gas System $42,463,000

Mechanical - Balance of Plant $6,891,300

Electrical - Auxiliary Power and 

Balance of Plant Electrical Work $41,935,100

Controls & Instrumentation $5,088,500

Civil Work $3,597,400

Removal and Relocation of Existing 

Equipment and Infrastructure $2,047,600

Other Costs $63,746,900

Total Indirect Costs $48,090,100

Escalation $46,602,900

Contingency $58,673,400

Bond Cost $4,786,700

Interest During Construction 

(AFUDC) $101,133,800

Total Project Cost $584,589,400

Page 1 of 1
OG & E 

Sooner Units 1 & 2 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: 

Est=Estimated Allow.=Allowance C= Contract Q=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Cost Develo

Dry FGD System 46,462,100 8,209,500 

31-45-25 Dry FGD System Q 2 LT 15,917,133 0.00 31,834,300 0 

31-45-35 Reagent Handling / Preparation Est 0 0 

31-45-35 Reagent Handling / Preparation - Mechanical Q 2 LT 3,969,614 0.00 7,939,200 0 

26-13-99 Lime Storage Silo with piping for pneumatic unloading (truck) Concrete Silo - Subcontract price Q 1 LT 3,200,000 0.00 3,200,000 0 

24-17-15 Elevator for lime silo

four person rack and pinion maintenance elevator - subcontract price includes labor

Est 1 LT 290,000 0.00 290,000 0 

22-13-27 Concrete pit for the elevator Est 10 CY 0 210.00 0 2,100 41-99-99 Electrical work for the elevator allowance Est 1 LT 0 20,000.00 0 20,000 

33-43-15 Pneumatic lime transfer equipment/piping including blowers, piping, and valves Q 1 EA 400,000 0.00 400,000 0 

23-17-23 Access Gallery Est 2,000 SF 0.00 35.00 0 70,000 

Dry FGD System - Civil / Structural Work 

Foundations for SDA's Quantities are total for 2 units

21-23-15 Excavation Est 2,140 CY 0.00 0.00 0 0 

21-17-25 Backfill Est 140 CY 0.00 0.00 0 0 22-13-37 Concrete Est 2,000 CY 0.00 105.00 0 210,000 22-25-35 Reinforcing Est 180 TN 0.00 1,150.00 0 207,000 

22-17-25 Formwork Est 6,000 SF 0.00 2.50 0 15,000 22-15-25 Embedded steel Est 5.00 TN 0.00 5,000.00 0 25,000 

SDA Superstructure Quantities are total for 2 units 

23-25-75 Common Penthouse for SDA's support steel, roof steel, girts and purlins Est 152 TN 0.00 2,650.00 0 402,500 24-37-43 SDA Roof Insulation between penthouse floor and SDA roof total for 2 SDAs Est 12,070 SF 0.00 15.00 0 181,100 24-37-47 Roofing for common SDA Penthouse standing seam type. Est 8,100 SF 0.00 18 0 145,800 24-41-25 Siding for common SDA Penthouse insulated metal siding Est 16,200 SF 0.00 12 0 194,400 36-13-23 Shell Insulation subcontract cost Est 61,688 SF 30.00 0 1,850,600 0 22-13-23 Concrete bottom floor for common SDA Penthouse includes metal decking and formwork Est 99 CY 210 0 20,800 41-37-99 Common Penthouse Building Services H&V and Lighting Est 8,100 SF 0.00 30.00 0 243,000 

31-41-77 Fire Protection for Penthouse Standpipe & hose stations. Est 2 LS 80,000 160,000 24-17-15 Elevator

For SDA - four person rack and pinion elevator. Suncontract price includes labor

Est 1 LT 290,000 0.00 290,000 0 

22-13-37 Concrete pit for the elevator Est 10 CY 0 210.00 0 2,100 41-99-99 Electrical work for the elevator allowance Est 1 LT 0 20,000.00 0 20,000 

Page 1 of 14
OG & E 

Sooner Units 1 & 2 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: 

Est=Estimated Allow.=Allowance C= Contract Q=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Cost Develo

SDA - Support Steel and Access Gallery

23-25-75 Support Steel Included in DFGD equip. Est 300 TN 0 0 0 0 

23-17-23 Walkway from U1 SDA's to U2 SDA's Est 20 TN 0 0 0 0 

23-17-23 Access Gallery Est 1,500 SF 0.00 35.00 0 52,500 

27-17-99 Touch-up painting Est 2 LT 0.00 45,000.00 0 90,000 

Reagent Handling / Preparation- Civil / Structural Work One common for both units Foundations for Lime Storage Silo

21-23-15 Excavation Est 280 CY 0.00 0.00 0 0 

21-17-25 Backfill Est 80 CY 0.00 0.00 0 0 22-13-37 Concrete Est 200 CY 0.00 105.00 0 21,000 22-25-35 Reinforcing Est 18 TN 0.00 1,150.00 0 20,700 

22-17-25 Formwork Est 600 SF 0.00 2.50 0 1,500 22-15-25 Embedded steel Est 0.50 TN 0.00 5,000.00 0 2,500 23-25-75 Support Steel for lime Storage Silo Not required - concrete silo23-17-23 Galleries Est 1,800 SF 0.00 35.00 0 63,000 23-17-53 Stair Tower for Lime Storage Silo Est 120 TN 2,650 0 318,000 0 31-41-77 Fire Protection Standpipe & hose stations Est 1 LS 60,000.00 60,000 0 

Lime Preparation / Recycle Building (55' x 100' x 125'H)

Quantities shown are total for 2 buildings, 1/unit

22 Substructure 21-23-15 Excavation Est 1,070 CY 0.00 0 0 

21-17-25 Backfill Est 70 CY 0.00 0 0 22-13-37 Concrete Est 1,000 CY 105.00 0 105,000 

22-25-35 Reinforcing Est 75 TN 1,150.00 0 86,300 

22-17-25 Formwork Est 3,000 SF 2.50 0 7,500 22-15-25 Embedded steel Est 2.50 TN 5,000.00 0 12,500 

Superstructure

23-25-75 Structural Steel Est 900 TN 2650 0 2,384,400 

24-41-25 Insulated Metal Siding Est 80,000 SF 12 0 960,000 

24-15-15 Rolling Overhead Door one for each building Est 640 SF 27 0 17,300 

23-23-23 Metal Roof Decking Est 11,000 SF 2.7 0 29,700 

24-37-43 Rigid Roof Insulation, 2" Thick Est 11,000 SF 2.4 0 26,400 24-37-17 Cant Strips, Treated Est 620 LF 1.32 0 800 

24-37-73 Roofing ( 4-Ply Tar & Gravel) Est 11,000 SF 1.55 0 17,100 

22-13-43 Lightweight Concrete Fill 1" Est 247 CY 100 0 24,700 

24-37-27 Roof Flashing Est 620 LF 14.45 0 9,000 

35-13-31 Roof Drains Est 2 LT 20000 0 40,000 

35-13-31 Floor Drains Est 2 LT 25000 0 50,000 

22-13-23 Floor Slabs includes metal decking and formwork Est 101 CY 210 0 21,200 

22-13-23 Floor Finishes Est 8,250 SF 2.5 0 20,600 

24-25-25 Louvers/Windows/Doors Est 8,000 SF 40 0 320,000 

34-41-99 Roof Ventilators Est 8 EA 15000 0 120,000 

23-17-23 Galleries & Landings Est 800 SF 45 0 36,000 

34-55-99 H&V Est 11,000 SF 16.7 0 183,300 

41-37-99 Electrical Service & Lighting Est 11,000 SF 20.0 0 220,000 

31-41-77 Fire Protection Standpipe & hose stations Est 2 LS 60,000.00 120,000 0 

23 Pipe Rack For Lime Handling, Waste Ash Handling and misc Mechanical Piping Quantities shown are total for 2 units

23-25-75 Structure and Support Steel Est 330 TN 0.00 2,650.00 0 874,500 

22 Foundations for support steel 0 0 

21-23-15 Excavation Est 1,292 CY 0.00 0.00 0 0 

21-17-25 Backfill Est 342 CY 0.00 0.00 0 0 22-13-37 Concrete Est 950 CY 0.00 105.00 0 99,800 22-25-35 Reinforcing Est 71 TN 0.00 1,150.00 0 81,900 

22-17-25 Formwork Est 9,500 SF 0.00 2.50 0 23,800 22-15-25 Embedded Steel Est 4,750 LB 0.00 2.50 0 11,900 22 Foundations for Misc. Support Steel Quantities shown are total for 2 units 0 0 

21-23-15 Excavation Est 272 CY 0.00 0.00 0 0 

21-17-25 Backfill Est 72 CY 0.00 0.00 0 0 22-13-37 Concrete Est 200 CY 0.00 105.00 0 21,000 22-25-35 Reinforcing Est 15 TN 0.00 1,150.00 0 17,300 

22-17-25 Formwork Est 2,000 SF 0.00 2.50 0 5,000 22-15-25 Embedded Steel Est 1,000 LB 0.00 2.50 0 2,500 

Page 2 of 14
OG & E 

Sooner Units 1 & 2 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: 

Est=Estimated Allow.=Allowance C= Contract Q=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Cost Develo

23-25-75 Misc. Support Steel not included elsewhere Quantities shown are total for 2 units Est 100 TN 0 2,650 0 265,000 

23-17-23 Misc. Galleries Quantities shown are total for 2 units Est 3,000 SF 0.00 35.00 0 105,000 

Fabric Filter 24,079,500 4,622,500 

31-57-15 Fabric Filter System Q 2 LT 9,912,416 0.00 19,824,800 0 

31-17-45 Fabric Filter Baghouse Air Compressor System Q 2 LT 2,027,372 0.00 4,054,700 0 

35-13-15 Fabric Filter Baghouse Compressor System Piping Included in air compressor system pricing Est 2 LT 0.00 0.00 0 0 

31-27-35 Fabric Filter Bypass Dampers Included in Fabric Filter System Price Est 2 LT 0.00 0.00 0 0 

31-57-99 Hopper Heaters Included in Fabric Filter System Price Est 2 LT 0.00 0.00 0 0 31-57-99 Vent Fan Included in Fabric Filter System Price Est 2 LT 0.00 0.00 0 0 31-25-35 Hoist & Trolley Beam Included in Fabric Filter System Price Est 2 LT 0.00 0.00 0 0 36-13-23 Insulation for Baghouse subcontract cost Est 65,111 SF 0.00 30.00 0 1,953,300 

23-25-75 Penthouse steel for baghouses Support steel, roof steel, girts and purlins. Est 79 TN 0.00 2,650.00 0 209,300 

24-41-25 Siding for baghouse penthouse insulated metal siding Est 12,960 SF 0.00 12 0 155,500 24-37-47 Roofing for baghouse penthouse standing seam type Est 5,751 SF 0.00 18 0 103,500 22-13-23 Concrete bottom floor for baghouse penthouse includes metal decking and formwork Est 70 CY 210 0 14,800 41-37-99 Building Services H&V and Lighting Est 5,751 SF 0.00 22.00 0 126,500 

31-41-77 Fire Protection for Penthouse Standpipe & hose stations Est 2 LS 60,000.00 120,000 23-25-75 Bottom Enclosure steel Support steel, girts and purlins. Total for Units 1&2 Est 171 TN 0.00 2,650.00 0 453,900 

41-37-99 Building Services H&V and Lighting Est 19,880 SF 0.00 22.00 0 437,400 

24-41-25 Siding for baghouse bottom enclosure

insulated metal siding, support steel and girts included in Alstom pricing

Est 17,976 SF 0.00 12 0 215,700 

31-41-77 Fire Protection for bottom enclosure Standpipe & hose stations Est 2 LS 40,000.00 0.00 80,000 0 

Fabric Filter System - Structural 

Foundations for Fabric Filter Baghouse Quantities shown are total for 2 units

21-23-15 Excavation Est 3,852 CY 0.00 0.00 0 

21-17-25 Backfill Est 252 CY 0.00 0.00 0 22-13-37 Concrete Est 3,600 CY 0.00 105.00 0 378,000 22-25-35 Reinforcing Est 324 TN 0.00 1,150.00 0 372,600 

22-17-25 Formwork Est 10,800 SF 0.00 2.50 0 27,000 22-15-25 Embedded Steel Est 9.00 TN 0.00 5,000.00 45,000 

Support Steel and Access Gallery 

23-25-75 Support Steel Included in Baghouse equip price Q 420 TN 0.00 0 0 0 

23-17-23 Access Gallery Q 3,000 SF 0.00 35.00 0 105,000 

27-17-99 Touch-up painting Est 1 LT 0.00 25,000.00 0 25,000 

Ash Recycling System - DFGD Contractor's Scope 6,843,000 0 

Page 3 of 14
OG & E 

Sooner Units 1 & 2 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: 

Est=Estimated Allow.=Allowance C= Contract Q=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Cost Develo

31-45-99 Ash Recycling System - Mechanical 2 LT 3,421,528 6,843,000 

31-45-99 Recycle Ash Storage Silo Included in Ash Recycling System Price Q 0.00 0.00 0 0 

31-45-99 Recycle Ash Silo Bin Vent Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Ash Fluidizing Air Blower Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Ash Fluidizing Air Heater Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Ash Silo Discharge Rotary Feeder Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Slurry Vibrating Screen Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Ash Prep Area Sump Tank Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Ash Prep Area Sump Tank Agitator Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Ash Slurry Mix Tank Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Ash Slurry Mix Tank Agitator Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Slurry Storage Tank Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Slurry Storage Tank Agitator Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Slurry Feed Pumps Included in Ash Recycling System Price Q 0.00 0.00 0 0 

Ash Recycling System - BOP Scope 60,000 534,800 

Ash Reagent Recycle Building Included with Lime Preparation Building

24-35 Ash Handling Blower Building (25' x 50' x 25'H) Quantities shown are total for 2 buildings, 1/unit

22-13 Substructure 

21-23-15 Excavation Est 214 CY 0.00 0.00 0 0 

21-17-25 Backfill Est 14 CY 0.00 0.00 0 0 22-13-37 Concrete Est 200 CY 0.00 105.00 0 21,000 22-25-35 Reinforcing Est 15 TN 0.00 1,150.00 0 17,300 

22-17-25 Formwork Est 800 SF 0.00 2.50 0 2,000 22-15-25 Embedded Steel Est 1,600 LB 0.00 2.50 0 4,000 24-35-25 Pre-engineered building Includes H&V and Lighting Est 2,500 SF 0.00 175.00 0 437,500 23-25-75 Additional Support Steel for Waste Ash Pipes outside of pipe rack Est 20 TN 0.00 2,650.00 0 53,000 

31-41-77 Fire Protection Standpipe & hose stations Est 2 LS 30,000 60,000 

Waste Ash and Fly Ash Handling System 10,131,300 339,300 

33 Waste Ash Handling System - Mechanical 

26-13-15 Waste Ash silo Concrete silo - subcontract price Q 1 LT 1,550,000 0.00 1,550,000 0 

24-17-15 Elevator for waste ash silo maintenance elvator - subcontract price Est 1 LT 290,000 0.00 290,000 0 

22-13-27 Concrete pit for the elevator total for 2 silo elevators Est 10 CY 0 210.00 0 2,100 41-99-99 Electrical work for the elevator allowance Est 1 LT 0 20,000.00 0 20,000 

33-13-45 Waste Handling Systsem Includes blowers, ash valves, and ash piping Q 1 LT 5,300,000 0.00 5,300,000 0 

33-13-45 Mechanical Equipment Est 0 0.00 0 0 

33-13-45 Mechanical Blowers Included in Waste Handling System Price Est 0 0.00 0 0 

Page 4 of 14
OG & E 

Sooner Units 1 & 2 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: 

Est=Estimated Allow.=Allowance C= Contract Q=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Cost Develo

33-13-45 Waste Ash Silo Unloading Equipment including Fluidizing Blowers Included in Waste Handling System Handling Price Est 0 0.00 0 0 

33-13-45 Waste Ash Vacuum Pipes from FF hoppers to Filter Separators Included in Waste Handling System Handling Price Est 0 0.00 0 0 33-13-45 Motor Operated Butterfly Valves Included in Waste Handling System Handling Price Est 0 0.00 0 0 

22-13-75 Fly Ash Silo

Field erected steel silo. Pricing includes mechanical equipment and ash piping

Est 75 TN 4,000 0.00 300,000 0 

33-13-45 Mechanical equipment for ash handling system and silo fly ash unloading equipment Est 1 LT 2,500,000 0.00 2,500,000 0 

Foundations for Fly Ash Silo 

21-23-15 Excavation Est 80 CY 0.00 0.00 0 

21-17-25 Backfill Est 30 CY 0.00 0.00 0 22-13-37 Concrete Est 50 CY 0.00 105.00 0 5,300 22-25-35 Reinforcing Est 5 TN 0.00 1,150.00 0 5,200 

22-17-25 Formwork Est 150 SF 0.00 2.50 0 400 22-15-25 Embedded Steel Est 0.13 TN 0.00 5,000.00 600 23-25-75 Support Steel for Fly Ash Storage Silo Est 50 TN 0.00 2,650.00 0 132,500 23-17-23 Access Gallery for fly ash silo Included with Misc Galleries. 0 SF 0 35 0 0 33-57-65 Truck Scale Est 1 LT 125,000 0 125,000 0 22-13-37 Concrete foundation and approach for truck scale Est 350 CY 0 210 0 73,500 

41-99-99 Electrical allowance for truck scale Est 1 LT 0 15,000 0 15,000 

Foundations for Waste Ash Silo 

21-23-15 Excavation Est 176 CY 0.00 0.00 0 

21-17-25 Backfill Est 66 CY 0.00 0.00 0 22-13-37 Concrete Est 110 CY 0.00 105.00 0 11,600 22-25-35 Reinforcing Est 10 TN 0.00 1,150.00 0 11,400 

22-17-25 Formwork Est 330 SF 0.00 2.50 0 800 22-15-25 Embedded Steel Est 0.28 TN 0.00 5,000.00 1,400 23-25-75 Support Steel for Waste Ash Storage Silo concrete silo Est 0 TN 0.00 2,650.00 0 0 23-17-53 Stair Tower for Waste Ash Silo Est 25 TN 2,650 0 66,300 0 23-17-23 Access Gallery for waste ash silo Est 1,700 SF 0 35 0 59,500 

Flue Gas System 5,558,000 14,067,000 

Spray Dryer Absorber Inlet Duct (from Existing IDFan Outlet) Quantities are total for 2 units 

23-15-35 Ductwork Steel, including plate, stiffeners, internal bracing, turning vanes and walkway grating Est 1,600 TN 0.00 3,250.00 0 5,200,000 36-13-57 Insulation & Lagging Est 152,000 SF 0.00 12.00 0 1,824,000 

31-33-15 Expansion Joints Est 3,200 LF 0.00 230.00 0 736,000 31-27-35 Dampers Not Required

44-21-99 Dry FGD Inlet Ductwork Instrumentation Est 4 LS 30,000.00 0.00 120,000 0 

Spray Dryer Absorber Outlet to Fabric Filter Inlet Quantities are total for 2 units 

23-15-35 Ductwork Steel, including plate, stiffeners, internal bracing, turning vanes and walkway grating included in DFGD equipment supply pricing

36-13-57 Insulation & Lagging Allow 50,000 SF 0.00 12.00 0 600,000 

31-33-15 Expansion Joints Material price is included in DFGD contract cost Est 275 LF 0.00 0.00 0 0 

44-21-99 Dry FGD Outlet Ductwork Instrumentation Material price is included in DFGD contract cost Est 1 LS 0.00 0.00 0 0 

31-27-35 Dampers Not required Est 0 SF 450.00 0.00 0 0 

Fabric Filter Outlet Duct to Booster Fans and Booster ID Fans to existing chimney breeching Quantities are total for 2 units 

Page 5 of 14
OG & E 

Sooner Units 1 & 2 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: 

Est=Estimated Allow.=Allowance C= Contract Q=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Cost Develo

23-15-35 Ductwork Steel, including plate, stiffeners, internal bracing, turning vanes and walkway grating Est 560 TN 0.00 3,250.00 0 1,820,000 36-13-57 Insulation & Lagging Est 56,000 SF 0.00 12.00 0 672,000 

31-33-15 Expansion Joints Est 1,800 LF 0.00 230.00 0 414,000 31-27-35 Dampers Not required Est 0 SF 450.00 0.00 0 0 

44-21-99 Fabric Filter Outlet Ductwork Instrumentation Est 4 LS 30,000.00 0.00 120,000 0 

Booster ID Fans Quantities are total for 2 units 

31-35-15 New Booster ID Fans

Axial fan, 2 x 50% per unit, 882,450 cfm, includes fan auxiliary equipment

Est 4 EA 775,000 0.00 3,100,000 0 

41-43-35 Motors for Booster ID Fans 3300 HP Est 4 EA 247,000 0.00 988,000 0 31-25-35 Hoist & trolleys for Booster ID Fans 5-ton cap Est 4 EA 15,000 0.00 60,000 0 36-13-23 Fan Insulation & Lagging total for two fans Est 6,000 SF 0.00 12.00 0 72,000 

31-27-35 Booster ID Fans Isolation Dampers Single Louver type damper assembly Est 2,400 SF 450.00 0.00 1,080,000 0 

Flue Gas System - StructuralDuctwork Support Foundations Total for all ductwork for 2 units 

21-23-15 Excavation Est 2,140 CY 0.00 0.00 0 

21-17-25 Backfill Est 140 CY 0.00 0.00 0 22-13-37 Concrete Est 2,000 CY 0.00 105.00 0 210,000 22-25-35 Reinforcing Est 150 TN 0.00 1,150.00 0 172,500 

22-17-25 Formwork Est 6,000 SF 0.00 2.50 0 15,000 22-15-25 Embedded Steel Est 5.00 TN 0.00 5,000.00 25,000 23-25-75 Structural Steel Duct Supports Est 580 TN 0.00 2,650.00 0 1,537,000 

ID Fan Foundations Quantities are total for 2 units 0 

21-23-15 Excavation Est 2,033 CY 0.00 0.00 0 

21-17-25 Backfill Est 133 CY 0.00 0.00 0 22-13-37 Concrete Est 1,900 CY 0.00 105.00 0 199,500 22-25-35 Reinforcing Est 143 TN 0.00 1,150.00 0 163,900 

22-17-25 Formwork Est 15,200 SF 0.00 2.50 0 38,000 22-15-25 Embedded Steel Est 9.50 TN 0.00 5,000.00 0 47,500 23-17-23 Access Gallery for all inlet and outlet ductwork Est 3,000 SF 0 35.00 0 105,000 41-37-43 Lighting for access galleries and Booster Fan area Est 6,000 SF 0.00 15.00 0 90,000 

Stack Coating

Acid resistant coating - top 50 ft of liner. Assumed chimney liner 20Ft dia x 500 ft high

61-23-35 Suspended Motorized Modular Platform Rental 90 day rental, each stack Est. 2 LT 45,000.00 0.00 90,000 0 

27-15-35 Prep and clean top 50ft of two flues (inside only) to white metal (SSPC-SP 5) Quantities shown are for 2 stacks. Includes misc. repairs Est. 6,400 SF 0.00 0.00 0 0 27-13-99 Apply acid resistant coating Quantities shown are for 2 stacks. Est. 6,400 SF 0.00 16.50 0 105,600 61-17-43 Temporary Power, Light and Ventilation Est. 2 LT 0.00 10,000.00 0 20,000 

Mechanical - Balance of Plant 0 2,913,900 PipingVacuum Conveying

35-13-99 Vacuum conveying to lime silo Est LF 0.00 57.60 0 0 

Makeup Water

35-13-15 8" CS, SCH 40, includes fittings, underground Raw water to reagent prep Est 1,130 LF 0.00 130.20 0 147,100 

35-13-15 6" CS, SCH 40, includes fittings, underground Raw water to reagent prep Est 120 LF 0.00 89.50 0 10,700 21-25-15 Excavation for Underground Piping Est 628 CY 0.00 0.00 0 0 

21-17-15 Bedding for Underground Piping Est 94 CY 0.00 40.00 0 3,800 

Page 6 of 14
OG & E 

Sooner Units 1 & 2 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: 

Est=Estimated Allow.=Allowance C= Contract Q=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Cost Develo

21-17-25 Backfill for Underground Piping Est 534 CY 0.00 0.00 0 0 

35-13-15 2.5" CS, SCH 40, includes fittings Slaker water and dilution water Est 320 LF 0.00 35.60 0 11,400 35-13-15 2.5" CS, SCH 80, includes fittings Slaker water and dilution water Est 320 LF 0.00 55.50 0 17,800 35-13-15 4" CS, SCH 40, includes fittings Recycle water Est 1,190 LF 0.00 57.60 0 68,500 

35-13-33 Pipe Supports for Makeup Water piping Est 2.58 TN 0.00 2,650.00 0 6,800 

Service Water

35-13-15 6" CS, SCH 40, includes fittings, underground Extend existing service water line to new lime unloading area Est 810 LF 0.00 89.50 0 72,500 

35-13-15 3" CS, SCH 40, includes fittings, underground Reagent prep building abd fly ash silos Est 1,520 LF 0.00 48.80 0 74,200 

21-25-15 Excavation for Underground Piping Est 1,294 CY 0.00 0.00 0 0 

21-17-15 Bedding for Underground Piping Est 194 CY 0.00 40.00 0 7,800 21-17-25 Backfill for Underground Piping Est 1,100 CY 0.00 0.00 0 0 35-13-15 3" CS, SCH 40, includes fittings Absorbers (penthouse) Est 680 LF 0.00 48.80 0 33,200 

35-15-15 2" CS, SCH 80, includes fittings

Reagent prep building, absorbers (penthouse), fly ash silos

Est 600 LF 0.00 39.80 0 23,900 

35-13-33 Pipe Supports for Service Water piping Est 1.51 TN 0.00 2,650.00 0 4,000 

Lime Slurry Pipe

35-13-15 2.5" CS, SCH 80, includes fittings Reagent prep to atomizer head tank in SDA Est 1,200 LF 0.00 55.50 0 66,600 

35-13-33 Pipe Supports for Service Water piping Est 1.76 TN 0.00 2,650.00 0 4,700 

Ash Pipe

35-13-99 10" Ashcolite, flanged Supports included with pipe rack Est 1,440 LF 0.00 165.00 0 237,600 

35-13-33 Pipe supports within building boundaries Est 10 EA 0.00 125.00 0 1,300 

Recycle Slurry Pipe

35-13-15 6" CS, SCH 80, includes fittings, underground Recycle ash silo to atomizer head tank Est 1,200 LF 0.00 135.20 0 162,200 

35-13-33 Pipe Supports for Recycle Slurry piping Est 4.28 TN 0.00 2,650.00 0 11,400 

Slurry Return Pipe

35-13-15 6" CS, SCH 80, includes fittings, underground SDA to reagent prep Est 1,200 LF 0.00 135.20 0 162,200 

35-13-33 Pipe Supports for Recycle Slurry piping Est 4.28 TN 0.00 2,650.00 0 11,400 

Sump Discharge / Drains

35-13-15 2.5" CS, SCH 40, includes fittings Absorber and Prep Building Est 260 LF 0.00 35.60 0 9,300 35-13-15 4" CS, SCH 40, includes fittings Reagent prep building Est 3,250 LF 0.00 57.60 0 187,200 

