4. DEVELOPMENTAL ANALYSIS 

In this section, we look at the Catawba-Wateree Project’s use of the Catawba and 

Wateree Rivers for hydropower purposes to see what effect various environmental measures 

would have on the project’s costs and power benefits. Consistent with the Commission’s 

approach to economic analysis, the power benefit of the project is determined by estimating the 

cost of obtaining the same amount of energy and capacity using the likely alternative generating 

resources available in the region. In keeping with Commission policy as described in Mead, our 

economic analysis is based on current electric power cost conditions and does not consider future 

escalation of fuel prices in valuing the hydropower project’s power benefits.19 

Our analysis includes: (1) an estimate of the net power benefit of the project for each of 

the licensing alternatives; and (2) an estimate of the cost of individual measures considered in the 

EIS for the protection, mitigation, and enhancement of environmental resources affected by the 

project. To determine the net power benefit for each of the licensing alternatives, we compare 

project costs to the value of the power output as represented by the cost of a likely alternative 

source of power in the region. For any alternative, a positive net annual power benefit indicates 

that the project power costs less than the current cost of alternative generation resources, and a 

negative net annual benefit indicates that project power costs more than the current cost of 

alternative generation resources. This estimate helps to support an informed decision concerning 

what is in the public interest with respect to a proposed license. However, project economics is 

only one of many public interest factors the Commission considers in determining whether, and 

under what conditions, to issue a license. 

4.1 POWER AND ECONOMIC BENEFITS OF THE BRIDGEWATER 

DEVELOPMENT 

Table 96 summarizes the assumptions and economic information we use in our analysis. 

This information was provided by Duke Energy in its license application. We find that the 

values provided by Duke Energy are reasonable for the purposes of our analysis. Cost items 

common to all alternatives include: taxes and insurance costs; net investment (the total 

investment in power plant facilities remaining to be depreciated); estimated future capital 

investment required to maintain and extend the life of plant equipment and facilities; relicensing 

costs; normal operation and maintenance cost; and Commission fees. All dollars are year 2008 

unless specified otherwise. 

 19 See Mead Corporation, Publishing Paper Division, 72 FERC ¶ 61,027 (July 13, 1995). 

In most cases, electricity from hydropower would displace some form of fossil-fueled 

generation, in which fuel cost is the largest component of the cost of electricity production. 

371 
Table 96 Staff assumptions for the economic analysis of the Bridgewater Development. 

Parameter Value 

Period of analysis (years) 30 

Local Tax Rate (%)1 3.0 

Federal tax rate (%)2 32 

Insurance Rate (%)3 0.25 

Net investment(2008$)4 72,447,768 

Future major capital cost5 22,670,930 

Relicensing cost (2008$)6 1,763,780 

Operation and maintenance (2008$)7 638,083 

Energy value (2008$/MWh)8 43.30 

Capacity value (2008$/kW-year)9 30.12 

Cost of Capital (%)10 8.5 

Discount rate (%)11 8.5 

1 Staff assumed a local tax rate of 3.0 percent. 

2 Staff assumed federal tax rate at 32 percent revenues. 

3 Staff assumed insurance rate equal to 0.25 percent of net investment. 

4 Net investment is the depreciated project investment allocated to power purposes and 

includes $2,344,786 (2008$) net plant investment for the existing facilities and $65,100,000 

(2006$) for the new powerhouse as reported by Duke Energy in exhibit D. 

5 Future major capital costs include implementation of measures to maintain present-day 

capability scheduled between 2008 and 2039 and are expressed as a present value. 

6 Relicensing costs include the administrative, legal/study, and other expenses to date. Staff 

has assumed total project relicensing cost $31,800,000 (2006$) is prorated by the average annual 

energy generation per project to determine the relicensing cost for each project. The Staff 

assumed relicensing cost for the Bridgewater Development in 2006$ is $1,637,906. 

7 Annual plant operation and maintenance costs reported by Duke are $554,941 (2006$).

8 Source: application for new license, exhibit D, page D-27, $40.21/MWh in 2006$. 

9 Source: application for new license, exhibit D, page D-27, $27.97/kW-year in 2006$. 

10 Based on Duke Energy’s weighted average cost of capital. Source: application for new 

license, exhibit D. 

11 Assumed by staff to be same as interest rate. 

Note: Staff escalated all 2006 values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent 

(12/31/06 to 12/31/07), and 2.3 percent (12/31/07 to 12/31/08) per year, respectively. The 

escalation rates were reported by the Department of Energy’s Cost Engineering Group 

(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Vari

ous%20Years.xls) 

372 
As currently operated, the 27.7-MW Bridgewater Development generates an average of 

74,250 MWh annually and has a dependable capacity of 25.8 MW. 

4.1.1 Comparison of Alternatives 

Table 97 summarizes the annual cost, power benefit, and annual net benefit for the three 

alternatives considered in this DEIS: no-action alternative, Duke Energy’s proposal, and the 

staff-recommended alternative. The power benefit in Table 97 is the combined annual value of 

the energy generation and capacity value for the Bridgewater Development. 

Table 97 Summary of the annual cost, power benefits, and annual net benefits for the three 

alternatives for the Bridgewater Development (Source: Staff). 

No action Duke Energy’s 

Proposal 

Staff-recommended 

alternative 

Installed capacity (MW) 27.7 27.7 27.7 

Annual generation (thousand 

MWh) 74.25 66.08 66.08 

Annual power value, 2008$: 

(mills/kWh): 

3,992,121 

(53.77) 

3,638,360 

(55.06) 

3,638,360 

(55.06) 

Annual cost, 2008$: 

(mills/kWh): 

7,833,257 

(105.50) 

9,849,563 

(149.06) 

9,780,844 

(148.02) 

Annual net benefit, 2008$ 

(mills/kWh): 

-3,841,136 

(-51.73) 

-6,211,203 

(-94.00) 

-6,142,484 

(-92.96) 

4.1.1.1 No-Action Alternative 

Under the no-action alternative, Duke Energy would continue to operate the project under 

the terms and conditions of the existing license, and no new environmental protection, 

mitigation, or enhancement measures would be implemented. 

Based on the above information and an average annual generation of 74,250 MWh, 

the existing project has an annual power value of $3,992,121 and costs $7,833,257 annually 

to operate and maintain. This results in a net annual benefit of negative $3,841,136 (or 

-$51.73/MWh). In other words, the project produces energy at a cost that is greater than that 

of currently available alternative generation by $3,841,136 annually.

4.1.1.2 Applicant’s Proposal 

In its license application and CRA, filed on December 22, 2007, Duke Energy proposes 

numerous operational and non-operational measures. 

As proposed by Duke Energy, the Bridgewater Development would generate an 

average of 66,080 MWh of electricity annually, have an annual power value of $3,638,360 

(55.06 mills/kWh), and total annual costs of $9,849,563 (149.06 mills/kWh). This results in a 

net annual benefit of negative $6,211,203 (-94.00 mills/kWh). In other words, the project 

373 
374 

produces energy at a cost that is greater than that of currently available alternative generation by 

$6,211,203 annually.

4.1.1.3 Staff Alternative 

Resource agencies and nongovernmental organizations recommended the implementation 

of a variety of measures at the project. Staff reviewed each recommendation and determined 

which measures were the most appropriate for implementation. In section 5.0, Comprehensive 

Development and Recommended Alternative, we discuss our reasons for recommending the staff 

alternative and why we conclude that the environmental benefits are worth these costs. Table 98 

list these proposed measures and identifies the ones that were adopted by staff. 

The staff alternative would generate an average of 66,080 MWh of electricity annually, 

have an annual power value of $3,638,360 (55.06 mills/kWh) and have total annual costs of 

$9,780,844 (148.02 mills/kWh). This results in an annual net benefit of negative $6,142,484 

(-92.96 mills/kWh). In other words, the project produces energy at a cost that is greater than that 

of currently available alternative generation by $6,142,484 annually. The staff alternative would 

increase the net annual project benefit by about $68,719 ($1.04/MWh) compared to the project as 

proposed by Duke Energy. 