35-13-33 Pipe Supports for Sump Discharge and Drains Est 5.19 TN 0.00 2,650.00 0 13,800 35-13-21 3" HDPE includes fittings Undeground. Absorber Sumps Est 580 LF 0.00 4.80 0 2,800 35-13-21 4" HDPE includes fittings Fly Ash Silos, Lime Silos Est 3,620 LF 0.00 4.80 0 17,400 

21-25-15 Excavation for Underground Piping Est 1,556 CY 0.00 0.00 0 0 

21-17-15 Bedding for Underground Piping Est 233 CY 0.00 40.00 0 9,300 21-17-25 Backfill for Underground Piping Est 1,322 CY 0.00 0.00 0 0 

Fire Protection

35-13-35 6" HDPE, includes fittings

Extend existing and new for Absorber, Reagent Prep, Fly Ash Silos and Lime Silos

Est 1,640 LF 0.00 8.50 0 13,900 

21-25-15 Excavation for Underground Piping Est 759 CY 0.00 0.00 0 0 

21-17-15 Bedding for Underground Piping Est 114 CY 0.00 40.00 0 4,600 21-17-25 Backfill for Underground Piping Est 645 CY 0.00 0.00 0 0 35-13-15 3" CS, SCH 40, includes fittings Absorber, Reagent Prep, Fly Ash Silos and Lime Silos Est 1,120 LF 0.00 48.80 0 54,700 

35-13-33 Pipe Supports for Fire Protection Est 1.44 TN 0.00 2,650.00 0 3,800 

Service Air

Page 7 of 14
OG & E 

Sooner Units 1 & 2 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: 

Est=Estimated Allow.=Allowance C= Contract Q=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Cost Develo

35-13-15 3" CS, SCH 40, includes fittings Absorber, Reagent Prep, Fly Ash Silos and Lime Silos Est 2,980 LF 0.00 48.80 0 145,400 

35-15-15 2" CS, SCH 80, includes fittings

Reagent prep building, absorbers (penthouse), fly ash silos

Est 1,000 LF 0.00 39.80 0 39,800 

35-13-33 Pipe Supports for Service Air Est 4.89 TN 0.00 2,650.00 0 13,000 

Instrument Air

35-15-13 2" 304SS, SCH 80, welded Absorber, Reagent Prep, Fly Ash Silos and Lime Silos Est 2,300 LF 0.00 101.42 0 233,300 

35-15-13 1.5" 304SS, SCH 80, welded Fly Ash Silos and Lime Silos Est 680 LF 0.00 73.37 0 49,900 

35-15-13 1" 304SS, SCH 80, welded Absorber, Reagent Prep, Fly Ash Silos and Lime Silos Est 1,140 LF 0.00 44.22 0 50,400 

35-13-33 Pipe Supports for Instrument Air Est 8.81 TN 0.00 2,650.00 0 23,400 

Valves

31-41-47 Hydrants Est 4 EA 0.00 1,500.00 0 6,000 

35-13-41 Valves with PIVS 6", CI Est 6 EA 0.00 575.00 0 3,500 35-15-41 1" CS Ball Est 4 EA 0.00 150.00 0 600 35-15-41 2" Bronze, Ball Est 4 EA 0.00 750.00 0 3,000 35-13-41 3" CS, Globe, welded Est 32 EA 0.00 1,800.00 0 57,600 35-13-41 6" CS Knifegate, welded Est 4 EA 0.00 3,200.00 0 12,800 

35-13-41 8" CS Knifegate, welded Est 20 EA 0.00 4,800.00 0 96,000 35-13-41 12" CS Knifegate, welded Est 8 EA 0.00 7,200.00 0 57,600 

35-15-41 Small bore valves, CS wededl Allowance Est 1 LT 0.00 10,000.00 0 10,000 31-75-17 Makeup Water pumps 1000 gpm, 200 ft TDH Est 2 EA 0.00 30,000.00 0 60,000 

31-75-93 Sump Pumps 440 gpm, 220 TDH Est 8 EA 0.00 25,000.00 0 200,000 

31-17-45 Air compressors 250 SCFM, 100 psig Est 2 EA 0.00 45,000.00 0 90,000 

31-17-65 Air receivers 1000 Gal Est 2 EA 0.00 7,000.00 0 14,000 31-17-55 Air dryers 250 net SCFM, 100 psig Est 2 EA 0.00 15,000.00 0 30,000 31-65-99 In-line electric water heaters (boilers) 475 kW Est 2 EA 0.00 17,200.00 0 34,400 

41-99-99 Allowance for electrical work for the electric boiler Allow 2 EA 0.00 5,000.00 0 10,000 41 Heat Tracing for Instrumentation Piping 

41-33-65 Heat tracing cable Allow. 5,700 LF 0.00 10.35 0 59,000 

36-15 Insulation for heat traced piping Assumed nominal 4" pipe size Allow. 5,976 SF 0.00 10.00 0 59,800 41-33-65 Power connector and other accessories including thermostats for heat tracing (by zones) Allow. 104 LS 0.00 950.00 98,500 

Electrical - Auxiliary Power and Balance of Plant Electrical Work 16,124,300 5,615,000 

41 Auxiliary Power Modifications Quantities are total for Unit 1&241-51-15 Rserve Aux. Transformer 230kV - 4.16kV, 34/45 MVA, 3phase Est 1 EA 544,000.00 0.00 544,000 0 

41-51-15 Unit Aux. Transformers 24kV - 4.16kV, 15/20 MVA, 3 phase Est 2 EA 490,000.00 0.00 980,000 0 41-51-15 Transformer, 480 V Substation 4.16KV-480V,3phase, 2000/2666KVA Est 4 EA 85,000.00 0.00 340,000 0 41-51-15 Transformer, 480 V Substation 4.16KV-480V,3phase, 1500/2000KVA Est 4 EA 77,000.00 0.00 308,000 0 

Page 8 of 14
OG & E 

Sooner Units 1 & 2 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: 

Est=Estimated Allow.=Allowance C= Contract Q=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Cost Develo

41-41-99 FGD/FF Power Control Centers (one for each unit)

(30'x60') building, includes:Enclosure with HVAC and Lighting/electric service4160V swgr480V swgrMCCsUPSBatteries / ChargersRoom/Area designated for DCSPhone Jack

Est 2 EA 2,103,000.00 0.00 4,206,000 0 

23-17-23 Platforms around elevated PCC quantities are total for Unit 1&2 PCCs Est 2,850 SF 35.00 0.00 99,800 0 23-25-75 Support steel for PCC platforms Est 20 TN 2,650.00 0.00 52,900 0 41-41-99 UAT Power Control Centers (one for each unit).

(15'x20') building, includes:Enclosure with HVAC and Lighting/electric service4160V swgr

Est 2 EA 300,000.00 0.00 600,000 0 

23-25-75 Auxiliary Steel Modifications for UAT PCC's to be located on turbine floor of each unit Est 7 TN 2,650.00 0.00 18,600 0 41-13-15 5KV Cable Bus duct 3000A Est 14,700 FT 550.00 0.00 8,085,000 0 23-25-75 Support steel for cable bus duct Est 84 TN 0.00 2,650.00 0 222,600 43-21-15 Cable Bus Terminations 750 KCM Est 288 EA 0.00 100.00 0 28,800 41-47-25 Relay Panels Est 6 EA 40,000.00 0.00 240,000 0 41-51-99 Lighting transformers 45KVA, 480V, 3 Phase Low voltage XFMR Est 16 EA 15,000.00 250.00 240,000 4,000 41-47-15 Lighting Distribution panel, 200A, 208-120V, 3 Phase Low voltage panel Est 16 EA 10,000.00 200.00 160,000 3,200 

22-13-17 Duct Bank- Swgr Bldg to Truck Scale 24"x24", 4x4" cells (includes embedded conduit) Est 2,100 LF 0.00 125 0 262,500 

42-13-47 Cable Trays 36" Trays Est 2,100 LF 0.00 30.00 0 63,000 42-13-47 Cable Trays 24" Control, & 24" Instrument Est 2,100 LF 0.00 25.00 0 42-15-37 Conduits misc sizes Est 2,100 LF 0.00 10.00 0 21,000 

Miscellaneous Electrical System 

41-15-15 Cathodic Protection Allowance Allow. 2 LS 75,000.00 0.00 150,000 0 41-25-55 Upgrade Fire detection system Allowance Allow. 2 LS 50,000.00 0.00 100,000 0 

CABLES

43-21-15 Cables 5kV 3/C, 500 kcmil Est 9,000 LF 0.00 29.11 0 262,000 43-21-15 Cables 5kV 3/C, 250 kcmil Est 1,050 LF 0.00 16.77 0 17,600 43-21-15 Cables 5kV 3/C, #4/0 Est 6,300 LF 0.00 9.78 0 61,600 43-21-35 Cables 5kV Terminations Est 91 EA 0.00 50.00 0 4,600 

480 V FGD Unit Substation FGD (SDA, Fabric Filter)

43-17-15 Power Feeder Cable, 600 V, from Unit Sub FGD to MCCs Power Feed to all MCC's (1/C 750 MCM) Est 31,500 LF 0.00 9.82 0 309,300 

43-17-15 Power Cable, 600 V (to equipment) 3/C, #10 Est 21,000 LF 0.00 0.87 0 18,300 43-17-15 Power Cable, 600 V (to equipment) 3/C, #6 Est 18,900 LF 0.00 1.92 0 36,300 

Page 9 of 14
OG & E 

Sooner Units 1 & 2 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: 

Est=Estimated Allow.=Allowance C= Contract Q=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Cost Develo

43-17-15 Power Cable, 600 V (to equipment) 3/C, #4 Est 7,770 LF 0.00 2.55 0 19,800 

43-17-15 Power Cable, 600 V (to equipment) 3/C, #2 Est 1,890 LF 0.00 4.40 0 8,300 43-17-15 Power Cable, 600 V (to equipment) 3/C, #1/0 Est 2,100 LF 0.00 6.33 0 13,300 43-17-15 Power Cable, 600 V (to equipment) 3/C, #4/0 Est 2,730 LF 0.00 13.35 0 36,400 43-17-15 Power Cable, 600 V (to equipment) 3/C, 350KCMIL Est 2,100 LF 0.00 17.98 0 37,800 

43-17-15 Power Cable, 600 V (to equipment) 3/C, 500KCMIL Est 2,100 LF 0.00 26.41 0 55,500 43-17-15 Power Cable, 600 V (for VFD's) 4/C, #10 SHLD Est 2,100 LF 0.00 1.20 0 2,500 

43-17-15 Power Cable, 600 V (for VFD's) 4/C, #6 SHLD Est 840 LF 0.00 2.70 0 2,300 43-17-15 Power Cable, 600 V (for VFD's) 4/C, #4 SHLD Est 630 LF 0.00 3.65 0 2,300 43-17-15 Power Cable, 600 V (for VFD's) 3/C, 350KCMIL, SHLD Est 2,100 LF 0.00 16.52 0 34,700 

43-13-17 Control Cable, 600 V 5/C, #10 Est 6,300 LF 0.00 1.30 0 8,200 

43-13-17 Control Cable, 600 V 2/C, #14 Est 31,500 LF 0.00 0.37 0 11,700 43-13-17 Control Cable, 600 V 3/C, #14 Est 14,700 LF 0.00 0.42 0 6,200 43-13-17 Control Cable, 600 V 5/C, #14 Est 6,300 LF 0.00 0.68 0 4,300 43-13-17 Control Cable, 600 V 7/C, #14 Est 2,100 LF 0.00 0.95 0 2,000 43-13-17 Control Cable, 600 V 9/C, #14 Est 2,100 LF 0.00 1.17 0 2,500 43-17-35 Power & Control Cable Terminations Power: 600, Control:1200 Est 3,780 EA 0.00 1.00 0 3,800 

43-13-13 Instrumentation Cable, 300 V 2 pr, #16 TW SHLD Est 63,000 LF 0.00 0.32 0 20,200 

43-13-13 Instrumentation Cable, 300 V 2 tr, #16 TW SHLD Est 14,700 LF 0.00 0.43 0 6,300 

43-13-13 Instrumentation Cable, 300 V 2 pr, #16 SHLD type E Est 14,700 LF 0.00 0.35 0 5,100 

43-13-33 Fiber Optic Cable 2 strand Est 2,100 LF 0.00 0.50 0 1,100 

43-13-33 Fiber Optic Cable 6 strand Est 5,250 LF 0.00 0.96 0 5,000 43-13-33 Fiber Optic Cable 12 strand Est 1,260 LF 0.00 1.46 0 1,800 43-13-33 Fiber Optic Cable 24 strand Est 2,730 LF 0.00 2.21 0 6,000 43-13-99 Profibus DP Cable Est 8,400 LF 0.00 1.50 0 12,600 43-13-27 Cat 5E Est 3,150 LF 0.00 1.40 0 4,400 43-13-43 Instrumentation Cable Terminations Est 6,300 EA 0.00 1.00 0 6,300 

42-17-15 Misc. Junction Boxes & Pull Boxes Est 2 LT 0.00 154,000.00 0 308,000 42-13-47 Cable Trays 36" Trays Est 8,400 LF 0.00 30.00 0 252,000 

42-13-47 Cable Trays 24" Control, & 24" Instrument Est 12,600 LF 0.00 25.00 0 

42-15-37 Conduits misc sizes Est 73,500 LF 0.00 10.00 0 735,000 41-31-15 Grounding

Includes ground grid, rods, bolted connections & cadwelds. Future installation only 

Est 2 LT 0.00 50,000.00 0 100,000 

41-17-25 PA / Page Party Extension System Allow. 2 LT 0.00 20,000.00 0 40,000 

41-17-35 Data COM Extension System Allow. 2 LT 0.00 5,000.00 0 10,000 41-17-35 Telephone Extension System Allow. 2 LT 0.00 5,000.00 0 10,000 41-53-17 Security System Allow. 2 LT 0.00 100,000.00 0 200,000 

480 V Lime/Ash Handling Unit Sub (Lime Handling, Reagent Prep, Ash Handl Area)

43-17-15 Power Cable, 600 V (to equipment) 3/C, #10 Est 18,900 LF 0.00 0.87 0 16,400 

43-17-15 Power Cable, 600 V (to equipment) 3/C, #6 Est 18,900 LF 0.00 1.92 0 36,300 43-17-15 Power Cable, 600 V (to equipment) 3/C, #4 Est 6,300 LF 0.00 2.55 0 16,100 43-17-15 Power Cable, 600 V (to equipment) 3/C, #1/0 Est 2,100 LF 0.00 6.33 0 13,300 43-17-15 Power Cable, 600 V (to equipment) 3/C, #4/0 Est 2,310 LF 0.00 11.53 0 26,600 43-17-15 Power Cable, 600 V (to equipment) 3/C, 350KCMIL Est 2,100 LF 0.00 17.98 0 37,800 

43-17-15 Power Cable, 600 V (to equipment) 3/C, 500KCMIL Est 6,300 LF 0.00 26.41 0 166,400 43-17-15 Power Cable, 600 V 4/C, #10 SHLD Est 2,100 LF 0.00 1.20 0 2,500 

43-17-15 Power Cable, 600 V 4/C, #6 SHLD Est 1,260 LF 0.00 2.70 0 3,400 43-17-15 Power Cable, 600 V 3/C, 350KCMIL, SHLD Est 1,260 LF 0.00 17.98 0 22,700 

43-17-15 Control Cable, 600 V 2/C, #10 Est 12,600 LF 0.00 0.70 0 8,800 

43-17-15 Control Cable, 600 V 7/C, #10 Est 5,250 LF 0.00 1.60 0 8,400 43-17-15 Control Cable, 600 V 2/C, #14 Est 29,400 LF 0.00 0.37 0 10,900 43-17-15 Control Cable, 600 V 3/C, #14 Est 10,500 LF 0.00 0.42 0 4,400 43-17-15 Control Cable, 600 V 5/C, #14 Est 9,450 LF 0.00 0.68 0 6,400 43-17-15 Control Cable, 600 V 7/C, #14 Est 2,100 LF 0.00 0.95 0 2,000 43-17-35 Power & Control Cable Terminations Power: 510, Control: 1000 Est 3,171 EA 0.00 1.00 0 3,200 

43-13-13 Instrumentation Cable, 300 V 1 pr, #16 TW SHLD Est 10,500 LF 0.00 0.18 0 1,900 

43-13-13 Instrumentation Cable, 300 V 1 tr, #16 TW SHLD Est 2,100 LF 0.00 0.29 0 600 

43-13-13 Instrumentation Cable, 300 V 2 pr, #16 TW SHLD Est 21,000 LF 0.00 0.32 0 6,700 

43-13-13 Instrumentation Cable, 300 V 2 tr, #16 TW SHLD Est 4,200 LF 0.00 0.43 0 1,800 

43-13-13 Instrumentation Cable, 300 V 8 pr, #16 TW SHLD Est 4,200 LF 0.00 0.86 0 3,600 

43-13-13 Instrumentation Cable, 300 V 2 pr, #16 SHLD type E Est 12,600 LF 0.00 0.35 0 4,400 

43-13-33 Fiber Optic Cable 2 strand Est 2,100 LF 0.00 0.50 0 1,100 

43-13-33 Fiber Optic Cable 6 strand Est 5,250 LF 0.00 0.96 0 5,000 43-13-33 Fiber Optic Cable 12 strand Est 1,260 LF 0.00 1.46 0 1,800 

Page 10 of 14
OG & E 

Sooner Units 1 & 2 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: 

Est=Estimated Allow.=Allowance C= Contract Q=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Cost Develo

43-13-33 Fiber Optic Cable 24 strand Est 2,730 LF 0.00 2.21 0 6,000 

43-13-99 Profibus DP Cable Est 8,400 LF 0.00 1.50 0 12,600 43-13-27 Cat 5E Est 3,150 LF 0.00 1.40 0 4,400 43-13-43 Instrumentation Cable Terminations Est 6,300 EA 0.00 1.00 0 6,300 

42-17-15 Misc. Junction Boxes & Pull Boxes Est 2 LT 0.00 100,000.00 0 200,000 42-13-47 Cable Trays 36" Trays Est 8,400 LF 0.00 30.00 0 252,000 

42-13-47 Cable Trays 24" Control, & 24" Instrument Est 12,600 LF 0.00 25.00 0 315,000 

42-15-37 Conduits misc sizes Est 52,500 LF 0.00 10.00 0 525,000 41-31-15 Grounding

Includes ground grid, rods, bolted connections & cadwelds. Future installation only 

Est 2 LT 0.00 50,000.00 0 100,000 

41-17-25 PA / Page Party Extension System Est 2 LT 0.00 20,000.00 0 40,000 

41-17-35 Data COM Extension System Est 2 LT 0.00 5,000.00 0 10,000 41-17-35 Telephone Extension System Est 2 LT 0.00 5,000.00 0 10,000 41-53-17 Lightning Protection Est 2 LT 0.00 30,000.00 0 60,000 

Electrical Aux Power Structural Work 0

Foundations for FGD/FF PCC's Quantities shown are total for 2 buildings, 1/unit

21-23-15 Excavation Est 963 CY 0.00 0.00 0 0 

21-17-25 Backfill Est 63 CY 0.00 0.00 0 0 22-13-37 Concrete Est 900 CY 0.00 105.00 0 94,500 22-25-35 Reinforcing Est 68 TN 0.00 1,150.00 0 77,600 

22-17-25 Formwork Est 3,600 SF 0.00 2.50 0 9,000 22-15-25 Embedded Steel Est 7,200 LB 0.00 2.50 0 18,000 22-13-67 Transformer Firewalls 2700 SF Est 100 CY 0.00 225.00 0 22,500 

Transformer Foundations Total for UAT and RAT with containments 0 0 

21-23-15 Excavation Est 621 CY 0.00 0.00 0 0 

21-17-25 Backfill Est 41 CY 0 

22-13-37 Concrete Est 580 CY 0.00 105.00 0 60,900 

22-25-35 Reinforcing Est 44 TN 0.00 1,150.00 0 50,000 

22-17-25 Formwork Est 2,320 SF 0.00 2.50 0 5,800 22-15-25 Embedded Steel Est 2,900 LB 0.00 2.50 0 7,300 23-25-75 Structural Steel Basin Gallery Steel for containments 4.50 TN 0.00 2,650.00 0 11,900 

23-17-23 1 1/4" Grating (Galv) Basin Grating 750 SF 0.00 18.00 0 13,500 

Controls & Instrumentation 4,125,000 75,000 

44-13-15 DCS 4500 I/O points Est 1 LS 2,925,000.00 0.00 2,925,000 0 

71-55-45 DCS - Vendor Field Support 200 mandays @ $1500/day Est 200 DAYS 1,500.00 0.00 300,000 0 44-24-43 Locally Mounted Instruments Est 300 EA 3,000.00 0.00 900,000 0 44-17-15 Instrument Racks included with instruments

35-15-13 Instrument Tubing Allow 1 LT 0.00 75,000 0 75,000 

Modifications / Installation of CEM system Not required Est

Civil Work 0 1,482,700 

21 Laydown Area Approx 4 Acre21-13-25 Cut and strip Topsoil stripping Est 38720 CY 0.00 0.00 0 0 

21-13-45 Topsoil storage stockpile assumes on site stockpiling Est 38720 CY 0.00 0.00 0 0 21-51-27 Geotextile membrane 10 oz/sy Est 19360 SY 0.00 1.80 0 34,800 

21-57-55 Aggregate surfacing 4" thick over entire area Est 19360 SY 0.00 5.65 0 109,400 21-47-25 Grass seeding over stockplie area Est 4 ACRE 0.00 1,000 0 4,000 21-41-65 Silt Fence Total for stockplie and laydown 

area Est 1,820 LF 0.00 1 0 1,800 

21-43-25 Fencing with one 3-strand barbed wire unit Fabric, posts on 10ft centers Est 1,760 LF 0.00 40 0 70,400 

21-43-45 Gates 50ft wide double swing Est 2 EA 0.00 3,500.00 0 7,000 21 Restoration of Laydown Area Est 0 ACRE 0.00 15.00 0 0 

21-21-25 Remove and dispose of aggregate Est 2,215 CY 0.00 0.00 0 0 

11-21-99 Removal of Geotextile membrane Est 19360 SY 0.00 0.00 0 0 

21-23-15 Earthwork to restore - Cut Est 2,462 CY 0.00 0.00 0 0 

21-23-45 Earthwork to restore - Fill Est 2,462 CY 0.00 0.00 0 0 21-23-45 Place topsoil - previously stockpiled Est 70000 CY 0.00 0.00 0 0 21-47-25 Grass seeding - mulch and fertilizer Est 4 ACRE 0.00 1,500 0 6,000 

21 DFGD Area Approx 4 Acre

21-13-25 Cut and strip Topsoil stripping Est 43560 CY 0.00 0.00 0 0 

21-13-45 Topsoil storage stockpile assumes on site stockpiling Est 43560 CY 0.00 0.00 0 0 21-51-27 Geotextile membrane 10 oz/sy Est 21780 SY 0.00 1.80 0 39,200 

Page 11 of 14
OG & E 

Sooner Units 1 & 2 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: 

Est=Estimated Allow.=Allowance C= Contract Q=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Cost Develo

21-57-55 Aggregate surfacing 4" thick over entire area Est 24200 SY 0.00 5.65 0 136,700 

Plant Drainage

21-25-15 Excavation Est 600 CY 0.00 0.00 0 0 

21-57-55 Crushed rock surfacing 12" Est 240 CY 0.00 54.00 0 13,000 

Storm Sewer 

22-23-65 4ft Manholes Est 6 EA 0.00 1,575.00 0 9,500 

22-23-65 6ft Manholes Est 5 EA 0.00 3,000.00 0 15,000 22-23-65 24"x24" Catch Basin 3 ft deep Est 10 EA 0.00 500.00 0 5,000 35-13-35 18" CHDPE Est 750 LF 0.00 30.00 0 22,500 35-13-35 24" CHDPE Est 750 LF 0.00 40.00 0 30,000 35-13-35 36" CHDPE Est 750 LF 0.00 70.00 0 52,500 21 Oily Water Sewer System

22-23-65 4ft Manholes Est 7 EA 0.00 1,575.00 0 11,000 

35-13-23 6" CISP Est 1,650 LF 0.00 28.00 0 46,200 35-13-23 6" Post indicator valve Est 6 EA 0.00 450.00 0 2,700 31-93-53 Oil Water Separator with Lift Station 3,000 gal Est 1 EA 0.00 100,000.00 0 100,000 

21 Sanitary Sewer

22-23-65 4ft Manholes Est 7 EA 0.00 1,575.00 0 11,000 

22-23-65 Cleanouts Est 5 EA 0.00 690.00 0 3,500 35-13-23 6" CISP Est 1,600 LF 0.00 28.00 0 44,800 21-25-15 Excavation for all drainage and sewer 

piping Est 2,222 CY 0.00 0.00 0 0 

21-17-15 Bedding / backfill for all drainage and sewer piping Est 556 CY 0.00 40.00 0 22,200 

Interior Plant Roads and Surfacing

21-13-25 Cut and strip Topsoil stripping Est 2,889 CY 0.00 0.00 0 0 

21-13-25 Cut Est 722 CY 0.00 0.00 0 0 21-17-55 Fill Est 722 CY 0.00 0.00 0 0 21-51-27 Geotextile membrane 10 oz/sy Est 8,667 SY 0.00 1.80 0 15,600 

21-57-55 Aggregate surfacing 6" thick over entire area Est 8,667 SY 0.00 8.50 0 73,700 21-57-35 Concrete road 9" thick, 24ft W x 2600 L Est 1,733 CY 0.00 17.52 0 30,400 

22-25-35 Reinforcing Est 173 TN 0.00 1,150.00 0 199,300 

22-17-25 Formwork Est 5,200 SF 0.00 2.50 0 13,000 21-57-55 Contractor Trailer Area Surfacing

Includes:9" aggregate surfacing12" subgrade prep

Est 14520 SY 0.00 22.48 0 326,400 

21-51-27 Geotextile membrane - entire area 10 oz/sy Est 14520 SY 0.00 1.80 0 26,100 

Removal and Relocation of Existing Equipment and Infrastructure 0 859,300 

Miscellaneous Pipe Relocation - Underground Quantities are total for Units 1&2

35-13-15 14" CS, SCH 40, includes fittings Fuel oil and chemical drains Est 938 LF 0.00 259.50 0 243,400 

35-13-15 12" CS, SCH 40, includes fittings Chemical drains and service water Est 375 LF 0.00 246.30 0 92,400 35-13-15 8" CS, SCH 40, includes fittings Oil drains Est 375 LF 0.00 89.50 0 33,600 

35-13-15 6" CS, SCH 40, includes fittings Fuel oil and service water Est 563 LF 0.00 130.20 0 73,300 

21-25-15 Excavation for Underground Piping Est 834 CY 0.00 0.00 0 0 

21-17-15 Bedding for Underground Piping Est 125 CY 0.00 40.00 0 5,000 21-17-25 Backfill for Underground Piping Est 709 CY 0.00 0.00 0 0 

Miscellaneous Pipe Relocation - Above Ground Quantities are total for Units 1&2 Allow. 1 LT 0.00 200,000 0 200,000 

35-13-15 12" CS, SCH 40, includes fittings Ash water, Unit 1&2 Est 250 LF 0.00 246.30 0 61,600 35-13-15 10" CS, SCH 40, includes fittings Ash water Est 250 LF 0.00 196.80 0 49,200 

35-13-15 8" Ashcolite, flanged Ash sluice line Est 500 LF 0.00 145.20 0 72,600 

35-13-15 4" CS, SCH 40, includes fittings Service water Est 250 LF 0.00 57.60 0 14,400 

35-13-33 Pipe Supports for relocated piping Est 5.22 TN 0.00 2,650.00 0 13,800 

Miscellaneous Structures Building Demolition Unit 1

11-26-99 Ductwork Est 120 TN 0.00 0 0 0 11-23-99 Steel Est 25 TN 0.00 0 0 0 11-22-99 Concrete Assumed existing foundations to be left in place

Miscellaneous Structures Building Demolition Unit 2

Page 12 of 14
OG & E 

Sooner Units 1 & 2 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: 

Est=Estimated Allow.=Allowance C= Contract Q=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Cost Develo

11-26-99 Ductwork Est 60 TN 0.00 0 0 0 11-23-99 Steel Est 10 TN 0.00 0 0 0 11-22-99 Concrete Assumed existing foundations to be left in place

:

Sub-Total of Equipment Material and Labor Costs 113,383,200 38,719,000 Other Costs 

81-13-45 Additional Crane Rental Allowance 4.00 % 0 

61-27-25 Mobilization/Demobilization Est 2.00 % 61-23-35 Scaffolding Est 2.50 % 967,975 

61-17-43 Temporary Facilities and Construction Utilities (Elect, Water, etc.) During Construction 1.00 % 0 

Allowance for Premium Time Labor Five (5) days per week Ten (10) hours per day. Est 1 LS 

61-21-45 Cost due to overtime inefficiency working 5x10's 8.00 % 

61-21-65 Per Diem Expense @ $10/HR 10 hr 

91-13-15 BOP Contractor's General & Administrative Costs

Based on BOP Materials & Labor Costs at 5% (not incl. Equipment Costs )

Est 5.00 % 1,935,950 

91-15-25 BOP Contractor's Profit

Based on BOP Materials & Labor Costs at 10% (not incl. Equipment Costs )

Est 10.00 % 3,871,900 

Total Equipment, Material and Labor Costs 113,383,200 45,494,800 Spare Parts, Special Tools and Consumables 

81-27-75 Mandatory Spare Parts (first year of operation) 0.00 % 0 81-25-35 Special Tools 81-25-25 Consumables (0.5% of Equipment/Material Cost) 0.5 % 567,000 227,000 

Freight, Duties, Taxes, Etc. 

71-27-35 Freight-ExWorks To Site

For material costs only. Freight for Equipment included with equipment costs.

5 % 1,935,950 

71-47-45 Taxes - Sales/Use/VAT/Business/Etc. Not Included 

Total Direct Costs 113,950,200 47,657,800 Total Indirect Costs 0 0 

71-13-15 Engineering / Procurement 6.50 % 

71-23-15 Construction Management 2.00 % 

71-45-57 Start-up & Commissioning Craft Support 2.00 % 71-53-15 Operator Training & Manuals 0.55 % 

71-21-15 Owner's Cost 5.00 % 

Page 13 of 14
OG & E 

Sooner Units 1 & 2 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: 

Est=Estimated Allow.=Allowance C= Contract Q=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Cost Develo

Total Project Cost without Escalation / Contingency 

95-95-95 Escalation 

Equipment.00% 11,964,800 

Material.00% 5,718,900 

Labor.00% 

Indirects.00% 

93-93-93 Contingency 13.970 % 

Total Project Cost with Escalation / Contingency 

97-97-97 Bond Cost 1.00 % 97-97-97 Interest During Construction (AFUDC) 8.66 % 

Total Project Cost 

123456789101112131415161718192021222324252627282930313233343536

Page 14 of 14
OG&E

Muskogee Units 4&5

DFGD System

Cost Estimate Account Summary

Date: 12/23/2009

Account Description Cost

Dry FGD System $86,741,200

Fabric Filter $45,872,900

Ash Recycling System - DFGD 

Contractor's Scope $12,102,900

Waste Ash and Fly Ash Handling 

System $14,311,500

Flue Gas System $52,238,200

Mechanical - Balance of Plant $6,201,400

Electrical - Auxiliary Power and 

Balance of Plant Electrical Work $37,923,600

Controls & Instrumentation $5,088,500

Civil Work $3,597,400

Removal and Relocation of Existing 

Equipment and Infrastructure $4,134,800

Other Costs $66,931,700

Total Indirect Costs $49,601,900

Escalation $63,277,100

Contingency $63,104,100

Bond Cost $5,111,300

Interest During Construction 

(AFUDC) $118,148,300

Total Project Cost $634,386,800

Page 1 of 1
OG & E 

Muskogee Units 4 & 5 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: Est=Estimated Allow.=Allowance WaC= Contract LabQ=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Un

h

(

Dry FGD System 46,462,100 8,387,700 

31-45-25 Dry FGD System Q 2 LT 15,917,133 0.00 31,834,300 0 31-45-35 Reagent Handling / Preparation Est 0 0 

31-45-35 Reagent Handling / Preparation - Mechanical Q 2 LT 3,969,614 0.00 7,939,200 0 26-13-99 Lime Storage Silo with piping for pneumatic unloading (truck) Concrete Silo - Subcontract price Q 1 LT 3,200,000 0.00 3,200,000 0 

24-17-15 Elevator for lime silo

four person rack and pinion maintenance elevator - subcontract price includes labor

Est 1 LT 290,000 0.00 290,000 0 

22-13-27 Concrete pit for the elevator Est 10 CY 0 210.00 0 2,100 41-99-99 Electrical work for the elevator allowance Est 1 LT 0 20,000.00 0 20,000 

33-43-15 Pneumatic lime transfer equipment/piping including blowers, piping, and valves Q 1 EA 400,000 0.00 400,000 0 

23-17-23 Access Gallery Est 2,000 SF 0.00 35.00 0 70,000 

Dry FGD System - Civil / Structural Work 

Foundations for SDA's Quantities are total for 2 units

21-53-13 Piles 16" dia X 60' deep, auger cast Est 14,400 LF 0.00 12.65 0 182,200 

21-23-15 Excavation Est 1,498 CY 0.00 0.00 0 0 

21-17-25 Backfill Est 98 CY 0.00 0.00 0 0 22-13-37 Concrete Est 1,400 CY 0.00 105.00 0 147,000 22-25-35 Reinforcing Est 126 TN 0.00 1,150.00 0 144,900 

22-17-25 Formwork Est 4,200 SF 0.00 2.50 0 10,500 22-15-25 Embedded steel Est 3.50 TN 0.00 5,000.00 0 17,500 

SDA Superstructure Quantities are total for 2 units 

23-25-75 Common Penthouse for SDA's support steel, roof steel, girts and purlins Est 152 TN 0.00 2,650.00 0 402,500 

24-37-43 SDA Roof Insulation between penthouse floor and SDA roof total for 2 SDAs Est 12,070 SF 0.00 15.00 0 181,100 

24-37-47 Roofing for common SDA Penthouse standing seam type. Est 8,100 SF 0.00 18 0 145,800 24-41-25 Siding for common SDA Penthouse insulated metal siding Est 16,200 SF 0.00 12 0 194,400 36-13-23 Shell Insulation subcontract cost Est 61,688 SF 30.00 0 1,850,600 0 22-13-23 Concrete bottom floor for common SDA Penthouse includes metal decking and formwork Est 99 CY 210 0 20,800 

41-37-99 Common Penthouse Building Services H&V and Lighting Est 8,100 SF 0.00 30.00 0 243,000 

31-41-77 Fire Protection for Penthouse Standpipe & hose stations. Est 2 LS 80,000 160,000 24-17-15 Elevator

For SDA - four person rack and pinion elevator. Suncontract price includes labor

Est 1 LT 290,000 0.00 290,000 0 

22-13-37 Concrete pit for the elevator Est 10 CY 0 210.00 0 2,100 41-99-99 Electrical work for the elevator allowance Est 1 LT 0 20,000.00 0 20,000 

Page 1 of 14
OG & E 

Muskogee Units 4 & 5 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: Est=Estimated Allow.=Allowance WaC= Contract LabQ=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Un

h

(

SDA - Support Steel and Access Gallery

23-25-75 Support Steel Included in DFGD equip. Est 300 TN 0 0 0 0 

23-17-23 Walkway from U1 SDA's to U2 SDA's Est 20 TN 0 0 0 0 

23-17-23 Access Gallery Est 1,500 SF 0.00 35.00 0 52,500 

27-17-99 Touch-up painting Est 2 LT 0.00 45,000.00 0 90,000 

Reagent Handling / Preparation- Civil / Structural Work One common for both units 

Foundations for Lime Storage Silo

21-53-13 Piles 16" dia X 60' deep, auger cast Est 4,200 LF 0.00 12.65 0 53,100 

21-23-15 Excavation Est 210 CY 0.00 0.00 0 0 

21-17-25 Backfill Est 60 CY 0.00 0.00 0 0 22-13-37 Concrete Est 150 CY 0.00 105.00 0 15,800 22-25-35 Reinforcing Est 14 TN 0.00 1,150.00 0 15,500 

22-17-25 Formwork Est 450 SF 0.00 2.50 0 1,100 22-15-25 Embedded steel Est 0.38 TN 0.00 5,000.00 0 1,900 23-25-75 Support Steel for lime Storage Silo Not required - concrete silo23-17-23 Galleries Est 1,800 SF 0.00 35.00 0 63,000 23-17-53 Stair Tower for Lime Storage Silo Est 120 TN 2,650 0 318,000 0 31-41-77 Fire Protection Standpipe & hose stations Est 1 LS 60,000.00 60,000 0 

Lime Preparation / Recycle Building (55' x 100' x 125'H)

Quantities shown are total for 2 buildings, 1/unit

22 Substructure 21-53-13 Piles 16" dia X 60' deep, auger cast Est 9,600 LF 0.00 12.65 0 121,400 

21-23-15 Excavation Est 1,284 CY 0.00 0 0 

21-17-25 Backfill Est 84 CY 0.00 0 0 22-13-37 Concrete Est 1,200 CY 105.00 0 126,000 

22-25-35 Reinforcing Est 90 TN 1,150.00 0 103,500 

22-17-25 Formwork Est 3,600 SF 2.50 0 9,000 22-15-25 Embedded steel Est 3.00 TN 5,000.00 0 15,000 

Superstructure

23-25-75 Structural Steel Est 900 TN 2650 0 2,384,400 

24-41-25 Insulated Metal Siding Est 80,000 SF 12 0 960,000 

24-15-15 Rolling Overhead Door one for each building Est 640 SF 27 0 17,300 23-23-23 Metal Roof Decking Est 11,000 SF 2.7 0 29,700 24-37-43 Rigid Roof Insulation, 2" Thick Est 11,000 SF 2.4 0 26,400 24-37-17 Cant Strips, Treated Est 620 LF 1.32 0 800 

24-37-73 Roofing ( 4-Ply Tar & Gravel) Est 11,000 SF 1.55 0 17,100 

22-13-43 Lightweight Concrete Fill 1" Est 247 CY 100 0 24,700 

24-37-27 Roof Flashing Est 620 LF 14.45 0 9,000 

35-13-31 Roof Drains Est 2 LT 20000 0 40,000 

35-13-31 Floor Drains Est 2 LT 25000 0 50,000 

22-13-23 Floor Slabs includes metal decking and formwork Est 101 CY 210 0 21,200 

22-13-23 Floor Finishes Est 8,250 SF 2.5 0 20,600 

24-25-25 Louvers/Windows/Doors Est 8,000 SF 40 0 320,000 

34-41-99 Roof Ventilators Est 8 EA 15000 0 120,000 

23-17-23 Galleries & Landings Est 800 SF 45 0 36,000 

34-55-99 H&V Est 11,000 SF 16.7 0 183,300 

41-37-99 Electrical Service & Lighting Est 11,000 SF 20.0 0 220,000 

31-41-77 Fire Protection Standpipe & hose stations Est 2 LS 60,000.00 120,000 0 

23 Pipe Rack For Lime Handling, Waste Ash Handling and misc Mechanical Piping Quantities shown are total for 2 units

23-25-75 Structure and Support Steel Est 300 TN 0.00 2,650.00 0 795,000 

22 Foundations for support steel 0 0 

21-53-13 Piles 16" dia X 60' deep, auger cast Est 6,000 LF 0.00 12.65 0 75,900 

21-23-15 Excavation Est 884 CY 0.00 0.00 0 0 

21-17-25 Backfill Est 234 CY 0.00 0.00 0 0 22-13-37 Concrete Est 650 CY 0.00 105.00 0 68,300 22-25-35 Reinforcing Est 49 TN 0.00 1,150.00 0 56,100 

22-17-25 Formwork Est 6,500 SF 0.00 2.50 0 16,300 22-15-25 Embedded Steel Est 3,250 LB 0.00 2.50 0 8,100 22 Foundations for Misc. Support Steel Quantities shown are total for 2 units 0 0 

21-23-15 Excavation Est 272 CY 0.00 0.00 0 0 

21-17-25 Backfill Est 72 CY 0.00 0.00 0 0 

Page 2 of 14
OG & E 

Muskogee Units 4 & 5 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: Est=Estimated Allow.=Allowance WaC= Contract LabQ=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Un

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22-13-37 Concrete Est 200 CY 0.00 105.00 0 21,000 

22-25-35 Reinforcing Est 15 TN 0.00 1,150.00 0 17,300 

22-17-25 Formwork Est 2,000 SF 0.00 2.50 0 5,000 22-15-25 Embedded Steel Est 1,000 LB 0.00 2.50 0 2,500 23-25-75 Misc. Support Steel not included elsewhere Quantities shown are total for 2 units Est 100 TN 0 2,650 0 265,000 

23-17-23 Misc. Galleries Quantities shown are total for 2 units Est 3,000 SF 0.00 35.00 0 105,000 

Fabric Filter 24,079,500 4,500,100 

31-57-15 Fabric Filter System Q 2 LT 9,912,416 0.00 19,824,800 0 31-17-45 Fabric Filter Baghouse Air Compressor System Q 2 LT 2,027,372 0.00 4,054,700 0 

35-13-15 Fabric Filter Baghouse Compressor System Piping Included in air compressor system pricing Est 2 LT 0.00 0.00 0 0 

31-27-35 Fabric Filter Bypass Dampers Included in Fabric Filter System Price Est 2 LT 0.00 0.00 0 0 

31-57-99 Hopper Heaters Included in Fabric Filter System Price Est 2 LT 0.00 0.00 0 0 

31-57-99 Vent Fan Included in Fabric Filter System Price Est 2 LT 0.00 0.00 0 0 

31-25-35 Hoist & Trolley Beam Included in Fabric Filter System Price Est 2 LT 0.00 0.00 0 0 

36-13-23 Insulation for Baghouse subcontract cost Est 65,111 SF 0.00 30.00 0 1,953,300 

23-25-75 Penthouse steel for baghouses Support steel, roof steel, girts and purlins. Est 79 TN 0.00 2,650.00 0 209,300 

24-41-25 Siding for baghouse penthouse insulated metal siding Est 12,960 SF 0.00 12 0 155,500 24-37-47 Roofing for baghouse penthouse standing seam type Est 5,751 SF 0.00 18 0 103,500 22-13-23 Concrete bottom floor for baghouse penthouse includes metal decking and formwork Est 70 CY 210 0 14,800 

41-37-99 Building Services H&V and Lighting Est 5,751 SF 0.00 22.00 0 126,500 

31-41-77 Fire Protection for Penthouse Standpipe & hose stations Est 2 LS 60,000.00 120,000 23-25-75 Bottom Enclosure steel Support steel, girts and purlins. Total for Units 1&2 Est 171 TN 0.00 2,650.00 0 453,900 

41-37-99 Building Services H&V and Lighting Est 19,880 SF 0.00 22.00 0 437,400 

24-41-25 Siding for baghouse bottom enclosure

insulated metal siding, support steel and girts included in Alstom pricing

Est 17,976 SF 0.00 12 0 215,700 

31-41-77 Fire Protection for bottom enclosure Standpipe & hose stations Est 2 LS 40,000.00 0.00 80,000 0 

Fabric Filter System - Structural 

Foundations for Fabric Filter Baghouse Quantities shown are total for 2 units

21-53-13 Piles 16" dia X 60' deep, auger cast Est 12,000 LF 0.00 12.65 0 151,800 

21-23-15 Excavation Est 2,568 CY 0.00 0.00 0 

21-17-25 Backfill Est 168 CY 0.00 0.00 0 22-13-37 Concrete Est 2,400 CY 0.00 105.00 0 252,000 22-25-35 Reinforcing Est 216 TN 0.00 1,150.00 0 248,400 

22-17-25 Formwork Est 7,200 SF 0.00 2.50 0 18,000 22-15-25 Embedded Steel Est 6.00 TN 0.00 5,000.00 30,000 

Support Steel and Access Gallery 

23-25-75 Support Steel Included in Baghouse equip price Q 420 TN 0.00 0 0 0 

23-17-23 Access Gallery Q 3,000 SF 0.00 35.00 0 105,000 

27-17-99 Touch-up painting Est 1 LT 0.00 25,000.00 0 25,000 

Page 3 of 14
OG & E 

Muskogee Units 4 & 5 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: Est=Estimated Allow.=Allowance WaC= Contract LabQ=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Un

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Ash Recycling System - DFGD Contractor's Scope 6,843,000 0 

31-45-99 Ash Recycling System - Mechanical 2 LT 3,421,528 6,843,000 31-45-99 Recycle Ash Storage Silo Included in Ash Recycling System Price Q 0.00 0.00 0 0 

31-45-99 Recycle Ash Silo Bin Vent Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Ash Fluidizing Air Blower Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Ash Fluidizing Air Heater Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Ash Silo Discharge Rotary Feeder Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Slurry Vibrating Screen Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Ash Prep Area Sump Tank Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Ash Prep Area Sump Tank Agitator Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Ash Slurry Mix Tank Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Ash Slurry Mix Tank Agitator Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Slurry Storage Tank Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Slurry Storage Tank Agitator Included in Ash Recycling System Price Q 0.00 0.00 0 0 31-45-99 Recycle Slurry Feed Pumps Included in Ash Recycling System Price Q 0.00 0.00 0 0 

Ash Recycling System - BOP Scope 60,000 565,200 

Ash Reagent Recycle Building Included with Lime Preparation Building

24-35 Ash Handling Blower Building (25' x 50' x 25'H) Quantities shown are total for 2 buildings, 1/unit

22-13 Substructure 

21-53-13 Piles 16" dia X 60' deep, auger cast Est 2,400 LF 0.00 12.65 0 30,400 

21-23-15 Excavation Est 214 CY 0.00 0.00 0 0 

21-17-25 Backfill Est 14 CY 0.00 0.00 0 0 22-13-37 Concrete Est 200 CY 0.00 105.00 0 21,000 22-25-35 Reinforcing Est 15 TN 0.00 1,150.00 0 17,300 

22-17-25 Formwork Est 800 SF 0.00 2.50 0 2,000 22-15-25 Embedded Steel Est 1,600 LB 0.00 2.50 0 4,000 24-35-25 Pre-engineered building Includes H&V and Lighting Est 2,500 SF 0.00 175.00 0 437,500 23-25-75 Additional Support Steel for Waste Ash Pipes outside of pipe rack Est 20 TN 0.00 2,650.00 0 53,000 31-41-77 Fire Protection Standpipe & hose stations Est 2 LS 30,000 60,000 

Waste Ash and Fly Ash Handling System 10,131,300 391,700 

33 Waste Ash Handling System - Mechanical 

26-13-15 Waste Ash silo Concrete silo - subcontract price Q 1 LT 1,550,000 0.00 1,550,000 0 24-17-15 Elevator for waste ash silo maintenance elvator - subcontract price Est 1 LT 290,000 0.00 290,000 0 

22-13-27 Concrete pit for the elevator total for 2 silo elevators Est 10 CY 0 210.00 0 2,100 41-99-99 Electrical work for the elevator allowance Est 1 LT 0 20,000.00 0 20,000 

33-13-45 Waste Handling Systsem Includes blowers, ash valves, and ash piping Q 1 LT 5,300,000 0.00 5,300,000 0 

Page 4 of 14
OG & E 

Muskogee Units 4 & 5 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: Est=Estimated Allow.=Allowance WaC= Contract LabQ=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Un

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33-13-45 Mechanical Equipment Est 0 0.00 0 0 

33-13-45 Mechanical Blowers Included in Waste Handling System Price Est 0 0.00 0 0 

33-13-45 Waste Ash Silo Unloading Equipment including Fluidizing Blowers Included in Waste Handling System Handling Price Est 0 0.00 0 0 

33-13-45 Waste Ash Vacuum Pipes from FF hoppers to Filter Separators Included in Waste Handling System Handling Price Est 0 0.00 0 0 

33-13-45 Motor Operated Butterfly Valves Included in Waste Handling System Handling Price Est 0 0.00 0 0 

22-13-75 Fly Ash Silo

Field erected steel silo. Pricing includes mechanical equipment and ash piping

Est 75 TN 4,000 0.00 300,000 0 

33-13-45 Mechanical equipment for ash handling system and silo fly ash unloading equipment Est 1 LT 2,500,000 0.00 2,500,000 0 

Foundations for Fly Ash Silo 

21-53-13 Piles 16" dia X 60' deep, auger cast Est 1,200 LF 0.00 12.65 0 15,200 

21-23-15 Excavation Est 64 CY 0.00 0.00 0 

21-17-25 Backfill Est 24 CY 0.00 0.00 0 22-13-37 Concrete Est 40 CY 0.00 105.00 0 4,200 22-25-35 Reinforcing Est 4 TN 0.00 1,150.00 0 4,100 

22-17-25 Formwork Est 120 SF 0.00 2.50 0 300 22-15-25 Embedded Steel Est 0.10 TN 0.00 5,000.00 500 23-25-75 Support Steel for Fly Ash Storage Silo Est 50 TN 0.00 2,650.00 0 132,500 23-17-23 Access Gallery for fly ash silo Included with Misc Galleries. 0 SF 0 35 0 0 33-57-65 Truck Scale Est 1 LT 125,000 0 125,000 0 21-53-13 Piles 16" dia X 60' deep, auger cast Est 900 LF 0.00 12.65 0 11,400 22-13-37 Concrete foundation and approach for truck scale Est 350 CY 0 210 0 73,500 

41-99-99 Electrical allowance for truck scale Est 1 LT 0 15,000 0 15,000 

Foundations for Waste Ash Silo 

21-53-13 Piles 16" dia X 60' deep, auger cast Est 2,400 LF 0.00 12.65 0 30,400 

21-23-15 Excavation Est 160 CY 0.00 0.00 0 

21-17-25 Backfill Est 60 CY 0.00 0.00 0 22-13-37 Concrete Est 100 CY 0.00 105.00 0 10,500 22-25-35 Reinforcing Est 9 TN 0.00 1,150.00 0 10,400 

22-17-25 Formwork Est 300 SF 0.00 2.50 0 800 22-15-25 Embedded Steel Est 0.25 TN 0.00 5,000.00 1,300 23-25-75 Support Steel for Waste Ash Storage Silo concrete silo Est 0 TN 0.00 2,650.00 0 0 23-17-53 Stair Tower for Waste Ash Silo Est 25 TN 2,650 0 66,300 0 23-17-23 Access Gallery for waste ash silo Est 1,700 SF 0 35 0 59,500 

Flue Gas System 5,810,000 18,243,400 

Spray Dryer Absorber Inlet Duct (from Existing IDFan Outlet) Quantities are total for 2 units 

23-15-35 Ductwork Steel, including plate, stiffeners, internal bracing, turning vanes and walkway grating Est 480 TN 0.00 3,250.00 0 1,560,000 

36-13-57 Insulation & Lagging Est 47,000 SF 0.00 12.00 0 564,000 

31-33-15 Expansion Joints Est 1,300 LF 0.00 230.00 0 299,000 31-27-35 Dampers Not Required

44-21-99 Dry FGD Inlet Ductwork Instrumentation Est 4 LS 30,000.00 0.00 120,000 0 

Spray Dryer Absorber Outlet to Fabric Filter Inlet Quantities are total for 2 units 

23-15-35 Ductwork Steel, including plate, stiffeners, internal bracing, turning vanes and walkway grating Est 240 TN 0.00 3,250.00 0 780,000 

36-13-57 Insulation & Lagging Allow 23,000 SF 0.00 12.00 0 276,000 

31-33-15 Expansion Joints Est 900 LF 0.00 0.00 0 0 

44-21-99 Dry FGD Outlet Ductwork Instrumentation Est 2 LS 30,000.00 0.00 60,000 0 31-27-35 Dampers Not required Est 0 SF 450.00 0.00 0 0 

Page 5 of 14
OG & E 

Muskogee Units 4 & 5 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: Est=Estimated Allow.=Allowance WaC= Contract LabQ=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Un

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Fabric Filter Outlet Duct to Booster Fans and Booster ID Fans to existing chimney breeching Quantities are total for 2 units 

23-15-35 Ductwork Steel, including plate, stiffeners, internal bracing, turning vanes and walkway grating Est 1,650 TN 0.00 3,250.00 0 5,362,500 

36-13-57 Insulation & Lagging Est 159,000 SF 0.00 12.00 0 1,908,000 

31-33-15 Expansion Joints Est 5,200 LF 0.00 230.00 0 1,196,000 31-27-35 Dampers Not required Est 0 SF 450.00 0.00 0 0 

44-21-99 Fabric Filter Outlet Ductwork Instrumentation Est 4 LS 30,000.00 0.00 120,000 0 

Booster ID Fans Quantities are total for 2 units 

31-35-15 New Booster ID Fans

Axial fan, 2 x 50% per unit, 882,450 cfm, includes fan auxiliary equipment

Est 4 EA 775,000 0.00 3,100,000 0 3

41-43-35 Motors for Booster ID Fans 3500 HP Est 4 EA 250,000 0.00 1,000,000 0 31-25-35 Hoist & trolleys for Booster ID Fans 5-ton cap Est 4 EA 15,000 0.00 60,000 0 36-13-23 Fan Insulation & Lagging total for two fans Est 6,000 SF 0.00 12.00 0 72,000 31-27-35 Booster ID Fans Isolation Dampers Single Louver type damper assembly Est 2,800 SF 450.00 0.00 1,260,000 0 

Flue Gas System - StructuralDuctwork Support Foundations Total for all ductwork for 2 units 

21-53-13 Piles 16" dia X 60' deep, auger cast Est 21,600 LF 0.00 12.65 0 273,200 

21-23-15 Excavation Est 2,140 CY 0.00 0.00 0 

21-17-25 Backfill Est 140 CY 0.00 0.00 0 22-13-37 Concrete Est 2,000 CY 0.00 105.00 0 210,000 22-25-35 Reinforcing Est 150 TN 0.00 1,150.00 0 172,500 

22-17-25 Formwork Est 6,000 SF 0.00 2.50 0 15,000 22-15-25 Embedded Steel Est 5.00 TN 0.00 5,000.00 25,000 23-25-75 Structural Steel Duct Supports Est 1,800 TN 0.00 2,650.00 0 4,770,000 