4.1.2 Cost of Environmental Measures 

Table 98 gives the cost of each of the environmental enhancement measures considered 

in our analysis. We convert all costs to equal annual (levelized) values over a 30-year period to 

give a uniform basis for comparing the benefits of a measure to its cost. All costs were adjusted 

from 2006$ to 2008$.
Table 98 Summary of capital, annual O&M, and annualized costs for environmental measures proposed by Du

by staff for the Bridgewater Development for a 30-year license. (Source: Staff) 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(

C

Operations

Reservoir Level Control – Install flow compliance gage and provide maintenance 

Duke Energy 108,000 9,974 11,000 

Reservoir Level Stabilization (Spring Lake Stabilization) 

Duke Energy 0 0 1,000 

Drought Mitigation – Low inflow protocol administration 

Duke Energy 0 0 2,000 

Drought Mitigation – Water Management Group Dues 

Duke Energy 0 0 14,000 

Maintenance and Emergency Protocol Duke Energy 0 0 1,000 

Flow and Reservoir Elevation Monitoring – USGS gage installation and maintenance 

Duke Energy 21,000 1,939 30,000 

Water Quality and Quantity

Monitoring and Compliance – Installation and maintenance of DO and groundwater monitors 

Duke Energy 108,000 9,974 55,000 

Water Quality Enhancements-Minimum flow units and aeration on 3 units 

Duke Energy 5,400,000 498,699 12,000 

1 Staff escalated those values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent (12/31/06 to 12/31/07), and 2

12/31/08) per year, respectively. The escalation rates were reported by the Department of Energy’s Cost Engineerin(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Various%20Years.xls).

375 
Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(

C

Aquatic Habitat Flows-Bypass Flow Valve Duke Energy 1,134,000 104,727 25,000 Flow Mitigation – Conservation Easements Duke Energy 643,000 59,383 0 

Fish, Wildlife, and Botanical Resources

Species Protection Plans Duke Energy 10,000 924 6,000 Habitat Enhancement Fund Duke Energy 167,000 15,422 0 

Terrestrial Invasive Plant Species Management Plan 

Staff 3,000 277 150 

Cultural Resources

Historic Properties Management Plan – Annual HPMP review, signs, website, and materials 

Duke Energy 9,000 831 1,000 

Recreational Resources

Recreation Management Plan Development Duke Energy 91,000 8,404 1,000 Recreation Use and Needs Update Duke Energy 45,000 4,156 0 

Recreation Enhancements Duke Energy 2,779,000 256,646 65,000 

Recreation Enhancements Duke Energy 9,360,000 864,412 125,000 

Recreation Enhancements Duke Energy 113,000 10,435 9,000 

Recreation Enhancements Staff 4,500 416 0 

Public Information

Recreation Flow Communication – Develop and Maintain Systems 

Duke Energy 20,000 1,847 5,000 

376 
377 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(

C

Safety and Security – Signage and Warning Device 

Duke Energy 80,000 7,388 1,000 

Safety and Security – Revise and implement safety plans 

Staff 98,500 9,097 1,000 

Shoreline Management

Shoreline Management Plan Updates (every 10 years) 

Duke Energy 26,000 2,401 0 

Shoreline Management Guidelines Updates (every 10 years) 

Duke Energy 8,000 738 0 

Other EnhancementsLand Conservation Support Duke Energy 667,000 61,599 0 Trash Management/Safety Duke Energy 14,000 1,293 4,000 

Funding for Conservation Easements Duke Energy 250,000 23,088 0 
4.2 POWER AND ECONOMIC BENEFITS OF THE RHODHISS DEVELOPMENT 

Table 99 summarizes the assumptions and economic information we use in our analysis. 

This information was provided by Duke Energy in its license application. We find that the 

values provided by Duke Energy are reasonable for the purposes of our analysis. Cost items 

common to all alternatives include: taxes and insurance costs; net investment (the total 

investment in power plant facilities remaining to be depreciated); relicensing costs; normal 

operation and maintenance cost; and Commission fees. All dollars are year 2008 unless 

specified otherwise. 

Table 99 Staff assumptions for the economic analysis of the Rhodhiss Development. 

Parameter Value 

Period of analysis (years) 30 

Local Tax Rate (%)1 3.0 

Federal tax rate (%)2 32 

Insurance Rate (%)3 0.25 

Net investment(2008$)4 14,515,721 

Future major capital cost5 11,215,390 

Relicensing cost (2008$)6 1,517,376 

Operation and maintenance (2008$/yr)7 427,664 

Energy value (2008$/MWh)8 43.35 

Capacity value (2008$/kW-year)9 28.46 

Cost of Capital (%)10 8.5 

Discount rate (%)11 8.5 

1 Staff assumed a local tax rate of 3.0 percent. 

2 Staff assumed federal tax rate at 32 percent revenues. 

3 Staff assumed insurance rate equal to 0.25 percent of net investment. 

4 Net investment is the depreciated project investment allocated to power purposes and 

includes $15,897,941 (2006$) net plant investment for the existing facilities as reported by Duke 

Energy in exhibit D. 

5 Future major capital costs include implementation of measures to maintain present-day 

capability scheduled between 2008 and 2039 and are expressed as a present value. 

6 Relicensing costs include the administrative, legal/study, and other expenses to date. Staff 

has assumed total project relicensing cost $31,800,000 (2006$) is prorated by the average annual 

energy generation per project to determine the relicensing cost for each project. The Staff 

assumed relicensing cost for the Rhodhiss Development in 2006$ is $1,409,087. 

7 Annual plant operation and maintenance costs reported by Duke are $397,143 (2006$). 

378 
8 Source: application for new license, exhibit D, page D-27, $40.26/MWh in 2006$. 

9 Source: application for new license, exhibit D, page D-27, $26.43/kW-year in 2006$. 

10 Based on Duke Energy’s weighted average cost of capital. Source: application for new 

license, exhibit D. 

11 Assumed by staff to be same as interest rate. 

Note: Staff escalated all 2006 values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent 

(12/31/06 to 12/31/07), and 2.3 percent (12/31/07 to 12/31/08) per year, respectively. The 

escalation rates were reported by the Department of Energy’s Cost Engineering Group. 

As currently operated, the 31.6-MW Rhodhiss Development generates an average of 

63,880 MWh annually and has a dependable capacity of 31.6 MW. 

4.2.1 Comparison of Alternatives 

Table 100 summarizes the annual cost, power benefit, and annual net benefit for the three 

alternatives considered in this DEIS: no-action alternative, Duke Energy’s proposal, and the 

staff-recommended alternative. 

Table 100 Summary of the annual cost, power benefits, and annual net benefits for the three 

alternatives for the Rhodhiss Development (Source: Staff). 

No action Duke Energy’s 

Proposal 

Staff-recommended 

alternative 

Installed capacity (MW) 31.6 31.6 31.6 

Annual generation (thousand 

MWh) 63.88 56.85 56.85 

Annual power value, 2008$: 

(mills/kWh): 

3,668,534 

(57.43) 

3,363,784 

(59.17) 

3,363,784 

(59.17) 

Annual cost, 2008$: 

(mills/kWh): 

2,793,298 

(43.73) 

3,743,443 

(65.85) 

3,588,482 

(62.59) 

Annual net benefit, 2008$: 

(mills/kWh): 

875,236 

(13.70) 

-379,660 

(-6.68) 

-194,698 

(-3.42) 

4.2.1.1 No-Action Alternative 

Under the no-action alternative, Duke Energy would continue to operate the project under 

the terms and conditions of the existing license, and no new environmental protection, 

mitigation, or enhancement measures would be implemented. 

Based on the above information and an average annual generation of 63,880 MWh, the 

existing project has an annual power value of $3,668,534 and costs $2,793,298 annually to 

operate and maintain. This results in a net annual benefit of $875,236 (or $13.70/MWh). In 

379 
380 

other words, the project produces energy at a cost that is less than that of currently available 

alternative generation by $875,236 annually. 

4.2.1.2 Applicant’s Proposal 

In its license application and CRA, filed on December 22, 2007, Duke Energy proposes 

numerous operational and non-operational measures. 

As proposed by Duke Energy, the Rhodhiss Development would generate an 

average of 56,850 MWh of electricity annually, have an annual power value of $3,363,748 

(59.17 mills/kWh), and total annual costs of $3,743,443 (65.85 mills/kWh), resulting in a 

negative net annual benefit of $379,660 (-6.68 mills/kWh). In other words, the project produces 

energy at a cost that is more than that of currently available alternative generation by $379,660 

annually.