Booster ID Fan Foundations Quantities are total for 2 units 0 

21-53-13 Piles 16" dia X 60' deep, auger cast Est 3,000 LF 0.00 12.65 0 38,000 

21-23-15 Excavation Est 1,819 CY 0.00 0.00 0 

21-17-25 Backfill Est 119 CY 0.00 0.00 0 22-13-37 Concrete Est 1,700 CY 0.00 105.00 0 178,500 22-25-35 Reinforcing Est 128 TN 0.00 1,150.00 0 146,600 

22-17-25 Formwork Est 13,600 SF 0.00 2.50 0 34,000 22-15-25 Embedded Steel Est 8.50 TN 0.00 5,000.00 0 42,500 23-17-23 Access Gallery for all inlet and outlet ductwork Est 3,000 SF 0 35.00 0 105,000 41-37-43 Lighting for access galleries and Booster Fan area Est 6,000 SF 0.00 15.00 0 90,000 

Stack Coating

Acid resistant coating - top 50 ft of liner. Assumed chimney liner 20Ft dia x 500 ft high

61-23-35 Suspended Motorized Modular Platform Rental 90 day rental, each stack Est. 2 LT 45,000.00 0.00 90,000 0 

27-15-35 Prep and clean top 50ft of two flues (inside only) to white metal (SSPC-SP 5) Quantities shown are for 2 stacks. Includes misc. repairs Est. 6,400 SF 0.00 0.00 0 0 27-13-99 Apply acid resistant coating Quantities shown are for 2 stacks. Est. 6,400 SF 0.00 16.50 0 105,600 61-17-43 Temporary Power, Light and Ventilation Est. 2 LT 0.00 10,000.00 0 20,000 

Mechanical - Balance of Plant 0 2,590,000 PipingVacuum Conveying

35-13-99 Vacuum conveying to lime silo Est 0 LF 0.00 57.60 0 0 

Page 6 of 14
OG & E 

Muskogee Units 4 & 5 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: Est=Estimated Allow.=Allowance WaC= Contract LabQ=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Un

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Makeup Water

35-13-15 8" CS, SCH 40, includes fittings, underground Raw water to reagent prep Est 1,160 LF 0.00 130.20 0 151,000 

21-25-15 Excavation for Underground Piping Est 644 CY 0.00 0.00 0 0 

21-17-15 Bedding for Underground Piping Est 97 CY 0.00 40.00 0 3,900 21-17-25 Backfill for Underground Piping Est 548 CY 0.00 0.00 0 0 35-13-15 6" CS, SCH 40, includes fittings, underground Raw water to reagent prep Est 900 LF 0.00 89.50 0 80,600 

35-13-15 2.5" CS, SCH 40, includes fittings Slaker water and dilution water Est 320 LF 0.00 35.60 0 11,400 35-13-15 2.5" CS, SCH 80, includes fittings Slaker water and dilution water Est 320 LF 0.00 55.50 0 17,800 35-13-15 4" CS, SCH 80, includes fittings Recycle water Est 720 LF 0.00 57.60 0 41,500 35-13-33 Pipe Supports for Makeup Water piping Est 4.00 TN 0.00 2,650.00 0 10,600 

Service Water

35-13-15 6" CS, SCH 40, includes fittings, underground Extend existing service water line to new lime unloading area Est 30 LF 0.00 89.50 0 2,700 

35-13-15 3" CS, SCH 40, includes fittings, underground Reagent prep building abd fly ash silos Est 50 LF 0.00 48.80 0 2,400 

21-25-15 Excavation for Underground Piping Est 44 CY 0.00 0.00 0 0 

21-17-15 Bedding for Underground Piping Est 7 CY 0.00 40.00 0 300 21-17-25 Backfill for Underground Piping Est 38 CY 0.00 0.00 0 0 35-13-15 3" CS, SCH 40, includes fittings Absorbers (penthouse) Est 680 LF 0.00 48.80 0 33,200 

35-15-15 2" CS, SCH 80, includes fittings

Reagent prep building, absorbers (penthouse), fly ash silos

Est 600 LF 0.00 39.80 0 23,900 

35-13-33 Pipe Supports for Service Water piping Est 1.51 TN 0.00 2,650.00 0 4,000 

Lime Slurry Pipe

35-13-15 2.5" CS, SCH 80, includes fittings Reagent prep to atomizer head tank in SDA Est 1,410 LF 0.00 55.50 0 78,300 

35-13-33 Pipe Supports for Service Water piping Est 2.07 TN 0.00 2,650.00 0 5,500 

Ash Pipe

35-13-99 10" Ashcolite, flanged Supports included with pipe rack Est 1,440 LF 0.00 165.00 0 237,600 

35-13-33 Pipe supports within building boundaries Est 10 EA 0.00 125.00 0 1,300 

Recycle Slurry Pipe

35-13-15 6" CS, SCH 80, includes fittings, underground Recycle ash silo to atomizer head tank Est 1,410 LF 0.00 135.20 0 190,600 

35-13-33 Pipe Supports for Recycle Slurry piping Est 5.03 TN 0.00 2,650.00 0 13,300 

Slurry Return Pipe

35-13-15 6" CS, SCH 80, includes fittings, underground SDA to reagent prep Est 1,410 LF 0.00 135.20 0 190,600 

35-13-33 Pipe Supports for Recycle Slurry piping Est 5.03 TN 0.00 2,650.00 0 13,300 

Sump Discharge / Drains

35-13-15 2.5" CS, SCH 40, includes fittings Absorber and Prep Building Est 260 LF 0.00 35.60 0 9,300 35-13-15 3" CS, SCH 40, includes fittings Reagent prep building Est 130 LF 0.00 48.80 0 6,300 

35-13-15 4" CS, SCH 40, includes fittings Reagent prep building Est 770 LF 0.00 57.60 0 44,400 35-13-33 Pipe Supports for Sump Discharge and Drains Est 1.42 TN 0.00 2,650.00 0 3,800 35-13-21 3" HDPE includes fittings Undeground. Absorber Sumps Est 3,460 LF 0.00 4.80 0 16,600 35-13-21 4" HDPE includes fittings Fly Ash Silos, Lime Silos Est 2,720 LF 0.00 4.80 0 13,100 

21-25-15 Excavation for Underground Piping Est 2,289 CY 0.00 0.00 0 0 

21-17-15 Bedding for Underground Piping Est 343 CY 0.00 40.00 0 13,700 21-17-25 Backfill for Underground Piping Est 1,946 CY 0.00 0.00 0 0 

Fire Protection

35-13-35 6" HDPE, includes fittings

Extend existing and new for Absorber, Reagent Prep, Fly Ash Silos and Lime Silos

Est 1,660 LF 0.00 8.50 0 14,100 

21-25-15 Excavation for Underground Piping Est 769 CY 0.00 0.00 0 0 

21-17-15 Bedding for Underground Piping Est 115 CY 0.00 40.00 0 4,600 21-17-25 Backfill for Underground Piping Est 653 CY 0.00 0.00 0 0 

Page 7 of 14
OG & E 

Muskogee Units 4 & 5 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: Est=Estimated Allow.=Allowance WaC= Contract LabQ=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Un

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35-13-15 3" CS, SCH 40, includes fittings Absorber, Reagent Prep, Fly Ash Silos and Lime Silos Est 1,120 LF 0.00 48.80 0 54,700 

35-13-33 Pipe Supports for Fire Protection Est 1.44 TN 0.00 2,650.00 0 3,800 

Service Air

35-13-15 3" CS, SCH 40, includes fittings Absorber, Reagent Prep, Fly Ash Silos and Lime Silos Est 2,280 LF 0.00 48.80 0 111,300 

35-15-15 2" CS, SCH 80, includes fittings

Reagent prep building, absorbers (penthouse), fly ash silos

Est 1,000 LF 0.00 39.80 0 39,800 

35-13-33 Pipe Supports for Service Air Est 3.99 TN 0.00 2,650.00 0 10,600 

Instrument Air

35-15-13 2" 304SS, SCH 80, welded Absorber, Reagent Prep, Fly Ash Silos and Lime Silos Est 1,810 LF 0.00 101.42 0 183,600 

35-15-13 1.5" 304SS, SCH 80, welded Fly Ash Silos and Lime Silos Est 470 LF 0.00 73.37 0 34,500 

35-15-13 1" 304SS, SCH 80, welded Absorber, Reagent Prep, Fly Ash Silos and Lime Silos Est 1,140 LF 0.00 44.22 0 50,400 

35-13-33 Pipe Supports for Instrument Air Est 7.09 TN 0.00 2,650.00 0 18,800 

Valves

31-41-47 Hydrants Est 4 EA 0.00 1,500.00 0 6,000 

35-13-41 Valves with PIVS 6", CI Est 6 EA 0.00 575.00 0 3,500 35-15-41 1" CS Ball Est 4 EA 0.00 150.00 0 600 

35-15-41 2" Bronze, Ball Est 4 EA 0.00 750.00 0 3,000 35-13-41 3" CS, Globe, welded Est 32 EA 0.00 1,800.00 0 57,600 35-13-41 6" CS Knifegate, welded Est 4 EA 0.00 3,200.00 0 12,800 

35-13-41 8" CS Knifegate, welded Est 20 EA 0.00 4,800.00 0 96,000 35-13-41 12" CS Knifegate, welded Est 8 EA 0.00 7,200.00 0 57,600 

35-15-41 Small bore valves, CS wededl Allowance Est 1 LT 0.00 10,000.00 0 10,000 31-75-93 Sump Pumps 440 gpm, 220 TDH Est 8 EA 0.00 25,000.00 0 200,000 

31-17-45 Air compressors 250 SCFM, 100 psig Est 2 EA 0.00 45,000.00 0 90,000 

31-17-65 Air receivers 1000 Gal Est 2 EA 0.00 7,000.00 0 14,000 31-17-55 Air dryers 250 net SCFM, 100 psig Est 2 EA 0.00 15,000.00 0 30,000 31-65-99 In-line electric water heaters (boilers) 475 kW Est 2 EA 0.00 17,200.00 0 34,400 

41-99-99 Allowance for electrical work for the electric boiler Allow 2 EA 0.00 5,000.00 0 10,000 41 Heat Tracing for Instrumentation Piping 

41-33-65 Heat tracing cable Allow. 5,700 LF 0.00 10.35 0 59,000 

36-15 Insulation for heat traced piping Assumed nominal 4" pipe size Allow. 5,976 SF 0.00 10.00 0 59,800 41-33-65 Power connector and other accessories including thermostats for heat tracing (by zones) Allow. 104 LS 0.00 950.00 98,500 

Electrical - Auxiliary Power and Balance of Plant Electrical Work 13,592,400 5,414,900 

41 Auxiliary Power Modifications Quantities are total for Unit 1&241-51-15 Rserve Aux. Transformer 230kV - 4.16kV, 34/45 MVA, 3phase Est 1 EA 544,000.00 0.00 544,000 0 

41-51-15 Unit Aux. Transformers 24kV - 4.16kV, 15/20 MVA, 3 phase Est 2 EA 490,000.00 0.00 980,000 0 

41-51-15 Transformer, 480 V Substation 4.16KV-480V,3phase, 2000/2666KVA Est 4 EA 85,000.00 0.00 340,000 0 

41-51-15 Transformer, 480 V Substation 4.16KV-480V,3phase, 1500/2000KVA Est 4 EA 77,000.00 0.00 308,000 0 

Page 8 of 14
OG & E 

Muskogee Units 4 & 5 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: Est=Estimated Allow.=Allowance WaC= Contract LabQ=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Un

h

(

41-41-99 FGD/FF Power Control Centers (one for each unit - stacked)

(30'x60') building, includes:Enclosure with HVAC and Lighting/electric service4160V swgr480V swgrMCCsUPSBatteries / ChargersRoom/Area designated for DCSPhone Jack

Est 2 EA 2,103,000.00 0.00 4,206,000 0 

23-17-23 Platforms around elevated PCC quantities are total for Unit 1&2 PCCs Est 2,850 SF 35.00 0.00 99,800 0 

23-25-75 Support steel for PCC platforms Est 40 TN 2,650.00 0.00 106,000 0 41-41-99 UAT Power Control Centers (one for each unit).

(15'x20') building, includes:Enclosure with HVAC and Lighting/electric service4160V swgr

Est 2 EA 300,000.00 0.00 600,000 0 

23-25-75 Auxiliary Steel Modifications for UAT PCC's to be located on turbine floor of each unit Est 7 TN 2,650.00 0.00 18,600 0 41-13-15 5KV Cable Bus duct 3000A Est 10,000 FT 550.00 0.00 5,500,000 0 23-25-75 Support steel for cable bus duct Est 84 TN 0.00 2,650.00 0 222,600 43-21-15 Cable Bus Terminations 750 KCM Est 288 EA 0.00 100.00 0 28,800 41-47-25 Relay Panels Est 6 EA 40,000.00 0.00 240,000 0 41-51-99 Lighting transformers 45KVA, 480V, 3 Phase Low voltage XFMR Est 16 EA 15,000.00 250.00 240,000 4,000 41-47-15 Lighting Distribution panel, 200A, 208-120V, 3 Phase Low voltage panel Est 16 EA 10,000.00 200.00 160,000 3,200 

22-13-17 Duct Bank- Swgr Bldg to Truck Scale 24"x24", 4x4" cells (includes embedded conduit) Est 900 LF 0.00 125 0 112,500 

42-13-47 Cable Trays 36" Trays Est 2,100 LF 0.00 30.00 0 63,000 42-13-47 Cable Trays 24" Control, & 24" Instrument Est 2,100 LF 0.00 25.00 0 42-15-37 Conduits misc sizes Est 2,100 LF 0.00 10.00 0 21,000 

Miscellaneous Electrical System 

41-15-15 Cathodic Protection Allowance Allow. 2 LS 75,000.00 0.00 150,000 0 41-25-55 Upgrade Fire detection system Allowance Allow. 2 LS 50,000.00 0.00 100,000 0 

CABLES

43-21-15 Cables 5kV 3/C, 500 kcmil Est 9,000 LF 0.00 29.11 0 262,000 43-21-15 Cables 5kV 3/C, 250 kcmil Est 1,050 LF 0.00 16.77 0 17,600 43-21-15 Cables 5kV 3/C, #4/0 Est 6,300 LF 0.00 9.78 0 61,600 43-21-35 Cables 5kV Terminations Est 91 EA 0.00 50.00 0 4,600 

480 V FGD Unit Substation FGD (SDA, Fabric Filter)

43-17-15 Power Feeder Cable, 600 V, from Unit Sub FGD to MCCs Power Feed to all MCC's (1/C 750 MCM) Est 31,500 LF 0.00 9.82 0 309,300 

43-17-15 Power Cable, 600 V (to equipment) 3/C, #10 Est 21,000 LF 0.00 0.87 0 18,300 

43-17-15 Power Cable, 600 V (to equipment) 3/C, #6 Est 18,900 LF 0.00 1.92 0 36,300 

Page 9 of 14
OG & E 

Muskogee Units 4 & 5 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: Est=Estimated Allow.=Allowance WaC= Contract LabQ=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Un

h

(

43-17-15 Power Cable, 600 V (to equipment) 3/C, #4 Est 7,770 LF 0.00 2.55 0 19,800 

43-17-15 Power Cable, 600 V (to equipment) 3/C, #2 Est 1,890 LF 0.00 4.40 0 8,300 43-17-15 Power Cable, 600 V (to equipment) 3/C, #1/0 Est 2,100 LF 0.00 6.33 0 13,300 43-17-15 Power Cable, 600 V (to equipment) 3/C, #4/0 Est 2,730 LF 0.00 13.35 0 36,400 43-17-15 Power Cable, 600 V (to equipment) 3/C, 350KCMIL Est 2,100 LF 0.00 17.98 0 37,800 

43-17-15 Power Cable, 600 V (to equipment) 3/C, 500KCMIL Est 2,100 LF 0.00 26.41 0 55,500 43-17-15 Power Cable, 600 V (for VFD's) 4/C, #10 SHLD Est 2,100 LF 0.00 1.20 0 2,500 

43-17-15 Power Cable, 600 V (for VFD's) 4/C, #6 SHLD Est 840 LF 0.00 2.70 0 2,300 43-17-15 Power Cable, 600 V (for VFD's) 4/C, #4 SHLD Est 630 LF 0.00 3.65 0 2,300 43-17-15 Power Cable, 600 V (for VFD's) 3/C, 350KCMIL, SHLD Est 2,100 LF 0.00 16.52 0 34,700 

43-13-17 Control Cable, 600 V 5/C, #10 Est 6,300 LF 0.00 1.30 0 8,200 

43-13-17 Control Cable, 600 V 2/C, #14 Est 31,500 LF 0.00 0.37 0 11,700 43-13-17 Control Cable, 600 V 3/C, #14 Est 14,700 LF 0.00 0.42 0 6,200 43-13-17 Control Cable, 600 V 5/C, #14 Est 6,300 LF 0.00 0.68 0 4,300 43-13-17 Control Cable, 600 V 7/C, #14 Est 2,100 LF 0.00 0.95 0 2,000 43-13-17 Control Cable, 600 V 9/C, #14 Est 2,100 LF 0.00 1.17 0 2,500 43-17-35 Power & Control Cable Terminations Power: 600, Control:1200 Est 3,780 EA 0.00 1.00 0 3,800 

43-13-13 Instrumentation Cable, 300 V 2 pr, #16 TW SHLD Est 63,000 LF 0.00 0.32 0 20,200 

43-13-13 Instrumentation Cable, 300 V 2 tr, #16 TW SHLD Est 14,700 LF 0.00 0.43 0 6,300 

43-13-13 Instrumentation Cable, 300 V 2 pr, #16 SHLD type E Est 14,700 LF 0.00 0.35 0 5,100 

43-13-33 Fiber Optic Cable 2 strand Est 2,100 LF 0.00 0.50 0 1,100 

43-13-33 Fiber Optic Cable 6 strand Est 5,250 LF 0.00 0.96 0 5,000 43-13-33 Fiber Optic Cable 12 strand Est 1,260 LF 0.00 1.46 0 1,800 43-13-33 Fiber Optic Cable 24 strand Est 2,730 LF 0.00 2.21 0 6,000 43-13-99 Profibus DP Cable Est 8,400 LF 0.00 1.50 0 12,600 43-13-27 Cat 5E Est 3,150 LF 0.00 1.40 0 4,400 43-13-43 Instrumentation Cable Terminations Est 6,300 EA 0.00 1.00 0 6,300 

42-17-15 Misc. Junction Boxes & Pull Boxes Est 2 LT 0.00 154,000.00 0 308,000 42-13-47 Cable Trays 36" Trays Est 8,400 LF 0.00 30.00 0 252,000 

42-13-47 Cable Trays 24" Control, & 24" Instrument Est 12,600 LF 0.00 25.00 0 

42-15-37 Conduits misc sizes Est 73,500 LF 0.00 10.00 0 735,000 41-31-15 Grounding

Includes ground grid, rods, bolted connections & cadwelds. Future installation only 

Est 2 LT 0.00 50,000.00 0 100,000 

41-17-25 PA / Page Party Extension System Allow. 2 LT 0.00 20,000.00 0 40,000 

41-17-35 Data COM Extension System Allow. 2 LT 0.00 5,000.00 0 10,000 41-17-35 Telephone Extension System Allow. 2 LT 0.00 5,000.00 0 10,000 41-53-17 Security System Allow. 2 LT 0.00 100,000.00 0 200,000 

480 V Lime/Ash Handling Unit Sub (Lime Handling, Reagent Prep, Ash Handl Area)

43-17-15 Power Cable, 600 V (to equipment) 3/C, #10 Est 18,900 LF 0.00 0.87 0 16,400 

43-17-15 Power Cable, 600 V (to equipment) 3/C, #6 Est 18,900 LF 0.00 1.92 0 36,300 43-17-15 Power Cable, 600 V (to equipment) 3/C, #4 Est 6,300 LF 0.00 2.55 0 16,100 43-17-15 Power Cable, 600 V (to equipment) 3/C, #1/0 Est 2,100 LF 0.00 6.33 0 13,300 43-17-15 Power Cable, 600 V (to equipment) 3/C, #4/0 Est 2,310 LF 0.00 11.53 0 26,600 43-17-15 Power Cable, 600 V (to equipment) 3/C, 350KCMIL Est 2,100 LF 0.00 17.98 0 37,800 

43-17-15 Power Cable, 600 V (to equipment) 3/C, 500KCMIL Est 6,300 LF 0.00 26.41 0 166,400 43-17-15 Power Cable, 600 V 4/C, #10 SHLD Est 2,100 LF 0.00 1.20 0 2,500 

43-17-15 Power Cable, 600 V 4/C, #6 SHLD Est 1,260 LF 0.00 2.70 0 3,400 43-17-15 Power Cable, 600 V 3/C, 350KCMIL, SHLD Est 1,260 LF 0.00 17.98 0 22,700 

43-17-15 Control Cable, 600 V 2/C, #10 Est 12,600 LF 0.00 0.70 0 8,800 

43-17-15 Control Cable, 600 V 7/C, #10 Est 5,250 LF 0.00 1.60 0 8,400 43-17-15 Control Cable, 600 V 2/C, #14 Est 29,400 LF 0.00 0.37 0 10,900 43-17-15 Control Cable, 600 V 3/C, #14 Est 10,500 LF 0.00 0.42 0 4,400 43-17-15 Control Cable, 600 V 5/C, #14 Est 9,450 LF 0.00 0.68 0 6,400 43-17-15 Control Cable, 600 V 7/C, #14 Est 2,100 LF 0.00 0.95 0 2,000 43-17-35 Power & Control Cable Terminations Power: 510, Control: 1000 Est 3,171 EA 0.00 1.00 0 3,200 

43-13-13 Instrumentation Cable, 300 V 1 pr, #16 TW SHLD Est 10,500 LF 0.00 0.18 0 1,900 

43-13-13 Instrumentation Cable, 300 V 1 tr, #16 TW SHLD Est 2,100 LF 0.00 0.29 0 600 

43-13-13 Instrumentation Cable, 300 V 2 pr, #16 TW SHLD Est 21,000 LF 0.00 0.32 0 6,700 

43-13-13 Instrumentation Cable, 300 V 2 tr, #16 TW SHLD Est 4,200 LF 0.00 0.43 0 1,800 

43-13-13 Instrumentation Cable, 300 V 8 pr, #16 TW SHLD Est 4,200 LF 0.00 0.86 0 3,600 

43-13-13 Instrumentation Cable, 300 V 2 pr, #16 SHLD type E Est 12,600 LF 0.00 0.35 0 4,400 

43-13-33 Fiber Optic Cable 2 strand Est 2,100 LF 0.00 0.50 0 1,100 

43-13-33 Fiber Optic Cable 6 strand Est 5,250 LF 0.00 0.96 0 5,000 43-13-33 Fiber Optic Cable 12 strand Est 1,260 LF 0.00 1.46 0 1,800 

Page 10 of 14
OG & E 

Muskogee Units 4 & 5 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: Est=Estimated Allow.=Allowance WaC= Contract LabQ=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Un

h

(

43-13-33 Fiber Optic Cable 24 strand Est 2,730 LF 0.00 2.21 0 6,000 

43-13-99 Profibus DP Cable Est 8,400 LF 0.00 1.50 0 12,600 43-13-27 Cat 5E Est 3,150 LF 0.00 1.40 0 4,400 43-13-43 Instrumentation Cable Terminations Est 6,300 EA 0.00 1.00 0 6,300 

42-17-15 Misc. Junction Boxes & Pull Boxes Est 2 LT 0.00 100,000.00 0 200,000 42-13-47 Cable Trays 36" Trays Est 8,400 LF 0.00 30.00 0 252,000 

42-13-47 Cable Trays 24" Control, & 24" Instrument Est 12,600 LF 0.00 25.00 0 315,000 

42-15-37 Conduits misc sizes Est 52,500 LF 0.00 10.00 0 525,000 41-31-15 Grounding

Includes ground grid, rods, bolted connections & cadwelds. Future installation only 

Est 2 LT 0.00 50,000.00 0 100,000 

41-17-25 PA / Page Party Extension System Est 2 LT 0.00 20,000.00 0 40,000 

41-17-35 Data COM Extension System Est 2 LT 0.00 5,000.00 0 10,000 41-17-35 Telephone Extension System Est 2 LT 0.00 5,000.00 0 10,000 41-53-17 Lightning Protection Est 2 LT 0.00 30,000.00 0 60,000 

Electrical Aux Power Structural Work 0

Foundations for FGD/FF PCC's Quantities shown are for stacked Unit 1&2 PCC's

21-53-13 Piles 16" dia X 60' deep, auger cast Est 1,200 LF 0.00 12.65 0 15,200 

21-23-15 Excavation Est 482 CY 0.00 0.00 0 0 

21-17-25 Backfill Est 32 CY 0.00 0.00 0 0 22-13-37 Concrete Est 450 CY 0.00 105.00 0 47,300 22-25-35 Reinforcing Est 34 TN 0.00 1,150.00 0 38,800 

22-17-25 Formwork Est 1,800 SF 0.00 2.50 0 4,500 22-15-25 Embedded Steel Est 3,600 LB 0.00 2.50 0 9,000 22-13-67 Transformer Firewalls 2700 SF Est 100 CY 0.00 225.00 0 22,500 

Transformer Foundations Total for UAT and RAT with containments 0 0 

21-53-13 Piles 16" dia X 60' deep, auger cast Est 2,700 LF 0.00 12.65 0 34,200 

21-23-15 Excavation Est 621 CY 0.00 0.00 0 0 

21-17-25 Backfill Est 41 CY 0 

22-13-37 Concrete Est 580 CY 0.00 105.00 0 60,900 

22-25-35 Reinforcing Est 44 TN 0.00 1,150.00 0 50,000 

22-17-25 Formwork Est 2,320 SF 0.00 2.50 0 5,800 22-15-25 Embedded Steel Est 2,900 LB 0.00 2.50 0 7,300 23-25-75 Structural Steel Basin Gallery Steel for containments 4.50 TN 0.00 2,650.00 0 11,900 

23-17-23 1 1/4" Grating (Galv) Basin Grating 750 SF 0.00 18.00 0 13,500 

Controls & Instrumentation 4,125,000 75,000 

44-13-15 DCS 4500 I/O points Est 1 LS 2,925,000.00 0.00 2,925,000 0 

71-55-45 DCS - Vendor Field Support 200 mandays @ $1500/day Est 200 DAYS 1,500.00 0.00 300,000 0 44-24-43 Locally Mounted Instruments Est 300 EA 3,000.00 0.00 900,000 0 44-17-15 Instrument Racks included with instruments

35-15-13 Instrument Tubing Allow 1 LT 0.00 75,000 0 75,000 

Modifications / Installation of CEM system Not required Est

Civil Work 0 1,482,700 

21 Laydown Area Approx 4 Acre21-13-25 Cut and strip Topsoil stripping Est 38720 CY 0.00 0.00 0 0 

21-13-45 Topsoil storage stockpile assumes on site stockpiling Est 38720 CY 0.00 0.00 0 0 21-51-27 Geotextile membrane 10 oz/sy Est 19360 SY 0.00 1.80 0 34,800 

21-57-55 Aggregate surfacing 4" thick over entire area Est 19360 SY 0.00 5.65 0 109,400 21-47-25 Grass seeding over stockplie area Est 4 ACRE 0.00 1,000 0 4,000 21-41-65 Silt Fence Total for stockplie and laydown 

area Est 1,820 LF 0.00 1 0 1,800 

21-43-25 Fencing with one 3-strand barbed wire unit Fabric, posts on 10ft centers Est 1,760 LF 0.00 40 0 70,400 