4.2.1.3 Staff Alternative 

Resource agencies and nongovernmental organizations recommended the implementation 

of a variety of measures at the project. Staff reviewed each recommendation and determined 

which measures were the most appropriate for implementation. In section 5.0, Comprehensive 

Development and Recommended Alternative, we discuss our reasons for recommending the staff 

alternative and why we conclude that the environmental benefits are worth these costs. 

Table 101 list these proposed measures and identifies the ones that were adopted by staff. 

The staff alternative would generate an average of 56,850 MWh of electricity annually, 

have an annual power value of $3,363,784 (59.17 mills/kWh), and have total annual costs of 

$3,588,482 (62.59 mills/kWh). This results in a annual net benefit of negative $194,698 

(-3.42 mills/kWh). In other words, the project produces energy at a cost that is greater than that 

of currently available alternative generation by $194,698 annually. The staff alternative would 

reduce the net annual project benefit by about $184,962 ($3.26/MWh) compared to the project as 

proposed by Duke Energy. 

4.2.2 Cost of Environmental Measures 

Table 101 gives the cost of each of the environmental enhancement measures considered 

in our analysis. We convert all costs to equal annual (levilized) values over a 30-year period to 

give a uniform basis for comparing the benefits of a measure to its cost. All costs were adjusted 

from 2006$ to 2008$. 
Table 101 Summary of capital, annual O&M, and annualized costs for environmental measures proposed by Du

by Staff for the Rhodhiss Development for a 30-year license. (Source: Staff) 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

co

OperationsDrought Mitigation – Low inflow protocol administration 

Duke Energy 0 0 2,000 

Drought Mitigation – Water Management Group Dues 

Duke Energy 0 0 14,000 

Maintenance and Emergency Protocol Duke Energy 0 0 1,000 

Water Quality and Quantity

Monitoring and Compliance – Installation and maintenance of DO and groundwater monitors 

Duke Energy 108,000 9,974 55,000 

Water Quality Enhancement – new aerating runner 

Duke Energy 2,876,000 265,603 12,000 

Fish, Wildlife, and Botanical ResourcesSpecies Protection Plans Duke Energy 7,000 647 5,000 Habitat Enhancement Fund Duke Energy 167,000 15,422 0 

Terrestrial Invasive Plant Species Management Plan 

Staff 3,000 277 150 

1 Staff escalated those values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent (12/31/06 to 12/31/07), and 2

12/31/08) per year, respectively. The escalation rates were reported by the Department of Energy’s Cost Engineerin(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Various%20Years.xls).

381 
Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

co

Cultural Resources

Historic Properties Management Plan – Annual HPMP review, signs, website, and materials 

Duke Energy 9,000 831 1,000 

Recreational ResourcesRecreation Management Plan Development Duke Energy 91,000 8,404 1,000 Recreation Use and Needs Update Duke Energy 45,000 4,156 0 

Recreation Enhancements Duke Energy 2,041,000 188,490 77,000 

Recreation Enhancements Duke Energy 2,971,000 274,377 0 

Recreation Enhancements Staff 4,500 416 0 Public Information

Safety and Security – Signage Duke Energy 10,000 924 1,000 Safety and Security – Revise and implement safety plans 

Staff 28,500 2,632 1,000 

Shoreline ManagementShoreline Management Plan Updates (every 10 years) 

Duke Energy 26,000 2,401 0 

Shoreline Management Guidelines Updates (every 10 years) 

Duke Energy 8,000 738 0 

Other EnhancementsLand Conservation Support Duke Energy 667,000 61,599 0 Trash Management/Safety Duke Energy 14,000 1,293 4,000 

382 
383 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

co

Funding for Conservation Easements Duke Energy 250,000 23,088 0 Conservation Easements Duke Energy 1,125,000 103,896 0 
4.3 POWER AND ECONOMIC BENEFITS OF THE OXFORD DEVELOPMENT 

Table 102 summarizes the assumptions and economic information we use in our analysis. 

This information was provided by Duke Energy in its license application. We find that the 

values provided by Duke Energy are reasonable for the purposes of our analysis. Cost items 

common to all alternatives include: taxes and insurance costs; net investment (the total 

investment in power plant facilities remaining to be depreciated); relicensing costs; normal 

operation and maintenance cost; and Commission fees. All dollars are year 2008 unless 

specified otherwise. 

Table 102 Staff assumptions for the economic analysis of the Oxford Development. 

Parameter Value 

Period of analysis (years) 30 

Local Tax Rate (%)1 3.0 

Federal tax rate (%)2 32 

Insurance Rate (%)3 0.25 

Net investment(2008$)4 28,323,220 

Future major capital cost5 8,201,300 

Relicensing cost (2008$)6 2,471,040 

Operation and maintenance7 439,605 

Energy value (2008$/MWh)8 43.25 

Capacity value (2008$/kW-year)9 36.95 

Cost of Capital (%)10 8.5 

Discount rate (%)11 8.5 

1 Staff assumed a local tax rate of 3.0 percent. 

2 Staff assumed federal tax rate at 32 percent revenues. 

3 Staff assumed insurance rate equal to 0.25 percent of net investment. 

4 Net investment is the depreciated project investment allocated to power purposes and 

includes $30,696,742 (2006$) net plant investment for the existing facilities as reported by Duke 

Energy in exhibit D. 

5 Future major capital costs include implementation of measures to maintain present-day 

capability scheduled between 2008 and 2039 and are expressed as a present value. 

6 Relicensing costs include the administrative, legal/study, and other expenses to date. Staff 

has assumed total project relicensing cost $31,800,000 (2006$) is prorated by the average annual 

energy generation per project to determine the relicensing cost for each project. The Staff 

assumed relicensing cost for the Oxford Development in 2006$ is $2,294,691. 

7 Annual plant operation and maintenance costs reported by Duke are $408,232 (2006$).

8 Source: application for new license, exhibit D, page D-27, $40.16/MWh in 2006$. 

384 
9 Source: application for new license, exhibit D, page D-27, $34.31/kW-year in 2006$. 

10 Based on Duke Energy’s weighted average cost of capital. Source: application for new 

license, exhibit D. 

11 Assumed by staff to be same as interest rate. 

Note: Staff escalated all 2006 values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent 

(12/31/06 to 12/31/07), and 2.3 percent (12/31/07 to 12/31/08) per year, respectively. The 

escalation rates were reported by the Department of Energy’s Cost Engineering Group. 

As currently operated, the 41.6-MW Oxford Development generates an average of 

104,030 MWh annually and has a dependable capacity of 41.6 MW. 

4.3.1 Comparison of Alternatives 

Table 103 summarizes the annual cost, power benefit, and annual net benefit for the three 

alternatives considered in this DEIS: no-action alternative, Duke Energy’s proposal, and the 

staff-recommended alternative. 

Table 103 Summary of the annual cost, power benefits, and annual net benefits for the three 

alternatives for the Oxford Development (Source: Staff). 

No action Duke Energy’s 

Proposal 

Staff-recommended 

alternative 

Installed capacity (MW) 41.6 41.6 41.6 

Annual generation (thousand 

MWh) 104.03 92.58 92.58 

Annual power value, 2008$: 

(mills/kWh): 

6,036,418 

(58.03) 

5,541,205 

(59.85) 

5,541,2050 

(59.85) 

Annual cost, 2008$: 

(mills/kWh): 

4,782,301 

(45.97) 

5,571,041 

(60.18) 

5,512,412 

(59.54) 

Annual net benefit, 2008$: 

(mills/kWh): 

1,254,117 

(12.06) 

-29,836 

(-0.32) 

28,793 

(0.31) 

4.3.1.1 No-Action Alternative 

Under the no-action alternative, Duke Energy would continue to operate the project under 

the terms and conditions of the existing license, and no new environmental protection, 

mitigation, or enhancement measures would be implemented. 

Based on the above information and an average annual generation of 104,030 MWh, the 

existing project has an annual power value of $6,036,418 and costs $4,782,301 annually to 

operate and maintain. This results in a net annual benefit of $1,254,117 (or $12.06 /MWh). In 

385 
386 

other words, the project produces energy at a cost that is less than that of currently available 

alternative generation by $1,254,117 annually. 

4.3.1.2 Applicant’s Proposal 

In its license application and CRA, filed on December 22, 2007, Duke Energy proposes 

numerous operational and non-operational measures. 