21-43-45 Gates 50ft wide double swing Est 2 EA 0.00 3,500.00 0 7,000 21 Restoration of Laydown Area Est 0 ACRE 0.00 15.00 0 0 

21-21-25 Remove and dispose of aggregate Est 2,215 CY 0.00 0.00 0 0 

11-21-99 Removal of Geotextile membrane Est 19360 SY 0.00 0.00 0 0 

21-23-15 Earthwork to restore - Cut Est 2,462 CY 0.00 0.00 0 0 

21-23-45 Earthwork to restore - Fill Est 2,462 CY 0.00 0.00 0 0 21-23-45 Place topsoil - previously stockpiled Est 70000 CY 0.00 0.00 0 0 21-47-25 Grass seeding - mulch and fertilizer Est 4 ACRE 0.00 1,500 0 6,000 

21 DFGD Area Approx 4 Acre

21-13-25 Cut and strip Topsoil stripping Est 43560 CY 0.00 0.00 0 0 

Page 11 of 14
OG & E 

Muskogee Units 4 & 5 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: Est=Estimated Allow.=Allowance WaC= Contract LabQ=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Un

h

(

21-13-45 Topsoil storage stockpile assumes on site stockpiling Est 43560 CY 0.00 0.00 0 0 

21-51-27 Geotextile membrane 10 oz/sy Est 21780 SY 0.00 1.80 0 39,200 

21-57-55 Aggregate surfacing 4" thick over entire area Est 24200 SY 0.00 5.65 0 136,700 

Plant Drainage

21-25-15 Excavation Est 600 CY 0.00 0.00 0 0 

21-57-55 Crushed rock surfacing 12" Est 240 CY 0.00 54.00 0 13,000 

Storm Sewer 

22-23-65 4ft Manholes Est 6 EA 0.00 1,575.00 0 9,500 

22-23-65 6ft Manholes Est 5 EA 0.00 3,000.00 0 15,000 22-23-65 24"x24" Catch Basin 3 ft deep Est 10 EA 0.00 500.00 0 5,000 35-13-35 18" CHDPE Est 750 LF 0.00 30.00 0 22,500 

35-13-35 24" CHDPE Est 750 LF 0.00 40.00 0 30,000 35-13-35 36" CHDPE Est 750 LF 0.00 70.00 0 52,500 

21 Oily Water Sewer System

22-23-65 4ft Manholes Est 7 EA 0.00 1,575.00 0 11,000 

35-13-23 6" CISP Est 1,650 LF 0.00 28.00 0 46,200 

35-13-23 6" Post indicator valve Est 6 EA 0.00 450.00 0 2,700 31-93-53 Oil Water Separator with Lift Station 3,000 gal Est 1 EA 0.00 100,000.00 0 100,000 

21 Sanitary Sewer

22-23-65 4ft Manholes Est 7 EA 0.00 1,575.00 0 11,000 

22-23-65 Cleanouts Est 5 EA 0.00 690.00 0 3,500 

35-13-23 6" CISP Est 1,600 LF 0.00 28.00 0 44,800 21-25-15 Excavation for all drainage and sewer 

piping Est 2,222 CY 0.00 0.00 0 0 

21-17-15 Bedding / backfill for all drainage and sewer piping Est 556 CY 0.00 40.00 0 22,200 

Interior Plant Roads and Surfacing

21-13-25 Cut and strip Topsoil stripping Est 2,889 CY 0.00 0.00 0 0 

21-13-25 Cut Est 722 CY 0.00 0.00 0 0 21-17-55 Fill Est 722 CY 0.00 0.00 0 0 21-51-27 Geotextile membrane 10 oz/sy Est 8,667 SY 0.00 1.80 0 15,600 

21-57-55 Aggregate surfacing 6" thick over entire area Est 8,667 SY 0.00 8.50 0 73,700 21-57-35 Concrete road 9" thick, 24ft W x 2600 L Est 1,733 CY 0.00 17.52 0 30,400 

22-25-35 Reinforcing Est 173 TN 0.00 1,150.00 0 199,300 

22-17-25 Formwork Est 5,200 SF 0.00 2.50 0 13,000 21-57-55 Contractor Trailer Area Surfacing

Includes:9" aggregate surfacing12" subgrade prep

Est 14520 SY 0.00 22.48 0 326,400 

21-51-27 Geotextile membrane - entire area 10 oz/sy Est 14520 SY 0.00 1.80 0 26,100 

Removal and Relocation of Existing Equipment and Infrastructure 0 1,086,300 

Miscellaneous Pipe Relocation - Underground Quantities are total for Units 1&2

35-13-15 14" CS, SCH 40, includes fittings Fuel oil and chemical drains Est 938 LF 0.00 259.50 0 243,400 

35-13-15 12" CS, SCH 40, includes fittings Chemical drains and service water Est 375 LF 0.00 246.30 0 92,400 35-13-15 8" CS, SCH 40, includes fittings Oil drains Est 375 LF 0.00 89.50 0 33,600 

35-13-15 6" CS, SCH 40, includes fittings Fuel oil and service water Est 563 LF 0.00 130.20 0 73,300 

21-25-15 Excavation for Underground Piping Est 834 CY 0.00 0.00 0 0 

21-17-15 Bedding for Underground Piping Est 125 CY 0.00 40.00 0 5,000 21-17-25 Backfill for Underground Piping Est 709 CY 0.00 0.00 0 0 

Miscellaneous Pipe Relocation - Above Ground Quantities are total for Units 1&2 Allow. 1 LT 0.00 200,000 0 200,000 3

35-13-15 12" CS, SCH 40, includes fittings Ash water, Unit 1&2 Est 250 LF 0.00 246.30 0 61,600 35-13-15 10" CS, SCH 40, includes fittings Ash water Est 250 LF 0.00 196.80 0 49,200 

35-13-15 8" Ashcolite, flanged Ash sluice line Est 500 LF 0.00 145.20 0 72,600 

35-13-15 4" CS, SCH 40, includes fittings Service water Est 250 LF 0.00 57.60 0 14,400 

35-13-33 Pipe Supports for relocated piping Est 5.22 TN 0.00 2,650.00 0 13,800 

Miscellaneous Structures Demolition/Relocation Unit 4New Foundations for Relocated ID Fans 2 fans total Est 0 

21-53-13 Piles 16" dia X 60' deep, auger cast Est 1,500 LF 0.00 12.65 0 19,000 

21-23-15 Excavation Est 250 CY 0.00 0.00 0 

22-13-37 Concrete Est 400 CY 0.00 105.00 0 42,000 22-25-35 Reinforcing Est 30 TN 0.00 1,150.00 0 34,500 

22-17-25 Formwork Est 3,200 SF 0.00 2.50 0 8,000 

Page 12 of 14
OG & E 

Muskogee Units 4 & 5 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: Est=Estimated Allow.=Allowance WaC= Contract LabQ=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Un

h

(

22-15-25 Embedded Steel Est 2.00 TN 0.00 5,000.00 0 10,000 11628 Relocate ID Fans

Remove from existing location, install in new location including all fan auxiliaries

Est 2 EA 0 0.00 0 0 3

11-26-99 Ductwork Est 120 TN 0.00 0 0 0 11-23-99 Steel Est 25 TN 0.00 0 0 0 

Miscellaneous Structures Demolition/Relocation Unit 5New Foundations for Relocated ID Fans 2 fans total Est 2 EA 0 0.00 0 0 3

21-53-13 Piles 16" dia X 60' deep, auger cast Est 1,500 LF 0.00 12.65 0 19,000 

21-23-15 Excavation Est 250 CY 0.00 0.00 0 

22-13-37 Concrete Est 400 CY 0.00 105.00 0 42,000 22-25-35 Reinforcing Est 30 TN 0.00 1,150.00 0 34,500 

22-17-25 Formwork Est 3,200 SF 0.00 2.50 0 8,000 22-15-25 Embedded Steel Est 2.00 TN 0.00 5,000.00 0 10,000 11628 Relocate ID Fans

Remove from existing location, install in new location including all fan auxiliaries

Est 2 EA 0 0.00 0 0 3

11-26-99 Ductwork Est 120 TN 0.00 0 0 0 11-23-99 Steel Est 25 TN 0.00 0 0 0 

:

Sub-Total of Equipment Material and Labor Costs 111,103,300 42,737,000 Other Costs 

81-13-45 Additional Crane Rental Allowance 4.00 % 0 

61-27-25 Mobilization/Demobilization Est 2.00 % 61-23-35 Scaffolding Est 2.50 % 1,068,425 

61-17-43 Temporary Facilities and Construction Utilities (Elect, Water, etc.) During Construction 1.00 % 0 

Allowance for Premium Time Labor Five (5) days per week Ten (10) hours per day. Est 1 LS 

61-21-45 Cost due to overtime inefficiency working 5x10's 8.00 % 

61-21-65 Per Diem Expense @ $10/HR 10 hr 

91-13-15 BOP Contractor's General & Administrative Costs

Based on BOP Materials & Labor Costs at 5% (not incl. Equipment Costs )

Est 5.00 % 2,136,850 

91-15-25 BOP Contractor's Profit

Based on BOP Materials & Labor Costs at 10% (not incl. Equipment Costs )

Est 10.00 % 4,273,700 

Total Equipment, Material and Labor Costs 111,103,300 50,216,000 Spare Parts, Special Tools and Consumables 

81-27-75 Mandatory Spare Parts (first year of operation) 0.00 % 0 81-25-35 Special Tools 81-25-25 Consumables (0.5% of Equipment/Material Cost) 0.5 % 556,000 251,000 

Freight, Duties, Taxes, Etc. 

Page 13 of 14
OG & E 

Muskogee Units 4 & 5 

Dry FGD Systems 

Conceptual Cost Estimate 

Cost Type: Est=Estimated Allow.=Allowance WaC= Contract LabQ=Vendor Quote

Code of 

Accounts Item Description Scope Definition Cost Type Quantity Unit of Measure Unit Equip.Cost Unit Material Cost Total Equipment Cost Total Material Cost Un

h

(

71-27-35 Freight-ExWorks To Site

For material costs only. Freight for Equipment included with equipment costs.

5 % 2,136,850 

71-47-45 Taxes - Sales/Use/VAT/Business/Etc. Not Included 

Total Direct Costs 111,659,300 52,603,900 Total Indirect Costs 0 0 

71-13-15 Engineering / Procurement 6.50 % 

71-23-15 Construction Management 2.00 % 

71-45-57 Start-up & Commissioning Craft Support 2.00 % 71-53-15 Operator Training & Manuals 0.55 % 

71-21-15 Owner's Cost 5.00 % 

Total Project Cost without Escalation / Contingency 

95-95-95 Escalation 

Equipment 16,190,600 

Material 8,942,700 Labor 

Indirects 

93-93-93 Contingency 14.085 % 

Total Project Cost with Escalation / Contingency 

97-97-97 Bond Cost 1.00 % 97-97-97 Interest During Construction (AFUDC) 8.66 % 

Total Project Cost 

Page 14 of 14
SOONER UNITS 1&2 

MUSKOGEE UNITS 4 & 5 

DRY FGD

DESIGN AND COST ESTIMATE BASIS DOCUMENT

DECEMBER 28, 2009 

PROJECT 11418-019 

PREPARED BY
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

CONTENTS

SECTION PAGE

i 

Design Basis for Dry FGD 

1. SOONER PLANT LOCATION AND TRANSPORTATION ACCESS........................................................1

1.1 WEATHER CONDITIONS ..................................................................................................................1

2. FUEL CHARACTERISTICS .................................................................................................................2

2.1 MAIN FUEL .....................................................................................................................................2

3. WATER SUPPLY.................................................................................................................................4

3.1 SOONER STATION RAW WATER SUPPLY........................................................................................4

3.2 MUSKOGEE STATION RAW WATER SUPPLY...................................................................................4

4. AIR QUALITY CONTROL SYSTEMS (AQCS)....................................................................................4

4.1 SO2 EMISSIONS CONTROL ..............................................................................................................4

4.2 PARTICULATE EMISSIONS CONTROL ..............................................................................................5

5. BOOSTER FANS..................................................................................................................................5

6. CHIMNEY...........................................................................................................................................5

7. MATERIAL HANDLING SYSTEM.......................................................................................................6

7.1 FLY ASH HANDLING SYSTEM.........................................................................................................6

7.2 LIME HANDLING SYSTEM...............................................................................................................6

8. COST ESTIMATING BASIS.................................................................................................................6

8.1 SOONER ESTIMATE SCOPE..............................................................................................................6

8.2 MUSKOGEE ESTIMATE SCOPE ........................................................................................................6

8.3 COMMERCIAL BASIS.......................................................................................................................7

8.4 TECHNICAL BASIS ..........................................................................................................................8
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

CONTENTS

SECTION PAGE

ii 

Design Basis for Dry FGD 

Tables

Table 1.1-1 Major Site Conditions – Sooner Station ....................................................................................1

Table 1.1-2 Major Site Conditions – Muskogee Station..............................................................................2

Table 2.1-1: Sooner & Muskogee – Coal Properties ...................................................................................3 

Attachments

Attachment 1 – Mass Balance Diagrams for Sooner Station and Muskogee Station 

Attachment 2 – Sooner Station General Arrangement Drawing 

Attachment 3 – Sooner Station Power Requirement Tables 

Attachment 4 – Sooner Station Units 1 and 2 Material Handling Diagrams 

Attachment 5 – Summary of Vendor Quotations 

Attachment 6 – Project Schedule
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

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Design Basis for Dry FGD 

1. SOONER PLANT LOCATION AND TRANSPORTATION ACCESS

Sooner Station consists of two 575 MW pulverized coal fired units located east of Red Rock, 

Oklahoma. Sooner Station is located on 11,000 acres of land that straddles Noble and 

Pawnee Counties. The power block for Sooner 1 & 2 is located in Noble County. 

The site is served by the Burlington Northern Santa Fe Railroad. The site is also accessible 

via truck from US Highway 177. 

A major feature of the site is the 150,000 acre-foot reservoir that provides cooling water for 

Sooner 1 & 2. 

The northern portion of the site contains the coal storage area. The rail loop encircles the 

coal handling area. Coal pile runoff flows to the Coal Pile Runoff Pond which, in turn, flows 

to the Waste System Evaporation Pond. 

Sooner 1 & 2 began commercial operation in 1979 and 1980 respectively. Sooner 1 & 2 are 

currently base load units and use No. 2 fuel oil as a start-up fuel and sub-bituminous low 

sulfur coal as the primary fuel. Each boiler was manufactured by Combustion Engineering 

with a design output of 550 megawatts (MW). Particulate emissions are controlled by cold 

side electrostatic dust precipitators with a design removal efficiency of 99.52%. Both units 

have 500-foot tall chimneys. 

1.1 WEATHER CONDITIONS

1.1.1 Sooner Plant Weather Conditions 

Table 1.1-1 lists the major site conditions at Sooner Station, which are based on American 

Society of Heating, Refrigeration and Air Conditioning Engineers (ASHRAE) data. 

Table 1.1-1 

Major Site Conditions – Sooner Station 

Parameter Data 

Nearest weather data location (2009 ASHRAE 

Handbook – Fundamentals (IP)) 

Stillwater, OK Regional Airport 

Latitude/longitude 36.15N/97.08W 

Elevation 933 feet 

Standard pressure 14.07 psia 

Heating dry bulb temperature, 99.6% occurrence 13.6 °F 
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

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Design Basis for Dry FGD 

Parameter Data 

Cooling dry bulb temperature, 0.4% occurrence 101.8 °F 

Extreme wind speed, 1% occurrence 24.6 mph 

50-year occurrence dry bulb temperatures: 

Maximum 112.3 °F 

Minimum -10.3 °F 

1.1.2 Muskogee Plant Weather Conditions 

Table 1.1-2 lists the major site conditions at Muskogee Station which are based on American 

Society of Heating, Refrigeration and Air Conditioning Engineers (ASHRAE) data. 

Table 1.1-2 

Major Site Conditions – Muskogee Station 

Parameter Data 

Nearest weather data location (2009 ASHRAE 

Handbook – Fundamentals (IP)) 

Tulsa, OK Lloyd Jones Regional 

Airport 

Latitude/longitude 35.40N/97.58W 

Elevation 520 feet 

Standard pressure 14.42 psia 

Heating dry bulb temperature, 99.6% occurrence 15.8 °F 

Cooling dry bulb temperature, 0.4% occurrence 100.1 °F 

Extreme wind speed, 1% occurrence 19.8 mph 

50-year occurrence dry bulb temperatures: 

Maximum 112.3 °F 

Minimum -10.3 °F 

2. FUEL CHARACTERISTICS

2.1 MAIN FUEL

Each facility typically fires Powder River Basin (PRB) coal delivered to each site by rail. 
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

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Design Basis for Dry FGD 

The design basis fuel analysis, presented in Table 2.1-1 was developed based on the PRB coal 

fired at the stations and potential future PRB coal sources. The worst case coal was used to 

size the FGD equipment while the average coal was used to develop yearly O&M costs. 

Table 2.1-1: Sooner & Muskogee – Coal Properties 

FUEL ANALYSIS: 

Powder River Basin 

Worst Case PRB 

(FGD Sizing) 

Powder River Basin 

Average PRB (Used 

for O&M Costs) 

Ultimate Analysis 

Carbon % 48.52 51.29 

Sulfur % 0.48 0.22 

Oxygen % 11.80 12.22 

Hydrogen % 3.10 3.34 

Nitrogen % 0.77 0.67 

Chlorine % 0.01 0.01 

Ash % 7.50 5.30 

Moisture % 27.82 26.95 

 100.00 100.00 

Proximate Analysis 

Moisture % 27.8 26.95 

Volatile matter % 32.21 31.73 

Fixed Carbon % 32.47 36.04 

Ash % 7.50 5.30 

Gross (Higher) Heating 

Value Btu/lb 8,000 8,400 

Gross Heating Value 

(Dulong) Btu/lb 8,084 8,593 

Hardgrove Grindability HGI 59 59 

 

Chlorine ppmvd (wt) 125 100 

Fluorine ppmvd (wt) 75 60 

Mercury ppmvd (wt) 0.10 0.08 

 

Ash Analysis 

Silica % 32.00 36.64 

Ferric Oxide % 5.00 5.57 

Alumina % 16.00 16.06 

Titanic Oxide % 1.30 1.37 

Calcium Oxide % 22.50 22.04 

Magnesia % 4.80 4.89 
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

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Design Basis for Dry FGD 

FUEL ANALYSIS: 

Powder River Basin 

Worst Case PRB 

(FGD Sizing) 

Powder River Basin 

Average PRB (Used 

for O&M Costs) 

Sulfur Trioxide % 14.70 8.40 

Potassium Oxide % 0.40 0.46 

Sodium Oxide % 1.10 1.64 

Phosphorous Pentoxide % 1.10 0.84 

Barium Oxide % 0.00 0.52 

Undetermined % 1.13 1.57 

Total % 100.0 100.0 

3. WATER SUPPLY

Each station will supply water for the dry FGD system from its existing cooling water supply. 

Because dry FGD systems do not produce wastewater, additional wastewater treatment is not 

required at either site. 

3.1 SOONER STATION RAW WATER SUPPLY

Sooner Station utilizes a cooling water reservoir to supply water to its once-through cooling 

system. The dry FGD will draw raw water from this same reservoir to use in its process. 

New raw water pumps will be installed near the existing circulating water pumps to supply 

make-up water to the dry FGD system. 

3.2 MUSKOGEE STATION RAW WATER SUPPLY

It has been assumed that the existing city water line will supply make-up water for the dry 

FGD system. 

4. AIR QUALITY CONTROL SYSTEMS (AQCS)

4.1 SO2 EMISSIONS CONTROL

Emissions of SO2 will be controlled using DFGD systems at both stations. Pebble lime slurry 

and recycle ash slurry will be used as the reagents. The maximum lime usage will be based 

on pebble lime with at least 90 percent as CaO availability determined using ASTM C25 and 

at least 40° C temperature rise in 3 minutes reactivity determined using ASTM C110. 
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

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Design Basis for Dry FGD 

4.2 PARTICULATE EMISSIONS CONTROL

Each of Sooner Units 1 and 2 and Muskogee Units 4 and 5 have existing electrostatic 

precipitators (ESPs) to control particulate emissions. These ESPs will remain in service after 

the DFGD systems are installed to allow both plants to continue to sell their ESP fly ash. 

Emissions of DFGD waste will be controlled using a new multi-compartment pulse jet fabric 

filter (PJFF), commonly called a baghouse. Waste collected in the PJFF hoppers will be 

pneumatically transported to the recycle ash storage silo for use as a reagent in the DFGD 

system. Excess waste will be pneumatically transported to a DFGD waste ash silo for 

disposal off-site. ESP fly ash will be blended into the DFGD waste to stabilize it. The 

blending ratio will be a maximum of 10% ESP fly ash. 

For the following reasons a new baghouse is proposed instead of trying to use the existing 

ESP for particulate control: 

• SO2 Emissions Control 

Utilizing a baghouse downstream of a dry FGD will provide a higher sulfur removal 

rate than utilizing an ESP. A DFGD/ESP combination would be expected to remove 

only about 70% of the sulfur while a DFGD/baghouse combination is capable of 

removal rates in the 90% range. In addition, using a baghouse will also lower emissions 

of HCl and HF compared to an ESP. Grand River Dam Authority Unit 2 is an example 

of a plant that utilizes an ESP with a Dry FGD and has an approximate sulfur removal 

rate of 70%. 

• Particulate Emissions 

If a dry FGD were added upstream of an existing ESP, the amount of dust loading in the 

ESP would be increased and the character of the dust loading would change. This 

would raise concerns of whether the plant could continue to meet particulate emissions 

limits without major ESP modifications. 

• Outage Duration 

A new baghouse with interconnecting ductwork could be completely installed prior to a 

tie-in outage whereas any ESP and ESP inlet and outlet duct modifications would have 

to take place during an outage. This would increase the required tie-in outage duration 

and increase power replacement costs for the project. 

5. BOOSTER FANS 

Two 50% capacity axial booster fans will be provided on each unit. 

6. CHIMNEY

The existing chimneys will be reused. The height of the chimney is 500 feet above grade. 

The top 50’ on the interior of each steel chimney and exterior of the concrete shell will have 

an acid resistant coating applied to mitigate the effects of acid condensation. 
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

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Design Basis for Dry FGD 

7. MATERIAL HANDLING SYSTEM

7.1 FLY ASH HANDLING SYSTEM

DFGD waste collected in the PJFF hoppers will be pneumatically transported to the recycle 

storage silo for use as a reagent in the DFGD system. Excess waste will be pneumatically 

transported to the DFGD waste silos for disposal off site. 

Filter separators will be provided on the recycle ash storage silo and the DFGD waste ash silo 

for control of fugitive fly ash emissions. 

7.2 LIME HANDLING SYSTEM

Lime will be delivered to each site via truck. The lime would be pneumatically transferred to 

a 14-day lime storage silo. From the 14-day storage silo, lime would be pneumatically 

conveyed to a 24-hour lime day bin located at the DFGD system reactant preparation building 

for each unit. One day bin will be located at each unit. 

Fugitive emissions will be controlled using bin vent filters located on the 14-day lime storage 

silo and the 24-hour lime day bins. 

8. COST ESTIMATING BASIS

Two separate cost estimates will be developed for this study. One estimate will be developed 

for Sooner Units 1 and 2, and the other for Muskogee Units 4 and 5. 

8.1 SOONER ESTIMATE SCOPE

The Sooner Station cost estimate will be based on the following scope: 

• Unit 1 Spray Dryer Absorber Area 

• Unit 2 Spray Dryer Absorber Area 

• Units 1 and 2 Common Areas (lime unloading and waste handling) 

• Auxiliary Power System 

• Booster ID Fans 

• Baghouses 

8.2 MUSKOGEE ESTIMATE SCOPE

The Muskogee Station cost estimate will be based on the following scope: 

• Unit 4 Spray Dryer Absorber Area 

• Unit 5 Spray Dryer Absorber Area 

• Units 4 and 5 Common Areas (lime unloading and waste handling) 

• Auxiliary Power System 
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

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Design Basis for Dry FGD 

• Booster ID Fans 

• Baghouses 

8.3 COMMERCIAL BASIS

8.3.1 Equipment and Material Cost 

Equipment and material costs will be based on vendor budgetary quotes, estimated quantities, 

and the S&L in-house database. 

8.3.2 Labor Wage Rates 

Labor wage rates will be based on an open shop Oklahoma labor force. 

8.3.3 Labor Crews 

The construction and erection labor cost is based on the use of applicable construction crews 

typically required for projects of this type. 

8.3.4 Productivity 

No allowances have been made to cover items such as the loss in productivity because of 

inability to attract labor, weather conditions, etc. 

8.3.5 Quantity Sources 

All quantity data was developed internally by S&L Lead Engineers. 

8.3.6 Project Schedule 

The project schedule is attached. 

8.3.7 Indirect Expenses 

The engineering costs included herein are estimated and are not to be interpreted as a 

proposal by S&L to perform engineering services. The indirect expenses also include 

Owner’s Construction Management, General Owner’s Costs, and Owner’s Bond Fees. 

8.3.8 Escalation Rates 

a. Equipment escalation is assumed to be 2.5% for 2010 and 4.0% for 2011 through 

2014. Based on project schedule, it is assumed that for Sooner 30% of the 

equipment will be purchased in 2012 with the balance purchased in 2013. No 

major equipment procurement is anticipated past 2013. For Muskogee, it is 

assumed that 30% of the equipment will be purchased in 2012 with the balance 

purchased in 2014. 
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

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Design Basis for Dry FGD 

b. Material escalation is 0.0% for 2010, 3.0% for 2011, and 5.0% for 2012 and 

beyond. Based on project schedule, it is assumed for Sooner that 10% of the 

material will be purchased in 2012, 50% in 2013, and 40% in 2014. For 

Muskogee it is assumed that 10% of the material will be purchased in 2013, 50% 

in 2014, and 40% in 2015. 

c. Labor escalation is 3.0% for 2010 and 4.0% for 2011-2014. Based on project 

schedule, it is assumed that for Sooner 10% of the labor cost will be spent in 

2012, 50% in 2013, and 40% in 2014. For Muskogee, it is assumed that 10% of 

the labor cost will be spent in 2013, 50% in 2014, and 40% in 2015. 

d. Escalation for indirects is 3.0% for 2010 and 4.0% for 2011-2015. Based on 

project schedule, it is assumed that for Sooner 20% of indirects will be spent in 

2011, 40% in 2012, 30% in 2014, and 10% in 2015. For Muskogee, it is 

assumed that 5% of the indirects will be spent in 2011, 15% in 2012, 40% in 

2013, 30% in 2014, and 10% in 2015. 

8.3.9 Sales/Use Taxes 

It has been assumed the project will be structured to avoid sales tax. Therefore, Sales/Use 

Taxes are estimated at 0% of equipment and material. 

8.3.10 Contingency 

For Sooner, contingency is estimated at 14.04% of total direct and indirect costs based on a 

95% confidence level. For Muskogee, contingency is estimated at 14.09% of total direct and 

indirect costs based on a 95% confidence level 

8.3.11 AFUDC Rate 

AFUDC is calculated as 8.66% from 2010 based on information received from OG&E. 