As proposed by Duke Energy, the Oxford Development would generate an 

average of 92,580 MWh of electricity annually, have an annual power value of $5,541,205 

(59.85 mills/kWh), and total annual costs of $5,571,041 (60.18 mills/kWh). This results in a net 

annual benefit of negative $29,836 (-0.32 mills/kWh). In other words, the project produces 

energy at a cost that is greater than that of currently available alternative generation by $29,836 

annually.

4.3.1.3 Staff Alternative 

Resource agencies and nongovernmental organizations recommended the implementation 

of a variety of measures at the project. Staff reviewed each recommendation and determined 

which measures were the most appropriate for implementation. In section 5.0, Comprehensive 

Development and Recommended Alternative, we discuss our reasons for recommending the staff 

alternative and why we conclude that the environmental benefits are worth these costs. 

Table 104 list these proposed measures and identifies the ones that were adopted by staff. 

The staff alternative would generate an average of 92,580 MWh of electricity annually, 

have an annual power value of $5,541,205 (59.85 mills/kWh), and have total annual costs of 

$5,512,412 (59.54 mills/kWh), resulting in an annual net benefit of $28,793 (0.31 mills/kWh). 

In other words, the project produces energy at a cost that is less than that of currently available 

alternative generation by $28,793 annually. The staff alternative would increase the net annual 

project benefit by about $56,629 ($0.63/MWh) compared to the project as proposed by Duke 

Energy. 

4.3.2 Cost of Environmental Measures 

Table 104 gives the cost of each of the environmental enhancement measures considered 

in our analysis. We convert all costs to equal annual (levelized) values over a 30-year period to 

give a uniform basis for comparing the benefits of a measure to its cost. All costs were adjusted 

from 2006$ to 2008$.
Table 104 Summary of capital, annual O&M, and annualized costs for environmental measures proposed by Du

by Staff for the Oxford Development for a 30-year license. (Source: Staff) 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

co

OperationsReservoir Level Control – Install flow compliance gage and provide maintenance Duke Energy 108,000 9,974 11,000 Drought Mitigation – Low inflow protocol administration Duke Energy 0 0 2,000 

Drought Mitigation – Water Management Group Dues Duke Energy 0 0 14,000 

Maintenance and Emergency Protocol Duke Energy 0 0 1,000 

Water Quality and Quantity

Monitoring and Compliance – Installation and maintenance of DO and groundwater monitors 

Duke Energy 108,000 9,974 55,000 

Water Quality Enhancement – new aerating runner Duke Energy 2,633,000 243,162 12,000 

Aquatic Habitat Flows – Bypass flow valve installation and maintenance Duke Energy 570,000 52,640 30,000 

Flow Mitigation - Conservation Easements Duke Energy 643,000 59,383 0 

1 Staff escalated those values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent (12/31/06 to 12/31/07), and 2

12/31/08) per year, respectively. The escalation rates were reported by the Department of Energy’s Cost Engineerin(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Various%20Years.xls).

387 
Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

co

Fish, Wildlife, and Botanical Resources

Species Protection Plans Duke Energy 9,000 831 5,000 Habitat Enhancement Fund Duke Energy 167,000 15,422 0 

Terrestrial Invasive Plant Species Management Plan Staff 3,000 277 150 

Cultural Resources

Historic Properties Management Plan – Annual HPMP review, signs, website, and materials 

Duke Energy 9,000 831 1,000 

Recreational ResourcesRecreation Management Plan Development Duke Energy 91,000 8,404 1,000 Recreation Use and Needs Update Duke Energy 45,000 4,156 0 

Recreation Enhancements Duke Energy 3,072,000 283,705 119,000 

Recreation Enhancements Duke Energy 0 0 9,000 

Recreation Enhancements Staff 4,500 416 0 

Public Information

Recreation Flow Communication – Develop and Maintain Systems Duke Energy 20,000 1,847 5,000 Safety and Security – Warning Device Duke Energy 100,000 9,236 0 

Safety and Security – Signage Duke Energy 10,000 924 1,000 

Safety and Security – Revise and implement safety plans Staff 28,500 2,632 1,000 

388 
389 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

co

Shoreline ManagementShoreline Management Plan Updates (every 10 years) Duke Energy 26,000 2,401 0 Shoreline Management Guidelines Updates (every 10 years) Duke Energy 8,000 738 0 

Other Enhancements

Land Conservation Support Duke Energy 667,000 61,599 0 Trash Management/Safety Duke Energy 14,000 1,293 4,000 

Funding for Conservation Easements Duke Energy 250,000 23,088 0 
4.4 POWER AND ECONOMIC BENEFITS OF THE LOOKOUT SHOALS 

DEVELOPMENT 

Table 105 summarizes the assumptions and economic information we use in our analysis. 

This information was provided by Duke Energy in its license application. We find that the 

values provided by Duke Energy are reasonable for the purposes of our analysis. Cost items 

common to all alternatives include: taxes and insurance costs; net investment (the total 

investment in power plant facilities remaining to be depreciated); relicensing costs; normal 

operation and maintenance cost; and Commission fees. All dollars are year 2008 unless 

specified otherwise. 

Table 105 Staff assumptions for the economic analysis of the Lookout Shoals Development. 

Parameter Value 

Period of analysis (years) 30 

Local Tax Rate (%)1 3.0 

Federal tax rate (%)2 32 

Insurance Rate (%)3 0.25 

Net investment(2008$)4 12,664,705 

Future major capital cost5 4,496,930 

Relicensing cost (2008$)6 2,164,135 

Operation and maintenance7 435,517 

Energy value (2008$/MWh)8 43.00 

Capacity value (2008$/kW-year)9 43.68 

Cost of Capital (%)10 8.5 

Discount rate (%)11 8.5 

1 Staff assumed a local tax rate of 3.0 percent. 

2 Staff assumed federal tax rate at 32 percent revenues. 

3 Staff assumed insurance rate equal to 0.25 percent of net investment. 

4 Net investment is the depreciated project investment allocated to power purposes and 

includes $13,960,963 (2006$) net plant investment for the existing facilities as reported by Duke 

Energy in exhibit D. 

5 Future major capital costs include implementation of measures to maintain present-day 

capability scheduled between 2008 and 2039 and are expressed as a present value. 

6 Relicensing costs include the administrative, legal/study, and other expenses to date. Staff 

has assumed total project relicensing cost $31,800,000 (2006$) is prorated by the average annual 

energy generation per project to determine the relicensing cost for each project. The Staff 

assumed relicensing cost for the Lookout Shoals Development in 2006$ is $2,009,689. 

7 Annual plant operation and maintenance costs reported by Duke are $404,436 (2006$). 

390 
8 Source: application for new license, exhibit D, page D-27, $39.93/MWh in 2006$. 

9 Source: application for new license, exhibit D, page D-27, $40.56/kW-year in 2006$. 

10 Based on Duke Energy’s weighted average cost of capital. Source: application for new 

license, exhibit D. 

11 Assumed by staff to be same as interest rate. 

Note: Staff escalated all 2006 values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent 

(12/31/06 to 12/31/07), and 2.3 percent (12/31/07 to 12/31/08) per year, respectively. The 

escalation rates were reported by the Department of Energy’s Cost Engineering Group. 

As currently operated, the 27.8-MW Lookout Shoals Development generates an average 

of 91,110 MWh annually and has a dependable capacity of 27.8 MW. 

4.4.1 Comparison of Alternatives 

Table 106 summarizes the annual cost, power benefit, and annual net benefit for the three 

alternatives considered in this DEIS: no-action alternative, Duke Energy’s proposal, and the 

staff-recommended alternative. 

Table 106 Summary of the annual cost, power benefits, and annual net benefits for the three 

alternatives for the Lookout Shoals Development (Source: Staff). 

No action 

Duke Energy’s 

Proposal 

Staff-recommended 

alternative 

Installed capacity (MW) 27.8 27.8 27.8 

Annual generation 

(thousand MWh) 91.11 81.08 81.08 

Annual power value, 

2008$: (mills/kWh): 

5,132,034 

(56.33) 

4,700,744 

(57.98) 

4,700,744 

(57.98) 

Annual cost, 2008$: 

(mills/kWh): 

3,167,170 

(34.76) 

3,550,028 

(43.78) 

3,501,085 

(43.18) 

Annual net benefit, 2008$: 

(mills/kWh): 

1,964,864 

(21.57) 

1,150,716 

(14.19) 

1,199,659 

(14.80) 

4.4.1.1 No-Action Alternative 

Under the no-action alternative, Duke Energy would continue to operate the project under 

the terms and conditions of the existing license, and no new environmental protection, 

mitigation, or enhancement measures would be implemented. 