8.3.12 Bond Fees 

Bond fees are estimated at 1% based on typical bond fees and the level of project equity. 

8.3.13 General Owner’s Cost 

General Owner’s Cost is estimated at 5% of Total Direct Cost. 

8.4 TECHNICAL BASIS

The following is a summary of the technical basis of the spray dryer absorber FGD system 

capital cost estimate. 

8.4.1 Common Lime Handling Systems 
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

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Design Basis for Dry FGD 

A common lime handling system will be installed at each station. The lime handling systems 

will be capable of unloading and conveying lime to day bins at each unit. 

a. Lime truck unloader 

i. Lime will be brought on site in trucks. 

ii. The system will be vacuum pneumatic to unload the truck. 

iii. The blowers will be housed in the skirt of the lime storage silo. 

iv. A ventilation system and dust collector will provide dust control. 

b. Lime storage silo 

i. One common lime storage silo will be provided to house 14-days of lime usage 

while burning the design coal. 

ii. The storage silo will be made of concrete. 

iii. The total storage will be 3000 tons. 

iv. The Lime silo will be 36-feet in diameter and 95-feet tall. 

v. Bin vent filters will be provided on the concrete silo for dust control. 

vi. The silo will have a two-hopper outlet. 

c. Lime transfer systems 

i. Two runs of pneumatic, pressurized pipe from the lime silo to the lime prep day 

bins 

ii. Piping will be located on an above grade pipe rack 

8.4.2 Lime Preparation and Recycle Area per Unit 

Each unit will have the following equipment in the quantities listed below. Both the lime 

preparation and recycle area for each unit will be located in the same building. Therefore, 

each unit will have a lime preparation and recycle of the dimensions 55 ft x 100 ft x 125 ft in 

height. 

a. Lime preparation 

i. Two 100% ball mill lime slakers each with a grit screen and gravimetric 

feeder. 
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

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Design Basis for Dry FGD 

ii. Two lime transfer tanks. 

iii. Two lime slurry storage tanks. 

iv. Two slurry feed centrifugal pumps. 

v. Two slurry transfer centrifugal pumps 

vi. One lime day bin 

vii. The equipment, tanks, and day bin will be enclosed by a preparation building 

of the dimension: 100 ft x 55 ft x 125 ft 

b. Each unit will be equipped with a recycle area to recycle lime byproduct through the 

absorber process. 

i. One (1) recycle storage silo 

ii. Two (2) recycle mix tanks 

iii. Two (2) recycle slurry tanks each with two (2) recycle slurry centrifugal 

pumps per tank 

iv. Agitators for each tank 

8.4.3 Absorber Area per Unit 

Each unit will be equipped with the absorber equipment detailed below. 

a. Two (2) absorber vessels per unit, with access doors 

b. Rotary atomizers or dual fluid nozzles, spare atomizers will be included 

c. The vessel material will be carbon steel of a thickness between 1/4 in. and 5/8 in. 

d. A penthouse enclosure for the absorbers. 

e. Each absorber will be provided with 6-inches of insulation and lagging. 

f. Heating and ventilation equipment will be provided for each absorber structure. 

g. Vacuum piping 

h. Vendor quotes have confirmed that two SDA’s will be utilized per unit. 

8.4.4 Baghouse FGD Waste Handling System Common to Both Units 
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

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Design Basis for Dry FGD 

A baghouse will be installed on each unit after the SDA’s to capture FGD waste. The 

baghouses will be sized to handle the FGD waste produced by each unit. Each station will 

have an FGD waste handling system to convey FGD waste from the baghouses to storage 

locations. The waste handling systems will be sized to handle the FGD waste produced by 

each unit. 

a. New pipe and blowers will be required to convey waste from the new baghouses. A 

new ash handling blower building of the dimensions 25 ft x 50 ft x 25 ft high will be 

provided, per unit. 

b. Addition of one new 3-day storage DFGD waste silo for truck unloading. 

i. The DFGD waste silo will be concrete, 30’ in diameter by 68’ tall. 

ii. The silo capacity will be 1,500-tons. 

c. A new ESP fly ash silo will be added near the DFGD waste silo for fly ash blending 

to stabilize the FGD waste. 

i. The fly ash silo will be concrete, 20’ in diameter by 46’ tall. 

ii. The fly ash silo capacity will be 450-tons. 

iii. A pin mixer for fly ash conditioning 

8.4.5 Flues Including Support Steel per Unit 

Each unit will require additional ductwork to bring the flue gas from the existing ID fans to 

the absorbers, absorbers to the baghouses, baghouses to the new booster fans, and new 

booster fans to the existing chimney. 

a. ID Fan Outlet to Absorber Inlet 

i. Carbon steel 1⁄4 in. 

ii. Velocity 4000 fpm 

iii. 6” insulation with lagging 

b. Absorber Outlet to Baghouse Inlet 

i. Carbon steel, 1⁄4 in. 

ii. Velocity 4000 fpm 

iii. 6” insulation with lagging 
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

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Design Basis for Dry FGD 

c. Baghouse Outlet to Axial Booster Fan 

i. Carbon steel, 1⁄4 in. 

ii. Velocity 4000 fpm 

iii. 4” insulation with lagging 

d. Booster Fan Outlet to Chimney 

i. Carbon steel, 1⁄4 in. 

ii. Velocity 4000 fpm 

iii. 4” insulation with lagging 

8.4.6 Control System Modifications 

The control system modification estimates are based on the estimated number of I/O points 

added to each unit and to the common system for each Station. In total, the entire dry FGD 

system will require approximately 4,500 new I/O points at each Station, broken down as 

follow.

a. Each individual unit will require approximately 1,250 I/O points. This includes the 

SDA’s and reagent prep areas. 

b. The common area at each station will require approximately 2,000 I/O points. 

8.4.7 Subsurface and Foundation Work, Both Stations 

Based on the Sooner soil reports, deep foundations (piles and caissons) are not required and 

are not included in the cost estimate. 

Based on the Muskogee soil reports, deep foundations (piles and caissons) are required and 

have been included in the Muskogee cost estimate. 

The existing storm drainage system in the DFGD area at both sites will have to be removed 

and replaced to make room for the new foundations associated with the DFGD system. 

8.4.8 Civil Work, Both Stations 

The civil work required will be typical to both stations. New roads will be paved for lime 

trucks and maintenance access. All other areas will be finished with white rock surfacing. 
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

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Design Basis for Dry FGD 

8.4.9 Construction Work, Both Stations 

Construction labor will be drawn from the same workforce for work on both stations. The 

workforce is detailed below. 

a. Labor will be open shop labor based out of Oklahoma. 

b. The workforce wages will include premiums and per diems. 

c. Labor is based on a 5x10 work week 

d. No incentives to attract labor are included 

8.4.10 Pipe Racks 

Pipe racks will be installed common to both units at each station as detailed below. 

a. A pipe rack for lime transport piping will be installed between the lime unloading 

area and the lime storage silos. 

b. A pipe rack for lime slurry piping from the lime slakers to the SDA’s 

c. A pipe rack for lime transport piping will be installed between the lime silo and 

reagent prep area. 

d. A pipe rack for FGD waste transport will be installed between the baghouse and new 

fly ash silos. 

e. A pipe rack for recycle transfer from the baghouses to the recycle prep area. 

f. A pipe rack for recycle slurry to the SDA’s 

g. One pipe rack per unit for cabling from the Auxiliary Transformers to the reagent 

areas. 

8.4.11 Chimney Modifications 

Each unit will re-use its existing chimney. The interior top 50 feet of each steel chimney 

liner will have an acid resistant coating applied to mitigate the effects of acid condensation. 

8.4.12 Baghouse Sizing 

A new baghouse will be installed at each unit. The baghouses will be used to remove DFGD 

waste from the flue gas stream. 
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

14 

Design Basis for Dry FGD 

8.4.13 Demolition and Relocation 

a. Sooner Station 

i. The existing storm drainage system in the DFGD area will be removed and 

replaced. 

ii. Ash piping in the vicinity of the existing ID fans will be relocated and resupported to make room for the new ductwork. 

b. Muskogee Station 

i. A prefabricated maintenance and material storage warehouse will require 

relocation at Muskogee Station. 

8.4.14 CEMS 

Each Unit’s existing CEMS will be reused. No modifications are required. 

8.4.15 Water Treatment at Each Station 

Water containing a sulfate content of less than 200 mg/L is considered good, and less than 

500 mg/L is considered acceptable. Sooner Station will obtain its water from the Sooner 

Reservoir, which has a sulfate content below 200 mg/L and Muskogee Station will draw its 

water from city water which also has a sulfate content below 200 mg/L. Therefore, water 

treatment, aside from strainers, will not be required at either station. 

8.4.16 Instrument Air Compressors and Dryers, per Station 

Each Station will require new instrument air compressors and dryers to expand the existing 

instrument air systems. The required sizing is discussed below. 

a. 2 x 100% air compressors sized for 250 scfm each at 100 psig. 

b. 2 x 100% instrument air dryers with filters, sized for 250 net scfm each. 

8.4.17 Field Painting, All Units 

All exposed ductwork will be painted with a multiple coat paint system. All other exposed 

steel with painted with an inorganic zinc primer and polyurethane system. 

8.4.18 Performance Testing 

Performance testing is included as part of the Owner’s costs in the estimate tabulation. 
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

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Design Basis for Dry FGD 

8.4.19 Construction Support 

Construction support will be required at each station. It is estimated that support will be 

required for 12 months, at an average of 1.5 persons per station. 

8.4.20 Piping per Unit 

Each Unit will require new instrument air piping run as a header from the new instrument air 

dryers. Instrument air takeoffs will be run from the headers to each lime silo or day bin, bin 

vent, and reagent preparation and recycle area. 

8.4.21 New Booster Fans 

New axial booster fans will be required to overcome the additional pressure drop seen 

through the SDA’s and baghouses. 

a. Two 3500 hp axial ID fans will be installed on each unit. These fans will be arranged 

in a 2 x 50% configuration. 

b. The price includes foundations and motors. A spare motor is not included. 

8.4.22 Electrical per Station 

The electrical items discussed below summarize everything required to power the new DFGD 

area at each Station 

a. One additional startup transformer will be required at each station. i.e. one at Sooner 

and one at Muskogee. 

b. One unit auxiliary transformer will be required per unit, totaling two per station. 

Each UAT will be housed in a pre-engineered building. 

c. Medium voltage switchgear for each unit. 

d. One 480 V switchgear for reagent preparation, recycle, and SDA at each unit. 

e. One pre-engineered reagent preparation electrical equipment building for each unit. 
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

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Design Basis for Dry FGD 

Attachment 1

Mass Balance Diagrams for 

Sooner Station and Muskogee Station 
Client: Oklahoma Gas Electric

Station: Sooner - Unit 1 or 2 SDA FGD System 

PROCESS FLOW DIAGRAM

04 05 07

01 

 02 

03 

Carbon wt% 48.52 SO2 In 

Hydrogen wt% 3.10 B SO2 ONitrogen wt% 0.77 SO3 In Sulfur wt% 0.48 SO3 OOxygen wt% 11.80Chlorine wt% 0.01 Fluorine wt% 0.00 Moisture wt% 27.82 CaO dry wt% 90.0 CAsh wt% 7.50 MgO dry wt% 5.0 06 BoosteCalc. HHV Btu/lb 8,084 Inert Solids dry wt% 5.0

08

 09

Temperature °FPressure in. WC (g)N2 lb/hr-vol% 4,010,582 69.80 4,010,582 66.22 4,010,582 66.22 4,010,582 66.22 10

O2 lb/hr-vol% 302,541 4.61 302,238 4.37 302,194 4.37 302,194 4.37H2O lb/hr-vol% 482,914 13.07 684,352 17.58 684,352 17.58 684,352 17.58 

CO2 lb/hr-vol% 1,125,871 12.47 1,125,871 11.83 1,125,871 11.83 1,125,871 11.83

SO2 lb/hr-ppmv 6,015 458 1,203 87 511 37 511 37 Recycle Feed Pumps (3x100%) 

SO3 lb/hr-ppmv 46 3915050

HCl lb/hr-ppmv 65 9000000HF lb/hr-ppmv 00000000 

Total Flow lb/hr-acfm 5,928,032 1,910,947 6,124,255 1,724,051 6,123,515 1,764,944 6,123,515 1,712,144 Recycle Solids Mixing Tanks (2x100%)MW - Moist. lb/lbmol-lb/lb 28.889 0.089 28.313 0.122 28.311 0.126 28.311 0.122Ash lb/hr-gr/acf 380 0.023 6,287 0.425 63 0.004 63 0.004

Fresh Lime Slaker H2O Lime Slurry Dilution H2O Diluted Slurry Recycle SDA Inlet Waste Solids Recycle Solids Recycle H2O Pin Mixer H2O Landfill Total Water Stabilization Flyas

01 02 03 04 05 06 07 08 09 10 11 12 13 14 

Inert Solids lb/hr 445 0 445 0 445 5,524 5,970 762 5,524 0 0 1,638 0 876 36CaO lb/hr 8,017 0 0 0 0 0 0 0 0 0 0 0 00Ca(OH)2 lb/hr 0 0 10,594 0 10,594 29,908 40,502 4,127 29,908 0 0 4,127 0 0 

MgO lb/hr 445 0 445 0 445 3,228 3,673 445 3,228 0 0 445 0 0 CaSO3*0.5H2O lb/hr 00000 60,656 60,656 8,369 60,656 0 0 8,369 0 0 

CaSO4*2H2O lb/hr 00000 26,958 26,958 3,720 26,958 0 0 3,720 0 0 

CaCl2 + CaF2 lb/hr 0 0 0 0 0 717 717 99 717 0 0 99 0 0 Total Solids lb/hr 8,908 0 11,484 0 11,484 126,992 138,476 17,522 126,992 0 0 18,398 0 876 36Water lb/hr 0 29,374 26,797 0 26,797 190,488 217,285 1,947 14,110 176,378 5,938 7,885 211,690 0 Total Flow lb/hr 8,908 29,374 38,281 0 38,281 317,480 355,762 19,469 141,102 176,378 5,938 26,283 211,690 876 36Total Flow gpm --- 59 62 0 62 491 554 --- --- 352 12 53 423 --- Solids wt% 100 0 30 0 30 40 39 90 90 0 0 70 0 100 

C

1

Baghouse

Inlet SInternApproSaturaSaturaOutlet Flow pVelocDiame

A B

279 163 163

-1 -7 -16

Stream Characteristics

Coal Analysis

Lime Analysis

D

171

Short Term Recycle Silos (2x100%)

Stream Characteristics

ID Fan Outlet SDA Outlet Stack Inlet Booster Fan Inlet

Fresh Lime Slurry Tank

From Cold ESP Outlet A

Spray Dryer Absorber

ID Fans (2x50%)

Lime Slaker

Long 

Wast

Pi

Sargent & Lundy LLC Confidential Page 1 of 1
Client: Oklahoma Gas Electric

Station: Sooner - Unit 1 or 2 SDA FGD System

Average Sulfur Case

PROCESS FLOW DIAGRAM

04 05 07

01 

 02 

03 

Carbon wt% 51.29 SO2 In 

Hydrogen wt% 3.34 B SO2 OuNitrogen wt% 0.67 SO3 In Sulfur wt% 0.22 SO3 OuOxygen wt% 12.22Chlorine wt% 0.01 Fluorine wt% 0.00 Moisture wt% 26.95 CaO dry wt% 90.0 CAsh wt% 5.30 MgO dry wt% 5.0 06 BoosteCalc. HHV Btu/lb 8,593 Inert Solids dry wt% 5.0

08

 09

Temperature °FPressure in. WC (g)N2 lb/hr-vol% 3,998,604 70.08 3,998,604 66.45 3,998,604 66.45 3,998,604 66.45 10

O2 lb/hr-vol% 301,362 4.62 301,231 4.38 301,230 4.38 301,230 4.38H2O lb/hr-vol% 469,360 12.80 670,245 17.33 670,245 17.33 670,245 17.33 

CO2 lb/hr-vol% 1,119,692 12.49 1,119,692 11.84 1,119,692 11.84 1,119,692 11.84

SO2 lb/hr-ppmv 2,605 200 521 38 513 37 513 37 Recycle Feed Pumps (3x100%) 

SO3 lb/hr-ppmv 20 1402020

HCl lb/hr-ppmv 61 8000000HF lb/hr-ppmv 00000000 

Total Flow lb/hr-acfm 5,891,704 1,897,800 6,090,297 1,710,996 6,090,286 1,751,677 6,090,286 1,699,299 Recycle Solids Mixing Tanks (2x100%)MW - Moist. lb/lbmol-lb/lb 28.911 0.087 28.339 0.120 28.338 0.124 28.338 0.120Ash lb/hr-gr/acf 252 0.016 7,298 0.498 73 0.005 73 0.005

Fresh Lime Slaker H2O Lime Slurry Dilution H2O Diluted Slurry Recycle SDA Inlet Waste Solids Recycle Solids Recycle H2O Pin Mixer H2O Landfill Total Water Stabilization Flyas

01 02 03 04 05 06 07 08 09 10 11 12 13 14 

Inert Solids lb/hr 195 0 195 0 195 6,916 7,111 374 6,916 0 0 745 0 370 24CaO lb/hr 3,511 0 0 0 0 0 0 0 0 0 0 0 00Ca(OH)2 lb/hr 0 0 4,639 0 4,639 39,548 44,187 2,142 39,548 0 0 2,142 0 0 

MgO lb/hr 195 0 195 0 195 3,602 3,797 195 3,602 0 0 195 0 0 CaSO3*0.5H2O lb/hr 00000 58,799 58,799 3,184 58,799 0 0 3,184 0 0 

CaSO4*2H2O lb/hr 00000 26,133 26,133 1,415 26,133 0 0 1,415 0 0 

CaCl2 + CaF2 lb/hr 00000 1,719 1,719 93 1,719 0 0 93 0 0 

Total Solids lb/hr 3,901 0 5,029 0 5,029 136,716 141,745 7,403 136,716 0 0 7,774 0 370 24Water lb/hr 0 12,863 11,734 0 11,734 205,075 216,809 823 15,191 189,884 2,509 3,332 205,256 0 Total Flow lb/hr 3,901 12,863 16,763 0 16,763 341,791 358,554 8,226 151,907 189,884 2,509 11,105 205,256 370 24Total Flow gpm --- 26 27 0 27 529 556 --- --- 379 5 22 410 --- Solids wt% 100 0 30 0 30 40 40 90 90 0 0 70 0 100 1

Fresh Lime Slurry Tank

From Cold ESP Outlet A

Spray Dryer Absorber

ID Fans (2x50%)

ID Fan Outlet SDA Outlet Stack Inlet Booster Fan Inlet

D

170

Short Term Recycle Silos (2x100%)

Stream CharacteristicsStream Characteristics

Coal Analysis

Lime Analysis

A B

279 162 162

-1 -7 -16

ApproaSaturatSaturatOutlet Flow pVelociDiame

C

1

Baghouse

Inlet SInterna

Lime Slaker

Long 

Waste 

Pin 

Sargent & Lundy LLC Confidential Page 1 of 1
Client: Oklahoma Gas Electric

Station: Muskogee - Unit 4 or 5 SDA FGD System 

PROCESS FLOW DIAGRAM

04 05 07

01 

 02 

03 

Carbon wt% 48.52 SO2 In 

Hydrogen wt% 3.10 B SO2 OuNitrogen wt% 0.77 SO3 In Sulfur wt% 0.48 SO3 OuOxygen wt% 11.80Chlorine wt% 0.01 Fluorine wt% 0.00 Moisture wt% 27.82 CaO dry wt% 90.0 CAsh wt% 7.50 MgO dry wt% 5.0 06 BoosteCalc. HHV Btu/lb 8,084 Inert Solids dry wt% 5.0

08

 09

Temperature °FPressure in. WC (g)N2 lb/hr-vol% 4,295,932 69.80 4,295,932 66.22 4,295,932 66.22 4,295,932 66.22 10

O2 lb/hr-vol% 324,066 4.61 323,742 4.37 323,695 4.37 323,695 4.37H2O lb/hr-vol% 517,273 13.07 733,044 17.58 733,044 17.58 733,044 17.58 

CO2 lb/hr-vol% 1,205,976 12.47 1,205,976 11.83 1,205,976 11.83 1,205,976 11.83

SO2 lb/hr-ppmv 6,442 458 1,288 87 548 37 548 37 Recycle Feed Pumps (3x100%) 

SO3 lb/hr-ppmv 49 3 10 15050

HCl lb/hr-ppmv 70 9000000HF lb/hr-ppmv 00000000 

Total Flow lb/hr-acfm 6,349,808 2,046,910 6,559,992 1,846,716 6,559,199 1,890,519 6,559,199 1,833,962 Recycle Solids Mixing Tanks (2x100%)MW - Moist. lb/lbmol-lb/lb 28.889 0.089 28.313 0.122 28.311 0.126 28.311 0.122Ash lb/hr-gr/acf 407 0.023 6,734 0.425 67 0.004 67 0.004

Fresh Lime Slaker H2O Lime Slurry Dilution H2O Diluted Slurry Recycle SDA Inlet Waste Solids Recycle Solids Recycle H2O Pin Mixer H2O Landfill Total Water Stabilization Flyas

01 02 03 04 05 06 07 08 09 10 11 12 13 14 

Inert Solids lb/hr 477 0 477 0 477 5,917 6,394 816 5,917 0 0 1,755 0 938 40CaO lb/hr 8,587 0 0 0 0 0 0 0 0 0 0 0 00Ca(OH)2 lb/hr 0 0 11,347 0 11,347 32,036 43,383 4,420 32,036 0 0 4,420 0 0 

MgO lb/hr 477 0 477 0 477 3,458 3,935 477 3,458 0 0 477 0 0 CaSO3*0.5H2O lb/hr 00000 64,972 64,972 8,965 64,972 0 0 8,965 0 0 

CaSO4*2H2O lb/hr 00000 28,876 28,876 3,984 28,876 0 0 3,984 0 0 

CaCl2 + CaF2 lb/hr 0 0 0 0 0 768 768 106 768 0 0 106 0 0 Total Solids lb/hr 9,541 0 12,302 0 12,302 136,027 148,329 18,768 136,027 0 0 19,707 0 938 40Water lb/hr 0 31,464 28,704 0 28,704 204,041 232,745 2,085 15,114 188,927 6,360 8,446 226,751 0 Total Flow lb/hr 9,541 31,464 41,005 0 41,005 340,069 381,074 20,854 151,142 188,927 6,360 28,153 226,751 938 40Total Flow gpm --- 63 66 0 66 526 594 --- --- 378 13 56 453 --- Solids wt% 100 0 30 0 30 40 39 90 90 0 0 70 0 100 1

C

1

Baghouse

Inlet SInternaApproaSaturatSaturatOutlet Flow pVelociDiame

A B

279 163 163

-1 -7 -16

Stream Characteristics

Coal Analysis

Lime Analysis

D

171

Short Term Recycle Silos (2x100%)

Stream Characteristics

ID Fan Outlet SDA Outlet Stack Inlet Booster Fan Inlet

Fresh Lime Slurry Tank

From Cold ESP Outlet A

Spray Dryer Absorber

ID Fans (2x50%)

Lime Slaker

Long 

Waste 

Pin 

Sargent & Lundy LLC Confidential Page 1 of 1
Client: Oklahoma Gas Electric

Station: Muskogee - Unit 4 or 5 SDA FGD System

Average Sulfur Case

PROCESS FLOW DIAGRAM

04 05 07

01 

 02 

03 

Carbon wt% 51.29 SO2 In 

Hydrogen wt% 3.34 B SO2 OuNitrogen wt% 0.67 SO3 In Sulfur wt% 0.22 SO3 OuOxygen wt% 12.22Chlorine wt% 0.01 Fluorine wt% 0.00 Moisture wt% 26.95 CaO dry wt% 90.0 CAsh wt% 5.30 MgO dry wt% 5.0 06 BoosteCalc. HHV Btu/lb 8,593 Inert Solids dry wt% 5.0

08

 09

Temperature °FPressure in. WC (g)N2 lb/hr-vol% 4,283,094 70.08 4,283,094 66.45 4,283,094 66.45 4,283,094 66.45 10

O2 lb/hr-vol% 322,803 4.62 322,663 4.38 322,662 4.38 322,662 4.38H2O lb/hr-vol% 502,756 12.80 717,934 17.33 717,934 17.33 717,934 17.33 

CO2 lb/hr-vol% 1,199,363 12.49 1,199,363 11.84 1,199,363 11.84 1,199,363 11.84

SO2 lb/hr-ppmv 2,778 199 556 38 550 37 550 37 Recycle Feed Pumps (3x100%) 

SO3 lb/hr-ppmv 21 1402020

HCl lb/hr-ppmv 66 8000000HF lb/hr-ppmv 00000000 

Total Flow lb/hr-acfm 6,310,880 2,032,825 6,523,614 1,832,731 6,523,606 1,876,308 6,523,606 1,820,203 Recycle Solids Mixing Tanks (2x100%)MW - Moist. lb/lbmol-lb/lb 28.911 0.087 28.339 0.120 28.338 0.124 28.338 0.120Ash lb/hr-gr/acf 270 0.016 7,831 0.498 78 0.005 78 0.005

Fresh Lime Slaker H2O Lime Slurry Dilution H2O Diluted Slurry Recycle SDA Inlet Waste Solids Recycle Solids Recycle H2O Pin Mixer H2O Landfill Total Water Stabilization Flyas

01 02 03 04 05 06 07 08 09 10 11 12 13 14 

Inert Solids lb/hr 208 0 208 0 208 7,425 7,633 400 7,425 0 0 795 0 395 26CaO lb/hr 3,744 0 0 0 0 0 0 0 0 0 0 0 00Ca(OH)2 lb/hr 0 0 4,947 0 4,947 42,443 47,390 2,287 42,443 0 0 2,287 0 0 

MgO lb/hr 208 0 208 0 208 3,860 4,068 208 3,860 0 0 208 0 0 CaSO3*0.5H2O lb/hr 00000 62,933 62,933 3,391 62,933 0 0 3,391 0 0 

CaSO4*2H2O lb/hr 00000 27,970 27,970 1,507 27,970 0 0 1,507 0 0 

CaCl2 + CaF2 lb/hr 00000 1,850 1,850 100 1,850 0 0 100 0 0 

Total Solids lb/hr 4,160 0 5,363 0 5,363 146,482 151,845 7,893 146,482 0 0 8,287 0 395 26Water lb/hr 0 13,717 12,514 0 12,514 219,723 232,236 877 16,276 203,447 2,675 3,552 219,839 0 Total Flow lb/hr 4,160 13,717 17,877 0 17,877 366,204 384,081 8,770 162,757 203,447 2,675 11,839 219,839 395 26Total Flow gpm --- 27 29 0 29 566 596 --- --- 407 5 24 439 --- Solids wt% 100 0 30 0 30 40 40 90 90 0 0 70 0 100 1

Fresh Lime Slurry Tank

From Cold ESP Outlet A

Spray Dryer Absorber

ID Fans (2x50%)

ID Fan Outlet SDA Outlet Stack Inlet Booster Fan Inlet

D

170

Short Term Recycle Silos (2x100%)

Stream CharacteristicsStream Characteristics

Coal Analysis

Lime Analysis

A B

279 162 162

-1 -7 -16

ApproaSaturatSaturatOutlet Flow pVelociDiame

C

1

Baghouse

Inlet SInterna

Lime Slaker

Long 

Waste 

Pin 

Sargent & Lundy LLC Confidential Page 1 of 1
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

17 

Design Basis for Dry FGD 

Attachment 2

Sooner Station and Muskogee Station 

General Arrangement Drawings 


Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

18 

Design Basis for Dry FGD 

Attachment 3

Sooner Station and Muskogee Station 

Power Requirement Tables 
Oklahoma Gas Electric

Sooner and Muskogee Stations

BART Analysis Follow-Up Work

Project No. 11418-019

November 25, 2009

Inputs:

Capacity Heat Input SDA Inlet 

Flow*

SDA 

Outlet 

Flow*

Booster 

Fan Inlet 

Flow*

Max. 