Based on the above information and an average annual generation of 91,110 MWh, the 

existing project has an annual power value of $5,132,034 and costs $3,167,170 annually to 

operate and maintain. This results in a net annual benefit of $1,964,864 ($21.57/MWh). In other 

391 
392 

words, the project produces energy at a cost that is less than that of currently available alternative 

generation by $1,964,864 annually. 

4.4.1.2 Applicant’s Proposal 

In its license application and CRA, filed on December 22, 2007, Duke Energy proposes 

numerous operational and non-operational measures. 

As proposed by Duke Energy, the Lookout Shoals Development would generate an 

average of 81,080 MWh of electricity annually, have an annual power value of $4,700,744 

(57.98 mills/kWh), and total annual costs of $3,550,028 (43.78 mills/kWh). This results in a net 

annual benefit of $1,150,716 (14.19 mills/kWh). In other words, the project produces energy at a 

cost that is less than that of currently available alternative generation by $1,150,716 annually. 

4.4.1.3 Staff Alternative 

Resource agencies and nongovernmental organizations recommended the implementation 

of a variety of measures at the project. Staff reviewed each recommendation and determined 

which measures were the most appropriate for implementation. In section 5.0, Comprehensive 

Development and Recommended Alternative, we discuss our reasons for recommending the staff 

alternative and why we conclude that the environmental benefits are worth these costs. 

Table 107 list these proposed measures and identifies the ones that were adopted by staff. 

The staff alternative would generate an average of 81,080 MWh of electricity 

annually, have an annual power value of $4,700,744 (57.98 mills/kWh), and have total annual 

costs of $3,501,085 (43.18 mills/kWh). This results in an annual net benefit of $1,199,659 

(14.80 mills/kWh). In other words, the project produces energy at a cost that is less than that of 

currently available alternative generation by $1,199,659 annually. The staff alternative would 

reduce the net annual project benefit by about $48,943 ($0.61/MWh) compared to the project as 

proposed by Duke Energy. 

4.4.2 Cost of Environmental Measures 

Table 107 gives the cost of each of the environmental enhancement measures considered 

in our analysis. We convert all costs to equal annual (levelized) values over a 30-year period to 

give a uniform basis for comparing the benefits of a measure to its cost. All costs were adjusted 

from 2006$ to 2008$.
Table 107 Summary of capital, annual O&M, and annualized costs for environmental measures proposed by Du

by Staff for the Lookout Shoals Development for a 30-year license. (Source: Staff) 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) T

c

OperationsReservoir Level Control – Install flow compliance gage and provide maintenance 

Duke Energy 108,000 9,974 11,000 

Drought Mitigation – Low inflow protocol administration 

Duke Energy 0 0 2,000 

Drought Mitigation – Water Management Group Dues 

Duke Energy 0 0 14,000 

Maintenance and Emergency Protocol Duke Energy 0 0 1,000 

Water Quality and Quantity

Monitoring and Compliance – Installation and maintenance of DO and groundwater monitors 

Duke Energy 108,000 9,974 55,000 

Flow Mitigation - Conservation Easements Duke Energy 643,000 59,383 0 

Fish, Wildlife, and Botanical Resources

Species Protection Plans Duke Energy 9,000 831 5,000 Habitat Enhancement Fund Duke Energy 167,000 15,422 0 

Terrestrial Invasive Plant Species Management Plan 

Staff 3,000 277 150 

1 Staff escalated those values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent (12/31/06 to 12/31/07), and 2

12/31/08) per year, respectively. The escalation rates were reported by the Department of Energy’s Cost Engineerin(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Various%20Years.xls).

393 
Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) T

c

Cultural Resources

Historic Properties Management Plan – Annual HPMP review, signs, website, and materials 

Duke Energy 9,000 831 1,000 

Recreational ResourcesRecreation Management Plan Development Duke Energy 91,000 8,404 1,000 Recreation Use and Needs Update Duke Energy 45,000 4,156 0 

Recreation Enhancements Duke Energy 1,595,000 147,301 40,000 

Recreation Enhancements Duke Energy 426,000 39,342 73,000 

Recreation Enhancements Duke Energy 0 0 9,000 

Recreation Enhancements Staff 4,500 416 0 

Public Information

Safety and Security – Signage Duke Energy 10,000 924 1,000 Safety and Security – Revise and implement safety plans Staff 128,500 11,868 1,000 

Shoreline Management

Shoreline Management Plan Updates (every 10 years) Duke Energy 26,000 2,401 0 Shoreline Management Guidelines Updates (every 10 years) Duke Energy 8,000 738 0 

394 
395 

Other Enhancements Land Conservation Support Duke Energy 667,000 61,599 0 Trash Management/Safety Duke Energy 14,000 1,293 4,000 

Funding for Conservation Easements Duke Energy 250,000 23,088 0 
4.5 POWER AND ECONOMIC BENEFITS OF THE COWANS FORD 

DEVELOPMENT 

Table 108 summarizes the assumptions and economic information we use in our analysis. 

This information was provided by Duke Energy in its license application. We find that the 

values provided by Duke Energy are reasonable for the purposes of our analysis. Cost items 

common to all alternatives include: taxes and insurance costs; net investment (the total 

investment in power plant facilities remaining to be depreciated); relicensing costs; normal 

operation and maintenance cost; and Commission fees. All dollars are year 2008 unless 

specified otherwise. 

Table 108 Staff assumptions for the economic analysis of the Cowans Ford Development. 

Parameter Value 

Period of analysis (years) 30 

Local Tax Rate (%)1 3.0 

Federal tax rate (%)2 32 

Insurance Rate (%)3 0.25 

Net investment(2008$)4 34,294,153 

Future major capital cost5 2,979,650 

Relicensing cost (2008$)6 4,267,600 

Operation and maintenance7 2,240,110 

Energy value (2008$/MWh)8 43.42 

Capacity value (2008$/kW-year)9 5.94 

Cost of Capital (%)10 8.5 

Discount rate (%)11 8.5 

1 Staff assumed a local tax rate of 3.0 percent. 

2 Staff assumed federal tax rate at 32 percent revenues. 

3 Staff assumed insurance rate equal to 0.25 percent of net investment. 

4 Net investment is the depreciated project investment allocated to power purposes and 

includes $38,982,106 (2006$) net plant investment for the existing facilities as reported by Duke 

Energy in exhibit D. 

5 Future major capital costs include implementation of measures to maintain present-day 

capability scheduled between 2008 and 2039 and are expressed as a present value. 

6 Relicensing costs include the administrative, legal/study, and other expenses to date. Staff 

has assumed total project relicensing cost $31,800,000 (2006$) is prorated by the average annual 

energy generation per project to determine the relicensing cost for each project. The Staff 

assumed relicensing cost for the Cowans Ford Development in 2006$ is $3,963,038. 

396 
7 Annual plant operation and maintenance costs reported by Duke are $2,080,242 (2006$).

8 Source: application for new license, exhibit D, page D-27, $40.32/MWh in 2006$. 

9 Source: application for new license, exhibit D, page D-27, $5.52/kW-year in 2006$. 

10 Based on Duke Energy’s weighted average cost of capital. Source: application for new 

license, exhibit D. 

11 Assumed by staff to be same as interest rate. 

Note: Staff escalated all 2006 values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent 

(12/31/06 to 12/31/07), and 2.3 percent (12/31/07 to 12/31/08) per year, respectively. The 

escalation rates were reported by the Department of Energy’s Cost Engineering Group 

(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Vari

ous%20Years.xls). 

As currently operated, the 400-MW Cowans Ford Development generates an average of 

179,660 MWh annually and has a dependable capacity of 400 MW. 

4.5.1 Comparison of Alternatives 

Table 109 summarizes the annual cost, power benefit, and annual net benefit for the three 

alternatives considered in this DEIS: no-action alternative, Duke Energy’s proposal, and the 

staff-recommended alternative. 

Table 109 Summary of the annual cost, power benefits, and annual net benefits for the three 

alternatives for the Cowans Ford Development (Source: Staff). 