Sulfur in 

Coal

HHV Inlet SO2

Max. 

Lime*

MWg mmBtu/hr acfm acfm acfm % Btu/lb lb/mmBtu lb/hr

Sooner Unit 1 or 2 570 5,116 1,910,947 1,724,051 1,764,944 0.48 8,084 1.176 8,908

Operating

Connected Operating HP kW HP kW HP kW Usage

Absorber Island

Atomizers 2 2 960 716 1920 1432 1920 1432

Penthouse Heaters 2 2 50 100 100 (winter)

Dampers 2 2 5 4 10 7 10 0.1 2% time

Miscellaneous 30 22 30 22 3 2 10% time

Total 1562 1535

Operating

Connected Operating HP kW HP kW HP kW Usage

Reagent Preparation and Recycle Island

Lime Unloading Blowe 2 1 300 224 600 448 30 22 10% time

Silo Live Bottom 2 1 7 5 14 10 7 5

Lime Feeder 2 1 5 4 10 7 5 4

Ball Mill Slaker 2 1 110 82 220 164 110 82

Slurry Tank Agitator 2 1 40 30 80 60 40 30

Slurry Feed Pump 2 1 20 15 40 30 20 15

Recycle Silo Fluidization Air Blowe 2 1 20 15 40 30 20 15

Recycle Silo Fluidization Air Heate 2 1 40 80 40

Recycle Slurry Mixer 2 1 150 112 300 224 150 112

Recycle Feed Pump 2 1 40 30 80 60 40 30

Miscellaneous 20 15 20 15 10 7 50% time

Total 1127 362

Summary of DFGD/BAGHOUSE Power Consumption

Sooner Unit 1 or 2

*From S&L mass balance

CONNECTED OPERATING

Load per Motor CONNECTED OPERATING

0.5 to 10 HP motors

0.5 to 10 HP motors

Load per Motor

Page 1 of 4
Oklahoma Gas Electric

Sooner and Muskogee Stations

BART Analysis Follow-Up Work

Project No. 11418-019

November 25, 2009

Summary of DFGD/BAGHOUSE Power Consumption

Sooner Unit 1 or 2

Operating

Connected Operating HP kW HP kW HP kW Usage

Baghouse/Ash Handling Island

Compressor 2 1 500 373 1000 746 250 187 50% time

Hopper Heater 16 16 260 260 130 50% time

Penthouse Heaters / Hopper

Enclosure Heaters 12 12 240 240 120 50% time

Transport Air Vac. Blowers 2 1 150 112 300 224 150 112

Miscellaneous 50 37 50 37 10 7 20% time

Total 1507 556

Operating

Connected Operating HP kW HP kW HP kW Usage

Booster Fan System w FGD

Booster Fan with FGD 2 2 3280 2450 6560 4890 6560 4890

Miscellaneous 20 10 20 15 20 15

Total 4900 4900

Total Aux. Power

Connected 

(MW)

Operating

(MW)

FGD System only (SDA+BH) Base 4.2 2.5

Total 4.2 2.5

SDA/Baghouse/Booster Fans Base 9.1 7.4

Total 9.1 7.4 1.29%

CONNECTED OPERATING

Load per Motor CONNECTED OPERATING

0.5 to 10 HP motors

0.5 to 10 HP motors

Load per Motor

Page 2 of 4
Oklahoma Gas Electric

Sooner and Muskogee Stations

BART Analysis Follow-Up Work

Project No. 11418-019

November 25, 2009

Inputs:

Capacity Heat Input SDA Inlet 

Flow*

SDA 

Outlet 

Flow*

Booster 

Fan Inlet 

Flow*

Max. 

Sulfur in 

Coal

HHV Inlet SO2

Max. 

Lime*

MWg mmBtu/hr acfm acfm acfm % Btu/lb lb/mmBtu lb/hr

Muskogee Unit 4 or 5 572 5,480 2,046,910 1,846,716 1,890,519 0.48 8,084 1.176 9,541

Operating

Connected Operating HP kW HP kW HP kW Usage

Absorber Island

Atomizers 2 2 1020 761 2040 1522 2040 1522

Penthouse Heaters 2 2 50 100 100 (winter)

Dampers 2 2 5 4 10 7 10 0.1 2% time

Miscellaneous 30 22 30 22 3 2 10% time

Total 1652 1624

Operating

Connected Operating HP kW HP kW HP kW Usage

Reagent Preparation and Recycle Island

Lime Unloading Blowe 2 1 320 239 640 477 32 24 10% time

Silo Live Bottom 2 1 8 6 16 12 8 6

Lime Feeder 2 1 5 4 10 7 5 4

Ball Mill Slaker 2 1 120 90 240 179 120 90

Slurry Tank Agitator 2 1 40 30 80 60 40 30

Slurry Feed Pump 2 1 30 22 60 45 30 22

Recycle Silo Fluidization Air Blowe 2 1 30 22 60 45 30 22

Recycle Silo Fluidization Air Heate 2 1 40 80 40

Recycle Slurry Mixer 2 1 150 112 300 224 150 112

Recycle Feed Pump 2 1 40 30 80 60 40 30

Miscellaneous 20 15 20 15 10 7 50% time

Total 1203 387

0.5 to 10 HP motors

Load per Motor

Load per Motor CONNECTED OPERATING

0.5 to 10 HP motors

Summary of DFGD/BAGHOUSE Power Consumption

Muskogee Unit 4 or 5

*From S&L mass balance

CONNECTED OPERATING

Page 3 of 4
Oklahoma Gas Electric

Sooner and Muskogee Stations

BART Analysis Follow-Up Work

Project No. 11418-019

November 25, 2009

Summary of DFGD/BAGHOUSE Power Consumption

Muskogee Unit 4 or 5

Operating

Connected Operating HP kW HP kW HP kW Usage

Baghouse/Ash Handling Island

Compressor 2 1 540 403 1080 806 270 201 50% time

Hopper Heater 16 16 260 260 130 50% time

Penthouse Heaters / Hopper

Enclosure Heaters 12 12 240 240 120 50% time

Transport Air Vac. Blowers 2 1 150 112 300 224 150 112

Miscellaneous 50 37 50 37 10 7 20% time

Total 1567 571

Operating

Connected Operating HP kW HP kW HP kW Usage

Booster Fan System w FGD

Booster Fan with FGD 2 2 3520 2630 7040 5250 7040 5250

Miscellaneous 20 10 20 15 20 15

Total 5260 5260

Total Aux. Power

Connected 

(MW)

Operating

(MW)

FGD System only (SDA+BH) Base 4.4 2.6

Total 4.4 2.6

SDA/Baghouse/Booster Fans Base 9.7 7.8

Total 9.7 7.8 1.37%

0.5 to 10 HP motors

0.5 to 10 HP motors

Load per Motor CONNECTED OPERATING

Load per Motor CONNECTED OPERATING

Page 4 of 4
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

19 

Design Basis for Dry FGD 

Attachment 4

Sooner Station Units 1 and 2 

Muskogee Units 4 and 5 

Material Handling Diagrams 




Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

20 

Design Basis for Dry FGD 

Attachment 5

Summary of DFGD Vendor Quotations 

Sooner and Muskogee 
OG&E

Sooner Units 1&2

DFGD Budgetary Proposal Pricing 

Equipment Description Bidder 1 Bidder 2 Bidder 3 Lime preparation $5,010,000 $20,000,000 Incl with Other MiscAbsorber Equipment $20,962,000 $16,000,000 $21,400,000Recycle System $4,506,000 $4,000,000 Incl with Other MiscFabric Filter $13,054,000 $26,000,000 $23,600,000Compressor System $2,670,000 $2,000,000 Incl with Other MiscOther Misc Equipment $10,820,000 $4,000,000 $33,000,000Total Equipment (Units 1&2) $57,022,000 $72,000,000 $78,000,000 S&L Cost Estimate for Sooner 1&2Erection Budget Price (Units 1&2) $62,384,000 $67,270,000 $73,036,000 S&L Cost Estimate for Sooner 1&2Note: Bidders 2 and 3 provided estimated erection manhours. Budget erection cost is calculated based on current S&L Cost Estimate using $62/mhr for mechanical labor cost (non-union) and 55% markup for Crane+scaffolding+mob/demob+Overtime+Per diem+G&A+ProfitNote: S&L Cost estimate was performed based on our historical pricing information for Equipment/Material and Labor Costs. Labor costs were developed independently from the three bidders

$70,500,000$65,753,000

PROPOSAL PRICING COMPARISON FOR OG&E - SOONER UNITS 1&2 DFGD SYS
Sooner 1 & 2 & Muskogee 4 & 5 12/28/09 

DESIGN BASIS DOCUMENT Project 11418-019 

21 

Design Basis for Dry FGD 

Attachment 6

Project Schedule 
Activity

ID DB

Activity

Description

Orig

Dur

e

u

Start Finish

DFGD

PRELIMINARY ENGINEERING

SLN1001 Project Authorization 0 01FEB11*SLN1G01020 Develop FGDs GAs and Engineering Studies 140 01FEB11 16AUG11SLN1G01090 Prepare Design Criteria 84 05APR11 01AUG11SLN1G01608 Prepare Preliminary Site Arrangement Dwgs 23 31MAY11 30JUN11

EPC SPEC

SLN1110 DFGD Sys EPC Spec - Bid Issue to Client 40 01FEB11 28MAR11SLN1118 DFGD Sys EPC Spec- Bid Issue to Vendors 5 29MAR11 04APR11SLN1120 Vendor Bid Period 60 05APR11 27JUN11SLN1130 Evaluate Bids 30 28JUN11 09AUG11SLN1140 Negotiation 40 10AUG11 04OCT11SLN1150 Award EPC 0 04OCT11

PERMITTING

SLP0000108 FGD Other Permits 978 02AUG11* 15MAY15SLN2P00001 Air Permit: Dry FGD Prepare/Submit 636 30AUG11 14FEB14

ENGINEERING - ALL UNITS

SLNSUM1900 Ductwork Design 472 15JUN12 15APR14SLNSUM0500 BOP Piping & Hanger Design 586 25JUN12 01OCT14SLNSUM0510 Electrical Design 654 28JUN12 12JAN15SLNSUM0520 Substructure Design 461 09JUL12 21APR14SLNSUM0800 Steel Design 450 09JUL12 04APR14SLNSUM1060 Develop Preliminary P&ID's 206 18JUL12 03MAY13SLNSUM0550 P&I ID Preparation 482 19SEP12 01AUG14SLNSUM0600 Electrical Wiring 533 22JAN13 13FEB15

MAJOR PROCUREMENT - ALL UNITS

SLN1M10000 DFGD Spec - Bid Issue 60 19OCT11 12JAN12SLN1M10060 DFGD Spec - Award Contract 0 11APR12SLN1M23600 Fabric Filter Bid/Award 100 12APR12 30AUG12SLN1M13500 ID Booster Fans - Bid/Award 92 07MAY12 12SEP12SLN1E17500 Switchyard/TL Upgrades Bid/Award 92 29MAY12 04OCT12

2011 2012 2013 

J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N 

© Primavera Systems, Inc.

Start Date 31MAY10Finish Date 26FEB16Data Date 01JUN10Run Date 30NOV09 13:26

DF01

OKLAHOMA GAS & ELECTRIC

Sooner & Muskogee Stations DFGD Prj

SUMMARY SCHEDULE

Sheet 1 of 4
Sheet 2 of 4

Activity

ID DB

Activity

Description

Orig

Dur

e

u

Start Finish

MAJOR PROCUREMENT - ALL UNITS

SLN2S12000 Ductwork Bid/Award 92 13AUG12 18DEC12SLN2S13000 Structural Steel Bid/Award 92 13AUG12 18DEC12SLN1ES7000 Aux Transformer Bid/Award 92 13SEP12 22JAN13SLN2E18000 Medium Voltage Switchgear Spec - Prep/Rvw/Award 92 16OCT12 22FEB13SLN2F15000 DCS Bid/Award 92 08NOV12 19MAR13SLN2M16000 Dampers Bid/Award 92 08NOV12 19MAR13

FABRICATION / DELIVERY - SOONER U1

FDS10010 DFGD Fabrication & Delivery - Sooner U1 262 17MAY12 22MAY13FDS10020 Fabric Filter Fabrication & Delivery - Sooner U1 300 31AUG12 29OCT13FDS10030 ID Booster Fan Fab & Delivery - Sooner U1 280 13SEP12 14OCT13FDS10040 Aux Transformer Fab & Delivery - Sooner U1 190 06MAR13 27NOV13

FABRICATION / DELIVERY - SOONER U2

FDS20010 DFGD Fabrication & Delivery - Sooner U2 262 05DEC12 10DEC13FDS20020 Fabric Filter Fabrication & Delivery - Sooner U2 300 25FEB13 23APR14FDS20030 ID Booster Fan Fab & Delivery - Sooner U2 280 18MAR13 16APR14FDS20040 Aux Transformer Fab & Delivery - Sooner U2 190 06AUG13 30APR14

FABRICATION / DELIVERY - MUSKOGEE U4

FDM40010 DFGD Fabrication & Delivery - Muskogee U4 262 30MAY13 04JUN14FDM40020 Fabric Filter Fab & Delivery - Muskogee U4 300 19AUG13 15OCT14FDM40030 ID Booster Fan Fab & Delivery - Muskogee U4 280 09SEP13 08OCT14FDM40040 Aux Transformer Fab & Delivery - Muskogee U4 190 29JAN14 22OCT14

FABRICATION / DELIVERY - MUSKOGEE U5

FDM50010 DFGD Fabrication & Delivery - Muskogee U5 262 21NOV13 26NOV14FDM50020 Fabric Filter Fab & Delivery - Muskogee U5 300 11FEB14 09APR15FDM50030 ID Booster Fan Fab & Delivery - Muskogee U5 280 04MAR14 02APR15FDM50040 Aux Transformer Fab & Delivery - Muskogee U5 190 23JUL14 16APR15

CONSTRUCTION CONTRACTS

SLN1S20000 General Work Contract - Prep/Rvw/Award/Spec 85 08JUN12 05OCT12

CONSTRUCTION - SOONER U1

CMS10010 General Work Contractor Mobilization - Sooner U1 10 22OCT12 02NOV12CMS10020 U/G Utilities Relocation FGD Area - Sooner U1 45 05NOV12 08JAN13CMS10030 DFGD Foundations - Sooner U1 80 24DEC12 16APR13CMS10040 Structural Steel Installation - Sooner U1 100 16APR13 03SEP13CMS10050 DFGD Erection and Startup - Sooner U1 300 22MAY13 21JUL14

2011 2012 2013 

J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N 

Sheet 2 of 4
Sheet 3 of 4

Activity

ID DB

Activity

Description

Orig

Dur

e

u

Start Finish

CONSTRUCTION - SOONER U1

CMS10060 ID Booster Fan Area Foundations - Sooner U1 90 24JUN13 28OCT13CMS10070 Duckwork Installation - Sooner U1 150 15AUG13 14MAR14CMS10080 Fabric Filter Erection - Sooner U1 145 30OCT13 22MAY14CMS10090 ID Booster Fan Installation - Sooner U1 60 12NOV13 05FEB14CMS10100 Electrical Installation - Sooner U1 160 05DEC13 21JUL14CMS10110 Mechanical Installation - Sooner U1 140 06JAN14 21JUL14CMS10120 Ductwork Erection ID Fan - Sooner U1 40 06FEB14 02APR14

START-UP - SOONER U1

SUS10010 FGD Commissioning & Start Up - Sooner U1 140 08FEB14 21JUL14SUS10020 Tie-in Outage - Sooner U1 37 09JUN14 21JUL14SUS10030 DFGD in Service - Sooner U1 0 21JUL14SUS10040 DFGD System Balancing / Performance Testing - S1 52 22JUL14 19SEP14

CONSTRUCTION - SOONER U2

CMS20010 General Work Contractor Mobilization - Sooner U2 10 15APR13* 26APR13CMS20020 U/G Utilities Relocation FGD Area - Sooner U2 45 29APR13 28JUN13CMS20030 DFGD Foundations - Sooner U2 80 17JUN13 07OCT13CMS20040 Structural Steel Installation - Sooner U2 100 07OCT13 25FEB14CMS20050 DFGD Erection and Startup - Sooner U2 300 12NOV13 12JAN15CMS20060 ID Booster Fan Area Foundations - Sooner U2 90 24DEC13 30APR14CMS20070 Duckwork Installation - Sooner U2 150 20FEB14 18SEP14CMS20080 Fabric Filter Erection - Sooner U2 145 24APR14 13NOV14CMS20090 ID Booster Fan Installation - Sooner U2 60 15MAY14 07AUG14CMS20100 Electrical Installation - Sooner U2 160 29MAY14 12JAN15CMS20110 Mechanical Installation - Sooner U2 140 26JUN14 12JAN15CMS20120 Ductwork Erection ID Fan - Sooner U2 40 08AUG14 02OCT14

START-UP - SOONER U2

SUS20010 FGD Commissioning & Start Up - Sooner U2 140 02AUG14 12JAN15SUS20020 Tie-in Outage - Sooner U2 37 01DEC14 12JAN15SUS20030 DFGD in Service - Sooner U2 0 12JAN15SUS20040 DFGD System Balancing / Performance Testing - S2 52 13JAN15 13MAR15

CONSTRUCTION - MUSKOGEE U4

CMM40010 General Work Contractor Mobilization - Muskogee4 10 07OCT13* 18OCT13CMM40020 U/G Utilities Relocation FGD Area - Muskogee U4 45 21OCT13 20DEC13

2011 2012 2013 

J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N 

Sheet 3 of 4
Sheet 4 of 4

Activity

ID DB

Activity

Description

Orig

Dur

e

u

Start Finish

CONSTRUCTION - MUSKOGEE U4

CMM40030 DFGD Foundations - Muskogee U4 80 09DEC13 01APR14CMM40040 Structural Steel Installation - Muskogee U4 100 01APR14 19AUG14CMM40050 DFGD Erection and Startup - Muskogee U4 300 07MAY14 06JUL15CMM40060 ID Booster Fan Area Foundations - Muskogee U4 90 18JUN14 22OCT14CMM40070 Duckwork Installation - Muskogee U4 150 14AUG14 13MAR15CMM40080 Fabric Filter Erection - Muskogee U4 145 16OCT14 08MAY15CMM40090 ID Booster Fan Installation - Muskogee U4 60 06NOV14 30JAN15CMM40100 Electrical Installation - Muskogee U4 160 20NOV14 06JUL15CMM40110 Mechanical Installation - Muskogee U4 140 18DEC14 06JUL15CMM40120 Ductwork Erection ID Fan - Muskogee U4 40 02FEB15 27MAR15

START-UP - MUSKOGEE U4

SUM40010 FGD Commissioning & Start Up - Muskogee U4 140 24JAN15 06JUL15SUM40020 Tie-in Outage - Muskogee U4 37 25MAY15 06JUL15SUM40030 DFGD in Service - Muskogee U4 0 06JUL15SUM40040 DFGD System Balancing / Performance Testing - M4 52 07JUL15 04SEP15

CONSTRUCTION - MUSKOGEE U5

CMM50010 General Work Contractor Mobilization - Muskogee5 10 01APR14* 14APR14CMM50020 U/G Utilities Relocation FGD Area - Muskogee U5 45 15APR14 16JUN14CMM50030 DFGD Foundations - Muskogee U5 80 03JUN14 23SEP14CMM50040 Structural Steel Installation - Muskogee U5 100 23SEP14 11FEB15CMM50050 DFGD Erection and Startup - Muskogee U5 300 29OCT14 28DEC15CMM50060 ID Booster Fan Area Foundations - Muskogee U5 90 10DEC14 16APR15CMM50070 Duckwork Installation - Muskogee U5 150 06FEB15 04SEP15CMM50080 Fabric Filter Erection - Muskogee U5 145 10APR15 30OCT15CMM50090 ID Booster Fan Installation - Muskogee U5 60 01MAY15 24JUL15CMM50100 Electrical Installation - Muskogee U5 160 15MAY15 28DEC15CMM50110 Mechanical Installation - Muskogee U5 140 12JUN15 28DEC15CMM50120 Ductwork Erection ID Fan - Muskogee U5 40 27JUL15 18SEP15

START-UP - MUSKOGEE U5

SUM50010 FGD Commissioning & Start Up - Muskogee U5 140 18JUL15 28DEC15SUM50020 Tie-in Outage - Muskogee U5 37 16NOV15 28DEC15SUM50030 DFGD in Service - Muskogee U5 0 28DEC15SUM50040 DFGD System Balancing / Performance Testing - M5 52 29DEC15 26FEB16

2011 2012 2013 

J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N 

Sheet 4 of 4
Oklahoma Gas & Electric December 28, 2009 

BART Analysis Follow-Up Report (Rev. 1) Project No. 11418-019 

Attachment B 

Annualized Costs 

Sooner Units 1 & 2 

Muskogee Units 4 & 5 
TABLE B-1

MUSKOGEE STATION UNIT 4

BART COST EVALUATION - DRY FGD (SDA) WORKSHEET

INPUT

Case

1 x 572 MW-gross 

PC Boiler

Gross Plant Output (MW-gross) 572

Net Plant Output (MW-net) 527 Adjusted to account for additional auxiliary power.

Approximate Full Load Flue Gas Flow Rate (acfm) 2,288,000

Maximum Heat Input (mmBtu/hr) 5,480

Uncontrolled SO2 Emission Rate (lb/mmBtu) 0.507

Post Dry FGD SO2 Emission Rate (lb/mmBtu) 0.10

Capacity Factor used for Cost Estimates (%) 90%

CAPITAL COSTS Basis

Direct Costs $167,572,100

Indirect Costs $24,801,000

Contingency $31,552,100

Total Plant Cost $223,925,200

Escalation $31,638,600

Allow. for Funds Used During Constr. (AFUDC) $61,629,800

Total Plant Investment (TPI) $317,193,600

 Replacement Power Costs $0

Total Capital Requirement (TCR) $317,193,600

Total Capital Investment ($/kW - gross) $555

Capital Recovery Factor 0.1036 See derivation in Table 5.

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $32,861,300

OPERATING COSTS Basis

Operating & Maintenance Costs

 Variable O&M Costs

Lime Reagent Cost $1,730,600 105.53 $ 

Based on maximum heat input, SO2 removal rate (lb/hr), 0.90 stoichiometry, 

90% CaO, 90% capacity factor, and $105.53/ton for lime.

Water Cost $534,100 2.57 $ Based on 219,839 lb/hr at full load, 90% capacity factor, and $2.57/1000 gal

FGD Waste Disposal Cost $1,894,300 40.59 $ 

Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity factor, 

and $40.59/ton on-site disposal cost. Disposal cost only includes FGD byproducts and does not include fly ash.

Bag and Cage Replacement Costs $675,100 3.31 $ 

Based on the exhaust gas flow through the baghouse, air-to-cloth ratio of 3.5 

for pulse jet baghouse, $3.31/ft2 bag cost (including fabric and hangers), 4% 

contingency for bag cleaning, and 3 year bag life.

Ash Disposal Costs $0 40.59 $ 

Assumed no increase in ash disposal with the fabric filter compared to the 

existing ESP control system. 

Auxiliary Power Cost $5,812,000 85.92 $ 

Based on auxiliary power requirement of 1% (gross) for DFGD plus 0.5% 

(gross) for the baghouse, 90% capacity factor, and $85.92/MWh.

 Total Variable O&M Costs $10,646,100

 Fixed O&M Costs

Additional Operators per shift 2.0 Based on S&L O&M estimate for dry FGD.

Operating Labor $1,029,500 58.76 $ 3 shifts/day, 365 days/year @ 58.76/hour (salary + benefits) .

Supervisor Labor $154,400 15.0% of operating labor. EPA Control Cost Manual, page 2-31

Maintenance Materials $1,903,200 0.6% Based on S&L experience on other FGD projects.

Maintenance Labor $1,132,500 110.0% of operating labor. EPA Control Cost Manual, page 2-31

 Total Fixed O&M Cost $4,219,600

Indirect Operating Cost

Property Taxes $2,696,100 0.85%

Insurance $33,200 0.0105%

Administration $843,900 20%

 Total Indirect Operating Cost $3,573,200

Total Annual Operating Cost $18,438,900

TOTAL ANNUAL COST

Annualized Capital Cost $32,861,300

Annual Operating Cost $18,438,900

 Total Annual Cost $51,300,200

Muskogee Unit 4

Based on Sargent & Lundy's conceptual cost estimating system. Direct costs 

include equipment, material, and labor; plus spare parts, special tools, 

consumables, and freight. Indirect costs include engineering, procurement, 

construction management, start-up, commissioning, operator training, and 

owner's costs.

Escalation and AFUDC were calculated from the estimated distribution of cash 

flows during the construction period and OG&E's before-tax weighted average 

cost of capital of 8.66%/year. The 37-day tie-in outage for each unit is 

assumed to be coordinated with the normal 5-week scheduled outage such that 

incremental replacement cost is negligible.

Calculated as % of total capital investment (EPA Air Pollution Control Cost 

Manual 6th Ed., page 2-34). Administrative costs are 20% of Fixed O&M 

based on S&L experience on other projects.
TABLE B-2

MUSKOGEE STATION UNIT 5

BART COST EVALUATION - DRY FGD (SDA) WORKSHEET

INPUT

Case

1 x 572 MW-gross 

PC Boiler

Gross Plant Output (MW-gross) 572

Net Plant Output (MW-net) 527 Adjusted to account for additional auxiliary power.

Approximate Full Load Flue Gas Flow Rate (acfm) 2,288,000

Maximum Heat Input (mmBtu/hr) 5,480

Uncontrolled SO2 Emission Rate (lb/mmBtu) 0.514

Post Dry FGD SO2 Emission Rate (lb/mmBtu) 0.10

Capacity Factor used for Cost Estimates (%) 90%

CAPITAL COSTS Basis

Direct Costs $167,572,100

Indirect Costs $24,801,000

Contingency $31,552,100

Total Plant Cost $223,925,200

Escalation $31,638,600

Allow. for Funds Used During Constr. (AFUDC) $61,629,800

Total Plant Investment (TPI) $317,193,600

 Replacement Power Costs $0

Total Capital Requirement (TCR) $317,193,600

Total Capital Investment ($/kW - gross) $555

Capital Recovery Factor 0.1036 See derivation in Table 5.

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $32,861,300

OPERATING COSTS Basis

Operating & Maintenance Costs

 Variable O&M Costs

Lime Reagent Cost $1,730,600 105.53 $ 

Based on maximum heat input, SO2 removal rate (lb/hr), 0.90 stoichiometry, 

90% CaO, 90% capacity factor, and $105.53/ton for lime.