No action Duke Energy’s 

Proposal 

Staff-recommended 

alternative 

Installed capacity (MW) 400 400 400 

Annual generation (thousand 

MWh) 179.66 159.89 159.89 

Annual power value, 2008$: 

(mills/kWh): 

10,176,837 

(56.64) 

9,318,424 

(58.28) 

9,318,424 

(58.28) 

Annual cost, 2008$: 

(mills/kWh): 

7,975,219 

(44.39) 

8,281,668 

(51.80) 

8,258,585 

(51.65) 

Annual net benefit, 2008$: 

(mills/kWh): 

2,201,618 

(12.25) 

1,036,756 

(6.48) 

1,059,839 

(6.63) 

4.5.1.1 No-Action Alternative 

Under the no-action alternative, Duke Energy would continue to operate the project under 

the terms and conditions of the existing license, and no new environmental protection, 

mitigation, or enhancement measures would be implemented. 

397 
398 

Based on the above information and an average annual generation of 179,660 MWh, the 

existing project has an annual power value of $10,176,837 and costs $7,975,219 annually to 

operate and maintain. This results in a net annual benefit of $2,201,618 (or $12.25/MWh). In 

other words, the project produces energy at a cost that is less than that of currently available 

alternative generation by $2,201,618 annually.

4.5.1.2 Applicant’s Proposal 

In its license application and CRA, filed on December 22, 2007, Duke Energy proposes 

numerous operational and non-operational measures. 

As proposed by Duke Energy, the Cowans Ford Development would generate an 

average of 159,890 MWh of electricity annually, have an annual power value of $9,318,424 

(58.28 mills/kWh), and total annual costs of $8,281,668 (51.80 mills/kWh). This results in a net 

annual benefit of $1,036,756 (6.48 mills/kWh). In other words, the project produces energy at a 

cost that is greater than that of currently available alternative generation by $1,036,756 annually.

4.5.1.3 Staff Alternative 

Resource agencies and nongovernmental organizations recommended the implementation 

of a variety of measures at the project. Staff reviewed each recommendation and determined 

which measures were the most appropriate for implementation. In section 5.0, Comprehensive 

Development and Recommended Alternative, we discuss our reasons for recommending the staff 

alternative and why we conclude that the environmental benefits are worth these costs. 

Table 110 list these proposed measures and identifies the ones that were adopted by staff. The 

cost for the staff recommendation to reassess the eligibility of the Cowans Ford Development for 

the National Register is negligible since the reassessment would occur as part of the process of 

review for the HPMP. 

The staff alternative would generate an average of 159,890 MWh of electricity annually, 

have an annual power value of $9,318,424 (58.28 mills/kWh), and have total annual costs of 

$8,258,585 (51.65 mills/kWh). This results in an annual net benefit of $1,059,839 

(6.63 mills/kWh). In other words, the project produces energy at a cost that is less than that of 

currently available alternative generation by $1,059,839 annually. The staff alternative would 

increase the net annual project benefit by about $23,083 ($0.15/MWh) compared to the project as 

proposed by Duke Energy. 

4.5.2 Cost of Environmental Measures 

Table 110 gives the cost of each of the environmental enhancement measures considered 

in our analysis. We convert all costs to equal annual (levelized) values over a 30-year period to 

give a uniform basis for comparing the benefits of a measure to its cost. All costs were adjusted 

from 2006$ to 2008$. 
Table 110 Summary of capital, annual O&M, and annualized costs for environmental measures proposed by Du

by Staff for the Cowans Ford Development for a 30-year license. (Source: Staff) 

Mitigation Measure Recommending Entities Capital Costs (2006$)1 Annualized Capital Costs (2008$) Annualized O&M (2008$) T

C

OperationsReservoir Level Stabilization (Spring Lake Stabilization) Duke Energy 0 0 1,000 Drought Mitigation – Low inflow protocol administration Duke Energy 0 0 2,000 

Drought Mitigation – Water Management Group Dues Duke Energy 0 0 14,000 Maintenance and Emergency Protocol Duke Energy 0 0 1,000 

Flow and Reservoir-Gage Maintenance Duke Energy 0 0 30,000 Water Quality and Quantity

Monitoring and Compliance – Installation and maintenance of DO and groundwater monitors Duke Energy 108,000 9,974 55,000 Fish, Wildlife, and Botanical ResourcesSpecies Protection Plans Duke Energy 7,000 647 5,000 Habitat Enhancement Fund Duke Energy 167,000 15,422 0 

Terrestrial Invasive Plant Species Management Plan Staff 3,000 277 150 

1 Staff escalated those values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent (12/31/06 to 12/31/07), and 2

12/31/08) per year, respectively. The escalation rates were reported by the Department of Energy’s Cost Engineerin(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Various%20Years.xls).

399 
Mitigation Measure Recommending Entities Capital Costs (2006$)1 Annualized Capital Costs (2008$) Annualized O&M (2008$) T

C

Cultural ResourcesHistoric Properties Management Plan – Annual HPMP review, signs, website, and materials Duke Energy 9,000 831 1,000 Recreational ResourcesRecreation Management Plan Development Duke Energy 91,000 8,404 1,000 Recreation Use and Needs Update Duke Energy 45,000 4,156 0 

Recreation Enhancements Duke Energy 2,145,000 198,094 47,000 

Recreation Enhancements Duke Energy 1,655,000 152,842 0 Recreation Enhancements Duke Energy 0 0 9,000 

Recreation Enhancements Staff 304,500 28,121 4,600 Public Information

Safety and Security – Signage Duke Energy 10,000 924 1,000 Safety and Security – Revise and implement safety plans Staff 98,500 9,097 1,000 Shoreline ManagementShoreline Management Plan Updates (every 10 years) Duke Energy 26,000 2,401 0 Shoreline Management Guidelines Updates (every 10 years) Duke Energy 8,000 738 0 

400 
401 

Mitigation Measure Recommending Entities Capital Costs (2006$)1 Annualized Capital Costs (2008$) Annualized O&M (2008$) T

C

Other Enhancements Land Conservation Support Duke Energy 667,000 61,599 0 Trash Management/Safety Duke Energy 14,000 1,293 4,000 

Funding for Conservation Easements Duke Energy 250,000 23,088 0 
4.6 POWER AND ECONOMIC BENEFITS OF THE MOUNTAIN ISLAND 

DEVELOPMENT 

Table 111 summarizes the assumptions and economic information we use in our analysis. 

This information was provided by Duke Energy in its license application. We find that the 

values provided by Duke Energy are reasonable for the purposes of our analysis. Cost items 

common to all alternatives include: taxes and insurance costs; net investment (the total 

investment in power plant facilities remaining to be depreciated); relicensing costs; normal 

operation and maintenance cost; and Commission fees. All dollars are year 2008 unless 

specified otherwise. 

Table 111 Staff assumptions for the economic analysis of the Mountain Island Development. 

Parameter Value 

Period of analysis (years) 30 

Local Tax Rate (%)1 3.0 

Federal tax rate (%)2 32 

Insurance Rate (%)3 0.25 

Net investment(2008$)4 16,705,673 

Future major capital cost5 3,144,400 

Relicensing cost (2008$)6 2,696,777 

Operation and maintenance7 867,750 

Energy value (2008$/MWh)8 43.40 

Capacity value (2008$/kW-year)9 25.32 

Interest rate (%)10 8.5 

Discount rate (%)11 8.5 

1 Staff assumed a local tax rate of 3.0 percent. 

2 Staff assumed federal tax rate at 32 percent revenues. 

3 Staff assumed insurance rate equal to 0.25 percent of net investment. 

4 Net investment is the depreciated project investment allocated to power purposes and 

includes $19,371,329 (2006$) net plant investment for the existing facilities as reported by Duke 

Energy in exhibit D. 

5 Future major capital costs include implementation of measures to maintain present-day 

capability scheduled between 2008 and 2039 and are expressed as a present value. 

6 Relicensing costs include the administrative, legal/study, and other expenses to date. Staff 

has assumed total project relicensing cost $31,800,000 (2006$) is prorated by the average annual 

energy generation per project to determine the relicensing cost for each project. The Staff 

assumed relicensing cost for the Mountain Island Development in 2006$ is $2,504,318. 

402 
7 Annual plant operation and maintenance costs reported by Duke are $805,822 (2006$). 

8 Source: application for new license, exhibit D, page D-27, $40.30/MWh in 2006$. 

9 Source: application for new license, exhibit D, page D-27, $23.51/kW-year in 2006$. 

10 Based on Duke Energy’s weighted average cost of capital. Source: application for new 

license, exhibit D. 