Water Cost $534,100 2.57 $ Based on 219,839 lb/hr at full load, 90% capacity factor, and $2.57/1000 gal

FGD Waste Disposal Cost $1,894,300 40.59 $ 

Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity factor, 

and $40.59/ton on-site disposal cost. Disposal cost only includes FGD byproducts and does not include fly ash.

Bag and Cage Replacement Costs $675,100 3.31 $ 

Based on the exhaust gas flow through the baghouse, air-to-cloth ratio of 3.5 

for pulse jet baghouse, $3.31/ft2 bag cost (including fabric and hangers), 4% 

contingency for bag cleaning, and 3 year bag life.

Ash Disposal Costs $0 40.59

Assumed no increase in ash disposal with the fabric filter compared to the 

existing ESP control system. 

Auxiliary Power Cost $5,812,000 85.92 $ 

Based on auxiliary power requirement of 1% (gross) for DFGD plus 0.5% 

(gross) for the baghouse, 90% capacity factor, and $85.92/MWh.

 Total Variable O&M Costs $10,646,100

 Fixed O&M Costs

Additional Operators per shift 2.0 Based on S&L O&M estimate for dry FGD.

Operating Labor $1,029,500 58.76 $ 3 shifts/day, 365 days/year @ 58.76/hour (salary + benefits) .

Supervisor Labor $154,400 15.0% of operating labor. EPA Control Cost Manual, page 2-31

Maintenance Materials $1,903,200 0.6% Based on S&L experience on other FGD projects.

Maintenance Labor $1,132,500 110.0% of operating labor. EPA Control Cost Manual, page 2-31

 Total Fixed O&M Cost $4,219,600

Indirect Operating Cost

Property Taxes $2,696,100 0.85%

Insurance $33,200 0.0105%

Administration $843,900 20%

 Total Indirect Operating Cost $3,573,200

Total Annual Operating Cost $18,438,900

TOTAL ANNUAL COST

Annualized Capital Cost $32,861,300

Annual Operating Cost $18,438,900

 Total Annual Cost $51,300,200

Muskogee Unit 5

Based on Sargent & Lundy's conceptual cost estimating system. Direct costs 

include equipment, material, and labor; plus spare parts, special tools, 

consumables, and freight. Indirect costs include engineering, procurement, 

construction management, start-up, commissioning, operator training, and 

owner's costs.

Escalation and AFUDC were calculated from the estimated distribution of cash 

flows during the construction period and OG&E's before-tax weighted average 

cost of capital of 8.66%/year. The 37-day tie-in outage for each unit is 

assumed to be coordinated with the normal 5-week scheduled outage such that 

incremental replacement cost is negligible.

Calculated as % of total capital investment (EPA Air Pollution Control Cost 

Manual 6th Ed., page 2-34). Administrative costs are 20% of Fixed O&M 

based on S&L experience on other projects.
TABLE B-3

SOONER STATION UNIT 1

BART COST EVALUATION - DRY FGD (SDA) WORKSHEET

INPUT

Case

1 x 569 MW-gross 

PC Boiler

Gross Plant Output (MW-gross) 569

Net Plant Output (MW-net) 524 Adjusted to account for additional auxiliary power.

Approximate Full Load Flue Gas Flow Rate (acfm) 2,276,000

Maximum Heat Input (mmBtu/hr) 5,116

Uncontrolled SO2 Emission Rate (lb/mmBtu) 0.509

Post Dry FGD SO2 Emission Rate (lb/mmBtu) 0.10

Capacity Factor used for Cost Estimates (%) 90%

CAPITAL COSTS Basis

Direct Costs $162,651,300

Indirect Costs $24,045,100

Contingency $29,336,700

Total Plant Cost $216,033,100

Escalation $23,301,500

Allow. for Funds Used During Constr. (AFUDC) $52,960,300

Total Plant Investment (TPI) $292,294,900

 Replacement Power Costs $0

Total Capital Requirement (TCR) $292,294,900

Total Capital Investment ($/kW - gross) $514

Capital Recovery Factor 0.1036 See derivation in Table 5.

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $30,281,800

OPERATING COSTS Basis

Operating & Maintenance Costs

 Variable O&M Costs

Lime Reagent Cost $1,826,900 118.80 $ 

Based on maximum heat input, SO2 removal rate (lb/hr), 0.90 stoichiometry, 

90% CaO, 90% capacity factor, and $118.80/ton for lime.

Water Cost $95,100 0.49 $ Based on 205,256 lb/hr at full load, 90% capacity factor, and $0.49/1000 gal

FGD Waste Disposal Cost $1,733,500 39.60 $ 

Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity factor, 

and $39.60/ton on-site disposal cost. Disposal cost only includes FGD byproducts and does not include fly ash.

Bag and Cage Replacement Costs $653,300 3.22 $ 

Based on the exhaust gas flow through the baghouse, air-to-cloth ratio of 3.5 

for pulse jet baghouse, $3.22/ft2 bag cost (including fabric and hangers), 4% 

contingency for bag cleaning, and 3 year bag life.

Ash Disposal Costs $0 39.60 $ 

Assumed no increase in ash disposal with the fabric filter compared to the 

existing ESP control system. 

Auxiliary Power Cost $5,640,900 83.83 $ 

Based on auxiliary power requirement of 1% (gross) for DFGD plus 0.5% 

(gross) for the baghouse, 90% capacity factor, and $83.83/MWh.

 Total Variable O&M Costs $9,949,700

 Fixed O&M Costs

Additional Operators per shift 2.0 2 Based on S&L O&M estimate for dry FGD.

Operating Labor $1,004,400 57.33 $ 3 shifts/day, 365 days/year @ 57.33/hour (salary + benefits) .

Supervisor Labor $150,700 15.0% of operating labor. EPA Control Cost Manual, page 2-31

Maintenance Materials $1,753,800 0.6% Based on S&L experience on other FGD projects.

Maintenance Labor $1,104,800 110.0% of operating labor. EPA Control Cost Manual, page 2-31

 Total Fixed O&M Cost $4,013,700

Indirect Operating Cost

Property Taxes $1,753,800 0.60%

Insurance $30,600 0.0105%

Administration $802,700 20%

 Total Indirect Operating Cost $2,587,100

Total Annual Operating Cost $16,550,500

TOTAL ANNUAL COST

Annualized Capital Cost $30,281,800

Annual Operating Cost $16,550,500

 Total Annual Cost $46,832,300

Sooner Unit 1 

Based on Sargent & Lundy's conceptual cost estimating system. Direct costs 

include equipment, material, and labor; plus spare parts, special tools, 

consumables, and freight. Indirect costs include engineering, procurement, 

construction management, start-up, commissioning, operator training, and 

owner's costs.

Escalation and AFUDC were calculated from the estimated distribution of cash 

flows during the construction period and OG&E's before-tax weighted average 

cost of capital of 8.66%/year. The 37-day tie-in outage for each unit is 

assumed to be coordinated with the normal 5-week scheduled outage such that 

incremental replacement cost is negligible.

Calculated as % of total capital investment (EPA Air Pollution Control Cost 

Manual 6th Ed., page 2-34). Administrative costs are 20% of Fixed O&M 

based on S&L experience on other projects.
TABLE B-4

SOONER STATION UNIT 2

BART COST EVALUATION - DRY FGD (SDA) WORKSHEET

INPUT

Case

1 x 569 MW-gross 

PC Boiler

Gross Plant Output (MW-gross) 569

Net Plant Output (MW-net) 524 Adjusted to account for additional auxiliary power.

Approximate Full Load Flue Gas Flow Rate (acfm) 2,276,000

Maximum Heat Input (mmBtu/hr) 5,116

Uncontrolled SO2 Emission Rate (lb/mmBtu) 0.516

Post Dry FGD SO2 Emission Rate (lb/mmBtu) 0.10

Capacity Factor used for Cost Estimates (%) 90%

CAPITAL COSTS Basis

Direct Costs $162,651,300

Indirect Costs $24,045,100

Contingency $29,336,700

Total Plant Cost $216,033,100

Escalation $23,301,500

Allow. for Funds Used During Constr. (AFUDC) $52,960,300

Total Plant Investment (TPI) $292,294,900

 Replacement Power Costs $0

Total Capital Requirement (TCR) $292,294,900

Total Capital Investment ($/kW - gross) $514

Capital Recovery Factor 0.1036 See derivation in Table 5.

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $30,281,800

OPERATING COSTS Basis

Operating & Maintenance Costs

 Variable O&M Costs

Lime Reagent Cost $1,826,900 118.80 $ 

Based on maximum heat input, SO2 removal rate (lb/hr), 0.90 stoichiometry, 

90% CaO, 90% capacity factor, and $118.80/ton for lime.

Water Cost $95,100 0.49 $ Based on 205,256 lb/hr at full load, 90% capacity factor, and $0.49/1000 gal

FGD Waste Disposal Cost $1,733,500 39.60 $ 

Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity factor, 

and $39.60/ton on-site disposal cost. Disposal cost only includes FGD byproducts and does not include fly ash.

Bag and Cage Replacement Costs $653,300 3.22 $ 

Based on the exhaust gas flow through the baghouse, air-to-cloth ratio of 3.5 

for pulse jet baghouse, $3.22/ft2 bag cost (including fabric and hangers), 4% 

contingency for bag cleaning, and 3 year bag life.

Ash Disposal Costs $0 39.60 $ 

Assumed no increase in ash disposal with the fabric filter compared to the 

existing ESP control system. 

Auxiliary Power Cost $5,640,900 83.83 $ 

Based on auxiliary power requirement of 1% (gross) for DFGD plus 0.5% 

(gross) for the baghouse, 90% capacity factor, and $83.83/MWh.

 Total Variable O&M Costs $9,949,700

 Fixed O&M Costs

Additional Operators per shift 2.0 2 Based on S&L O&M estimate for dry FGD.

Operating Labor $1,004,400 57.33 $ 3 shifts/day, 365 days/year @ 57.33/hour (salary + benefits) .

Supervisor Labor $150,700 15.0% of operating labor. EPA Control Cost Manual, page 2-31

Maintenance Materials $1,753,800 0.6% Based on S&L experience on other FGD projects.

Maintenance Labor $1,104,800 110.0% of operating labor. EPA Control Cost Manual, page 2-31

 Total Fixed O&M Cost $4,013,700

Indirect Operating Cost

Property Taxes $1,753,800 0.60%

Insurance $30,600 0.0105%

Administration $802,700 20%

 Total Indirect Operating Cost $2,587,100

Total Annual Operating Cost $16,550,500

TOTAL ANNUAL COST

Annualized Capital Cost $30,281,800

Annual Operating Cost $16,550,500

 Total Annual Cost $46,832,300

Sooner Unit 2

Based on Sargent & Lundy's conceptual cost estimating system. Direct costs 

include equipment, material, and labor; plus spare parts, special tools, 

consumables, and freight. Indirect costs include engineering, procurement, 

construction management, start-up, commissioning, operator training, and 

owner's costs.

Escalation and AFUDC were calculated from the estimated distribution of cash 

flows during the construction period and OG&E's before-tax weighted average 

cost of capital of 8.66%/year. The 37-day tie-in outage for each unit is 

assumed to be coordinated with the normal 5-week scheduled outage such that 

incremental replacement cost is negligible.

Calculated as % of total capital investment (EPA Air Pollution Control Cost 

Manual 6th Ed., page 2-34). Administrative costs are 20% of Fixed O&M 

based on S&L experience on other projects.
Table B-5

Annual and Levelized Capital ChargesReal Rates Excluding Inflation

Calendar Year 2014 2015 2016 2017 2018 2019 2020 2021 2022 

Operating Year 1 2 3 4 5 6 7 8 9 Tax Depreciation 5.000% 5.000% 5.000% 5.000% 5.000% 5.000% 5.000% 5.000% 5.000% Debt Balance 44,300,000 42,085,000 39,870,000 37,655,000 35,440,000 33,225,000 31,010,000 28,795,000 26,580,000 Equity Balance 55,700,000 52,915,000 50,130,000 47,345,000 44,560,000 41,775,000 38,990,000 36,205,000 33,420,000 

Levelized Values

Capital Recovery 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 

Debt Return 932,578 1,525,649 1,449,366 1,373,084 1,296,801 1,220,519 1,144,237 1,067,954 991,672 915,389 Equity Return 2,740,413 4,483,171 4,259,012 4,034,854 3,810,695 3,586,537 3,362,378 3,138,220 2,914,061 2,689,902 Income Taxes 1,688,180 2,761,772 2,623,684 2,485,595 2,347,506 2,209,418 2,071,329 1,933,241 1,795,152 1,657,063 

Property Taxes and Insurance 0 000000000Total Capital Charges 10,361,171 13,770,592 13,332,062 12,893,533 12,455,003 12,016,473 11,577,944 11,139,414 10,700,885 10,262,355  Annual Rate (% of initial capital investment) 13.77% 13.33% 12.89% 12.46% 12.02% 11.58% 11.14% 10.70% 10.26%  Levelized Rate 10.36%Income Statement (Check)Revenue Requirements 13,770,592 13,332,062 12,893,533 12,455,003 12,016,473 11,577,944 11,139,414 10,700,885 10,262,355 Property Taxes and Insurance 000000000EBITDA 13,770,592 13,332,062 12,893,533 12,455,003 12,016,473 11,577,944 11,139,414 10,700,885 10,262,355 Depreciation 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 EBIT 8,770,592 8,332,062 7,893,533 7,455,003 7,016,473 6,577,944 6,139,414 5,700,885 5,262,355 Interest 1,525,649 1,449,366 1,373,084 1,296,801 1,220,519 1,144,237 1,067,954 991,672 915,389 EBT 7,244,943 6,882,696 6,520,449 6,158,202 5,795,954 5,433,707 5,071,460 4,709,213 4,346,966 Income Taxes  Cash 2,761,772 2,623,684 2,485,595 2,347,506 2,209,418 2,071,329 1,933,241 1,795,152 1,657,063  Deferred 000000000 Total 2,761,772 2,623,684 2,485,595 2,347,506 2,209,418 2,071,329 1,933,241 1,795,152 1,657,063 Net Income 4,483,171 4,259,012 4,034,854 3,810,695 3,586,537 3,362,378 3,138,220 2,914,061 2,689,902 Equity Return (Check) 4,483,171 4,259,012 4,034,854 3,810,695 3,586,537 3,362,378 3,138,220 2,914,061 2,689,902 Tax Calculations:EBITDA 13,770,592 13,332,062 12,893,533 12,455,003 12,016,473 11,577,944 11,139,414 10,700,885 10,262,355 Tax Depreciation 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 EBIT 8,770,592 8,332,062 7,893,533 7,455,003 7,016,473 6,577,944 6,139,414 5,700,885 5,262,355 Interest 1,525,649 1,449,366 1,373,084 1,296,801 1,220,519 1,144,237 1,067,954 991,672 915,389 EBT 7,244,943 6,882,696 6,520,449 6,158,202 5,795,954 5,433,707 5,071,460 4,709,213 4,346,966 Taxes 2,761,772 2,623,684 2,485,595 2,347,506 2,209,418 2,071,329 1,933,241 1,795,152 1,657,063 Rate Base - Year Begin 100,000,000 95,000,000 90,000,000 85,000,000 80,000,000 75,000,000 70,000,000 65,000,000 60,000,000 Book Depreciation 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 Deferred Taxes 000000000Net Book 95,000,000Rate Base - Year End 95,000,000 90,000,000 85,000,000 80,000,000 75,000,000 70,000,000 65,000,000 60,000,000 55,000,000 
Table B-5

Annual and Levelized Capital ChargesReal Rates Excluding Inflation

Calendar YearOperating Year Tax DepreciationDebt BalanceEquity Balance

Levelized Values

Capital Recovery 5,000,000

Debt Return 932,578Equity Return 2,740,413Income Taxes 1,688,180Property Taxes and Insurance 0Total Capital Charges 10,361,171 Annual Rate (% of initial capital investment) Levelized Rate 10.36%Income Statement (Check)Revenue RequirementsProperty Taxes and Insurance EBITDADepreciationEBITInterestEBTIncome Taxes  Cash Deferred TotalNet IncomeEquity Return (Check)Tax Calculations:EBITDATax DepreciationEBITInterestEBTTaxesRate Base - Year BeginBook DepreciationDeferred TaxesNet BookRate Base - Year End

2026 2027 2028 2029 2030 2031 2032 2033

13 14 15 16 17 18 19 20

5.000% 5.000% 5.000% 5.000% 5.000% 5.000% 5.000% 5.000%

17,720,000 15,505,000 13,290,000 11,075,000 8,860,000 6,645,000 4,430,000 2,215,00022,280,000 19,495,000 16,710,000 13,925,000 11,140,000 8,355,000 5,570,000 2,785,000

5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000

610,260 533,977 457,695 381,412 305,130 228,847 152,565 76,282

1,793,268 1,569,110 1,344,951 1,120,793 896,634 672,476 448,317 224,1591,104,709 966,620 828,532 690,443 552,354 414,266 276,177 138,089

00000000

8,508,237 8,069,707 7,631,178 7,192,648 6,754,118 6,315,589 5,877,059 5,438,530

8.51% 8.07% 7.63% 7.19% 6.75% 6.32% 5.88% 5.44%

8,508,237 8,069,707 7,631,178 7,192,648 6,754,118 6,315,589 5,877,059 5,438,530

00000000

8,508,237 8,069,707 7,631,178 7,192,648 6,754,118 6,315,589 5,877,059 5,438,5305,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,0003,508,237 3,069,707 2,631,178 2,192,648 1,754,118 1,315,589 877,059 438,530

610,260 533,977 457,695 381,412 305,130 228,847 152,565 76,282

2,897,977 2,535,730 2,173,483 1,811,236 1,448,989 1,086,741 724,494 362,2471,104,709 966,620 828,532 690,443 552,354 414,266 276,177 138,089

00000000

1,104,709 966,620 828,532 690,443 552,354 414,266 276,177 138,0891,793,268 1,569,110 1,344,951 1,120,793 896,634 672,476 448,317 224,1591,793,268 1,569,110 1,344,951 1,120,793 896,634 672,476 448,317 224,1598,508,237 8,069,707 7,631,178 7,192,648 6,754,118 6,315,589 5,877,059 5,438,5305,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,0003,508,237 3,069,707 2,631,178 2,192,648 1,754,118 1,315,589 877,059 438,530

610,260 533,977 457,695 381,412 305,130 228,847 152,565 76,282

2,897,977 2,535,730 2,173,483 1,811,236 1,448,989 1,086,741 724,494 362,2471,104,709 966,620 828,532 690,443 552,354 414,266 276,177 138,089

40,000,000 35,000,000 30,000,000 25,000,000 20,000,000 15,000,000 10,000,000 5,000,000

5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000 5,000,000

00000000

35,000,000 30,000,000 25,000,000 20,000,000 15,000,000 10,000,000 5,000,000 0
Oklahoma Gas & Electric December 28, 2009 

BART Analysis Follow-Up Report (Rev. 1) Project No. 11418-019 

Attachment C 

BART Comparison Table 
Oklahoma Gas Electric

Sooner and Muskogee StationsBART Analysis Follow-Up Work

BART Cost Evaluation

SO2 Control

Technology Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGStation MUSKOGEE STATION MUSKOGEE STATION SOONER STATION SOONER STATION GERALD GENTLEMAN GERALD GENTLEMAN WHITE BLUFF WHITE BLUFF BOARDMAN NORTHEASTERN NORTHUnit UNIT 4 UNIT 5 UNIT 1 UNIT 2 UNIT 1 UNIT 2 UNIT 1 UNIT 2 UNIT 1 UNIT 3 UDate December 2009 December 2009 December 2009 December 2009 March 2008 March 2008 August 2008 August 2008 November 2007 May 2008 MRating (gross) MW 572 572 569 569 750 750 850 850 617 493 Rating (net) MW 527 527 524 524 665 700 844 844 584 470 Heat Input: mmBtu/hr 5,480 5,480 5,116 5,116 7,393 7,782 9,339 10,221 5,793 4,775 Capacity Factor % 90% 90% 90% 90% 100% 100% 85% 85% 85% 85% Maximum Hours/year: hours/yr 7,884 7,884 7,884 7,884 8,760 8,760 7,446 7,446 7,446 7,446 Capital Cost Recovery Factor Equipment Life years 20 20 20 20 20 20 40 40 20 20 Interest Rate % 5.43% 5.43% 5.43% 5.43% 5.25% 5.25% 7.67% 7.67% 7% 8% Capital Cost Recovery Factor 0.1036 0.1036 0.1036 0.1036 0.0820 0.0820 0.0809 0.0809 0.0944 0.1019 0Energy Impact % or MW 1.5% 1.5% 1.5% 1.5% 13 MW 13 MW 11.4 MW 11.4 MW 4,088 kW Not specified in BART Not specFuel Subbituminous coal Subbituminous coal Subbituminous coal Subbituminous coal Subbituminous coal Subbituminous coal Subbituminous coal Subbituminous coal Low sulfur PRB Western sub-bituminous Western sFuel Sulfur Content % 0.20 - 0.37 0.20 - 0.37 0.20 - 0.37 0.20 - 0.37 0.7 0.7 0.78 0.73 0.17 - 1.00 0.45 - 0.49 0.4

EMISSIONS

BART Baseline Uncontrolled SO2 Emission Rate lb/mmBtu 0.507 0.514 0.509 0.516 0.749 0.749 0.915 0.854 0.614 0.900 BART Baseline Annual SO2 Emissions ton/year 9,113 9,006 9,394 8,570 24,254 25,531 31,806 32,510 14,902 16,000 1Expected SO2 Emission Rate lb/mmBtu 0.10 0.10 0.10 0.10 0.15 0.15 0.15 0.15 0.15 0.15 

Expected SO2 Emissions ton/year 2,160 2,160 2,017 2,017 4,857 5,113 5,215 5,708 3,643 2,720 

Expected SO2 Emissions Reduction ton/year 6,953 6,846 7,377 6,553 19,397 20,418 26,591 26,802 11,259 13,280 1

SO2 Removal % 80.3% 80.5% 80.4% 80.6% 80.0% 80.0% 83.6% 82.4% 75.6% 83.0% 8

 Visibility Improvement - Sum of Class I Areas Δdv 9.842 

 Visibility Improvement - Single Class I Areas Δdv 0.969 

COSTS

Total Capital Cost Investment $ 317,193,600 317,193,600 292,294,900 292,294,900 486,188,000 495,404,000 353,448,500 353,448,500 247,293,000 273,350,000 273

Capital Cost per kW (gross) $/kw 555 555 514 514 731 708 419 419 401 555 Annual Capital Recovery Costs $/year 32,861,300 32,861,300 30,281,800 30,281,800 38,980,692 41,032,308 51,655,000 51,655,000 23,344,000 27,841,302 27,Annual Operating Costs $/year 18,438,900 18,438,900 16,550,500 16,550,500 13,826,000 13,980,000 13,500,000 13,500,000 12,978,000 15,535,100 15,

Total Annual Costs $/year 51,300,200 51,300,200 46,832,300 46,832,300 53,146,692 55,370,308 65,155,000 65,155,000 36,322,000 43,376,402 43,Average Annual Cost Effectiveness $/ton 7,378 7,493 6,348 7,147 2,740 2,712 2,450 2,431 3,226 3,266 Incremental Impairment Improvement Cost - Sum of Class I Areas $/yr/dv 3,690,510 

Incremental Impairment Improvement Cost - Single Class I Area $/yr/dv 37,484,004 

1.275 1.170 0.641 3.587 1.0504.217 2.440 Not Available Not Available 3.670

169,189,000 82,621,717

24,330,187 38,387,131 Don't have necessary Δdv data Don't have necessary Δdv data 23,638,366

80,470,902 80,055,214 39,260,000

008_Attachment C_OG&E BART Comparison 12-28-09 Page 1 of 2
Oklahoma Gas Electric

Sooner and Muskogee StationsBART Analysis Follow-Up Work

BART Cost Evaluation

SO2 Control

Technology Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGD-SDA/FF Dry FGStation MUSKOGEE STATION MUSKOGEE STATION SOONER STATION SOONER STATION GERALD GENTLEMAN GERALD GENTLEMAN WHITE BLUFF WHITE BLUFF BOARDMAN NORTHEASTERN NORTHUnit UNIT 4 UNIT 5 UNIT 1 UNIT 2 UNIT 1 UNIT 2 UNIT 1 UNIT 2 UNIT 1 UNIT 3 U

ANNUAL COST

O&M Costs - TOTAL 14,865,700 14,865,700 13,963,400 13,963,400 13,826,000 13,980,000 13,500,000 13,500,000 12,978,000 4,601,100 4,6Fixed O&M - TOTAL $/year 4,219,600 4,219,600 4,013,700 4,013,700 3,906,000 3,906,000 3,550,000 3,550,000 4,709,000 0 

Maintenance (Mat + Labor) $/year 3,035,700 3,035,700 2,858,600 2,858,600 2,911,000 2,911,000 Incl. above Incl. above 4,409,000 --- 

Operating (Labor) $/year 1,183,900 1,183,900 1,155,100 1,155,100 995,000 995,000 Incl. above Incl. above 300,000 --- 

Variable O&M - TOTAL $/year 10,646,100 10,646,100 9,949,700 9,949,700 9,920,000 10,074,000 9,950,000 9,950,000 8,269,000 4,601,100 4,6

Lime $/year 1,730,600 1,730,600 1,826,900 1,826,900 7,316,000 7,420,000 Incl. above Incl. above 4,915,000 3,090,000 3,0

Water $/year 534,100 534,100 95,100 95,100 483,000 499,000 Incl. above Incl. above 300,000 --- Solid FGD Waste $/year 1,894,300 1,894,300 1,733,500 1,733,500 1,620,000 1,643,000 Incl. above Incl. above 742,000 --- Fly Ash Disposal $/year 0 0 0 0 --- --- --- --- --- --- Bags and Cages $/year 675,100 675,100 653,300 653,300 --- --- Incl. above Incl. above 790,000 --- 

Sales of Allowances $/year 0000 -4,755,000 -4,744,000 --- --- --- --- Auxiliary Power $/year 5,812,000 5,812,000 5,640,900 5,640,900 5,256,000 5,256,000 Incl. above Incl. above 1,522,000 1,511,100 1,5

Extended Outage Power Purc. $/year 0000 340,000 358,000 0000

Indirect Costs $/year 3,573,200 3,573,200 2,587,100 2,587,100 00000 10,934,000 10,

Property Taxes $/year 2,696,100 2,696,100 1,753,800 1,753,800 --- --- --- --- --- 2,733,500 2,7Insurance $/year 33,200 33,200 30,600 30,600 --- --- --- --- --- 2,733,500 2,7Administration $/year 843,900 843,900 802,700 802,700 --- --- --- --- --- 5,467,000 5,4

Fixed Charges on Investment $/year 32,861,300 32,861,300 30,281,800 30,281,800 38,980,692 41,032,308 51,655,000 51,655,000 23,344,000 27,841,302 27,

Annual Cost $/year 51,300,200 51,300,200 46,832,300 46,832,300 53,146,692 55,370,308 65,155,000 65,155,000 36,322,000 43,376,402 43,

008_Attachment C_OG&E BART Comparison 12-28-09 Page 2 of 2