11 Assumed by staff to be same as interest rate. 

Note: Staff escalated all 2006 values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent 

(12/31/06 to 12/31/07), and 2.3 percent (12/31/07 to 12/31/08) per year, respectively. The 

escalation rates were reported by the Department of Energy’s Cost Engineering Group 

(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Vari

ous%20Years.xls). 

As currently operated, the 60.6-MW Mountain Island Development generates an average 

of 113,530 MWh annually and has a dependable capacity of 60.6 MW. 

4.6.1 Comparison of Alternatives 

Table 112 summarizes the annual cost, power benefit, and annual net benefit for the three 

alternatives considered in this DEIS: no-action alternative, Duke Energy’s proposal, and the 

staff-recommended alternative. 

Table 112 Summary of the annual cost, power benefits, and annual net benefits for the three 

alternatives for the Mountain Island Development (Source: Staff). 

No action Duke Energy’s 

Proposal 

Staff-recommended 

alternative 

Installed capacity (MW) 60.6 60.6 60.6 

Annual generation (thousand 

MWh) 113.53 101.04 101.04 

Annual power value, 2008$: 

(mills/kWh): 

6,461,594 

(56.92) 

5,919,528 

(58.59) 

5,919,528 

(58.59) 

Annual cost, 2008$: 

(mills/kWh): 

4,265,532 

(37.57) 

4,443,747 

(43.98) 

4,386,092 

(43.41) 

Annual net benefit, 2008$: 

(mills/kWh): 

2,196,062 

(19.34) 

1,475,781 

(14.61) 

1,533,436 

(15.18) 

4.6.1.1 No-Action Alternative 

Under the no-action alternative, Duke Energy would continue to operate the project under 

the terms and conditions of the existing license, and no new environmental protection, 

mitigation, or enhancement measures would be implemented. 

403 
404 

Based on the above information and an average annual generation of 113,530 MWh, the 

existing project has an annual power value of $6,461,594 and costs $4,265,532 annually to 

operate and maintain. This results in a net annual benefit of $2,196,062 (or $19.34/MWh). In 

other words, the project produces energy at a cost that is greater than that of currently available 

alternative generation by $2,196,062 annually.

4.6.1.2 Applicant’s Proposal 

In its license application and CRA, filed on December 22, 2007, Duke Energy proposes 

numerous operational and non-operational measures. 

As proposed by Duke Energy, the Mountain Island Development would generate an 

average of 101,040 MWh of electricity annually, have an annual power value of $5,919,528 

(58.59 mills/kWh), and total annual costs of $4,443,747 (43.98 mills/kWh). This results in a net 

annual benefit of $1,475,781 (14.61 mills/kWh). In other words, the project produces energy at a 

cost that is less than that of currently available alternative generation by $1,475,781 annually.

4.6.1.3 Staff Alternative 

Resource agencies and nongovernmental organizations recommended the implementation 

of a variety of measures at the project. Staff reviewed each recommendation and determined 

which measures were the most appropriate for implementation. In section 5.0, Comprehensive 

Development and Recommended Alternative, we discuss our reasons for recommending the staff 

alternative and why we conclude that the environmental benefits are worth these costs. 

Table 113 list these proposed measures and identify the ones that were adopted by staff. 

The staff alternative would generate an average of 101,040 MWh of electricity annually, 

have an annual power value of $5,919,528 (58.59 mills/kWh), and have total annual costs of 

$4,386,092 (43.41 mills/kWh). This results in an annual net benefit of $1,553,436 

(16.97 mills/kWh). In other words, the project produces energy at a cost that is greater than that 

of currently available alternative generation by $1,533,436 annually. The staff alternative would 

increase the net annual project benefit by about $57,655 ($0.57/MWh) compared to the project as 

proposed by Duke Energy. 

4.6.2 Cost of Environmental Measures 

Table 113 gives the cost of each of the environmental enhancement measures considered 

in our analysis. We convert all costs to equal annual (levelized) values over a 30-year period to 

give a uniform basis for comparing the benefits of a measure to its cost. All costs were adjusted 

from 2006$ to 2008$. 
Table 113 Summary of capital, annual O&M, and annualized costs for environmental measures proposed by Du

by Staff for the Mountain Island Development for a 30-year license. (Source: Staff) 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

C

OperationsDrought Mitigation – Low inflow protocol administration Duke Energy 0 0 2,000 Drought Mitigation – Water Management Group Dues Duke Energy 0 0 14,000 

Maintenance and Emergency Protocol Duke Energy 0 0 1,000 

Water Quality and Quantity

Monitoring and Compliance – Installation and maintenance of DO and groundwater monitors 

Duke Energy 108,000 9,974 55,000 

Flow Mitigation – Conservation Easements Duke Energy 643,000 59,383 0 

Fish, Wildlife, and Botanical Resources

Species Protection Plans Duke Energy 9,000 831 5,000 Habitat Enhancement Fund Duke Energy 167,000 15,422 0 

Terrestrial Invasive Plant Species Management Plan Staff 3,000 277 150 Cultural Resources

1 Staff escalated those values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent (12/31/06 to 12/31/07), and 2

12/31/08) per year, respectively. The escalation rates were reported by the Department of Energy’s Cost Engineerin(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Various%20Years.xls).

405 
406 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

C

Historic Properties Management Plan – Annual HPMP review, signs, website, & materials Duke Energy 9,000 831 1,000 Recreational ResourcesRecreation Management Plan Development Duke Energy 91,000 8,404 1,000 Recreation Use and Needs Update Duke Energy 45,000 4,156 0 

Recreation Enhancements Duke Energy 667,000 61,599 20,000 

Recreation Enhancements Duke Energy 206,000 19,024 20,000 Recreation Enhancements Duke Energy 0 0 9,000 

Recreation Enhancements Staff 4,500 416 0 

Public Information

Safety and Security – Signage Duke Energy 10,000 924 1,000 Safety and Security – Revise and implement safety plans Staff 28,500 2,632 1,000 

Shoreline Management

Shoreline Management Plan Updates (every 10 years) Duke Energy 26,000 2,401 0 Shoreline Management Guidelines Updates (every 10 years) Duke Energy 8,000 738 0 

Other Enhancements

Land Conservation Support Duke Energy 667,000 61,599 0 Trash Management/Safety Duke Energy 14,000 1,293 4,000 

Funding for Conservation Easements Duke Energy 250,000 23,088 0 
4.7 POWER AND ECONOMIC BENEFITS OF THE WYLIE DEVELOPMENT 

Table 114 summarizes the assumptions and economic information we use in our analysis. 

This information was provided by Duke Energy in its license application. We find that the 

values provided by Duke Energy are reasonable for the purposes of our analysis. Cost items 

common to all alternatives include: taxes and insurance costs; net investment (the total 

investment in power plant facilities remaining to be depreciated); relicensing costs; normal 

operation and maintenance cost; and Commission fees. All dollars are year 2008 unless 

specified otherwise. 

Table 114 Staff assumptions for the economic analysis of the Wylie Development. 

Parameter Value 

Period of analysis (years) 30 

Local Tax Rate (%)1 3.0 

Federal tax rate (%)2 32 

Insurance Rate (%)3 0.25 

Net investment(2008$)4 31,856,667 

Future major capital cost5 13,602,790 

Relicensing cost (2008$)6 3,364,083 

Operation and maintenance7 810,852 

Energy value (2008$/MWh)8 42.44 

Capacity value (2008$/kW-year)9 25.88 

Cost of Capital (%)10 8.5 

Discount rate (%)11 8.5 

1 Staff assumed a local tax rate of 3.0 percent. 

2 Staff assumed federal tax rate at 32 percent revenues. 

3 Staff assumed insurance rate equal to 0.25 percent of net investment. 

4 Net investment is the depreciated project investment allocated to power purposes and 

includes $34,522,323 (2006$) net plant investment for the existing facilities as reported by Duke 

Energy in exhibit D. 

5 Future major capital costs include implementation of measures to maintain present-day 

capability scheduled between 2008 and 2039 and are expressed as a present value. 

6 Relicensing costs include the administrative, legal/study, and other expenses to date. Staff 

has assumed total project relicensing cost $31,800,000 (2006$) is prorated by the average annual 

energy generation per project to determine the relicensing cost for each project. The Staff 

assumed relicensing cost for the Wylie Development in 2006$ is $3,124,001. 

7 Annual plant operation and maintenance costs reported by Duke are $752,985 (2006$). 

407 
8 Source: application for new license, exhibit D, page D-27, $39.41/MWh in 2006$. 

9 Source: application for new license, exhibit D, page D-27, $24.03/kW-year in 2006$. 

10 Based on Duke Energy’s weighted average cost of capital. Source: application for new 

license, exhibit D. 

11 Assumed by staff to be same as interest rate. 

Note: Staff escalated all 2006 values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent 

(12/31/06 to 12/31/07), and 2.3 percent (12/31/07 to 12/31/08) per year, respectively. The 

escalation rates were reported by the Department of Energy’s Cost Engineering Group 

(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Vari

ous%20Years.xls). 

As currently operated, the 74-MW Wylie Development generates an average of 

141,620 MWh annually and has a dependable capacity of 74 MW. 

4.7.1 Comparison of Alternatives 

Table 115 summarizes the annual cost, power benefit, and annual net benefit for the three 

alternatives considered in this DEIS: no-action alternative, Duke Energy’s proposal, and the 

staff-recommended alternative. 

Table 115 Summary of the annual cost, power benefits, and annual net benefits for the three 

alternatives for the Wylie Development (Source: Staff). 

No action Duke Energy’s 

Proposal 

Staff-recommended 

alternative 

Installed capacity (MW) 74 74 74 

Annual generation (thousand 

MWh) 141.62 126.04 126.04 

Annual power value, 2008$: 

(mills/kWh): 

7,925,473 

(55.96) 

7,264,258 

(57.63) 

7,264,258 

(57.63) 

Annual cost, 2008$ 

(mills/kWh): 

6,006,040 

(42.41) 

7,039,944 

(55.85) 

7,144,612 

(56.69) 

Annual net benefit, 2008$ 

(mills/kWh): 

1,919,432 

(13.55) 

224,313 

(1.78) 

119,645 

(0.95) 

4.7.1.1 No-Action Alternative 

Under the no-action alternative, Duke Energy would continue to operate the project under 

the terms and conditions of the existing license, and no new environmental protection, 

mitigation, or enhancement measures would be implemented. 

408 
409 

Based on the above information and an average annual generation of 141,620 MWh, the 

existing project has an annual power value of $7,925,473 and costs $6,006,040 annually to 

operate and maintain. This results in a net annual benefit of $1,919,432 (or $13.55/MWh). In 

other words, the project produces energy at a cost that is less than that of currently available 

alternative generation by $1,919,432 annually.

4.7.1.2 Applicant’s Proposal 

In its license application and CRA, filed on December 22, 2007, Duke Energy proposes 

numerous operational and non-operational measures. 

As proposed by Duke Energy, the Wylie Development would generate an average 

of 126,040 MWh of electricity annually, have an annual power value of $7,264,258 

(57.63 mills/kWh), and total annual costs of $7,039,944 (55.85 mills/kWh). This results in a net 

annual benefit of $224,313 (1.78 mills/kWh). In other words, the project produces energy at a 

cost that is less than that of currently available alternative generation by $224,313 annually. 

4.7.1.3 Staff Alternative 

Resource agencies and nongovernmental organizations recommended the implementation 

of a variety of measures at the project. Staff reviewed each recommendation and determined 

which measures were the most appropriate for implementation. In section 5.0, Comprehensive 

Development and Recommended Alternative, we discuss our reasons for recommending the staff 

alternative and why we conclude that the environmental benefits are worth these costs. 

Table 116 list these proposed measures and identifies the ones that were adopted by staff. 

The staff alternative would generate an average of 126,040 MWh of electricity annually, 

have an annual power value of $7,264,258 (57.63 mills/kWh), and have total annual costs of 

$7,144,612 (56.69 mills/kWh). This results in a annual net benefit of $119,645 

(0.95 mills/kWh). In other words, the project produces energy at a cost that is less than that of 

currently available alternative generation by $119,645 annually. The staff alternative would 

reduce the net annual project benefit by about $104,668 ($0.83/MWh) compared to the project as 

proposed by Duke Energy. 

4.7.2 Cost of Environmental Measures 

Table 116 gives the cost of each of the environmental enhancement measures considered 

in our analysis. We convert all costs to equal annual (levelized) values over a 30-year period 

analysis to give a uniform basis for comparing the benefits of a measure to its cost. All costs 

were adjusted from 2006$ to 2008$. 
Table 116 Summary of capital, annual O&M, and annualized costs for environmental measures proposed by Du

by Staff for the Wylie Development for a 30-year license. (Source: Staff) 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

C

OperationsReservoir Level Stabilization (Spring Lake Stabilization) Duke Energy 0 0 1,000 Drought Mitigation – Low inflow protocol administration Duke Energy 0 0 2,000 

Drought Mitigation – Water Management Group Dues Duke Energy 0 0 14,000 

Maintenance and Emergency Protocol Duke Energy 0 0 1,000 

Flow and Reservoir Elevation Monitoring – USGS gage installation and maintenance Duke Energy 0 0 30,000 Water Quality and Quantity

Monitoring and Compliance – Installation and maintenance of DO and groundwater monitors Duke Energy 108,000 9,974 55,000 Water Quality Enhancement – minimum flow unit with aerating runner Duke Energy 3,989,000 368,391 12,000 Flow Mitigation – Conservation Easements Duke Energy 168,000 15,515 0 

Flow Mitigation – Mitigation Fund Duke Energy 200,000 18,470 0 

1 Staff escalated those values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent (12/31/06 to 12/31/07), and 2

12/31/08) per year, respectively. The escalation rates were reported by the Department of Energy’s Cost Engineerin(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Various%20Years.xls).

410 
Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

C

Fish, Wildlife, and Botanical Resources

Species Protection Plans Duke Energy 12,000 1,108 8,000 Habitat Enhancement Fund Duke Energy 167,000 15,422 0 

Terrestrial Invasive Plant Species Management Plan 

Staff 3,000 277 150 

Cultural Resources

Historic Properties Management Plan – Annual HPMP review, signs, website, and materials Duke Energy 9,000 831 1,000 Recreational ResourcesRecreation Management Plan Development Duke Energy 91,000 8,404 1,000 Recreation Use and Needs Update Duke Energy 45,000 4,156 0 

Recreation Enhancements Duke Energy 1,816,000 167,711 20,000 

Recreation Enhancements Duke Energy 4,292,000 396,373 18,000 

Recreation Enhancements Duke Energy 260,000 24,011 0 

Recreation Enhancements Staff 2,178,500 201,188 18,000 

Public Information

Recreation Flow Communication – Develop and Maintain Systems Duke Energy 20,000 1,847 5,000 Safety and Security – Signage Duke Energy 10,000 924 1,000 Safety and Security – Revise and implement safety plans Staff 28,500 2,632 1,000 

411 
412 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

C

Shoreline ManagementShoreline Management Plan Updates (every 10 years) Duke Energy 26,000 2,401 0 Shoreline Management Guidelines Updates (every 10 years) Duke Energy 8,000 738 0 Other EnhancementsLand Conservation Support Duke Energy 1,064,000 98,262 0 Trash Management/Safety Duke Energy 14,000 1,293 4,000 

Funding for Conservation Easements Duke Energy 300,000 27,706 0 
4.8 POWER AND ECONOMIC BENEFITS OF THE FISHING CREEK 

DEVELOPMENT 

Table 117 summarizes the assumptions and economic information we use in our analysis. 

This information was provided by Duke Energy in its license application. We find that the 

values provided by Duke Energy are reasonable for the purposes of our analysis. Cost items 

common to all alternatives include: taxes and insurance costs; net investment (the total 

investment in power plant facilities remaining to be depreciated); relicensing costs; normal 

operation and maintenance cost; and Commission fees. All dollars are year 2008 unless 

specified otherwise. 

Table 117 Staff assumptions for the economic analysis of the Fishing Creek Development. 

Parameter Value 

Period of analysis (years) 30 

Local Tax Rate (%)1 3.0 

Federal tax rate (%)2 32 

Insurance Rate (%)3 0.25 

Net investment(2008$)4 30,145,439 

Future major capital cost5 6,378,190 

Relicensing cost (2008$)6 3,540,554 

Operation and maintenance7 828,301 

Energy value (2008$/MWh)8 43.24 

Capacity value (2008$/kW-year)9 43.29 

Cost of Capital (%)10 8.5 

Discount rate (%)11 8.5 

1 Staff assumed a local tax rate of 3.0 percent. 

2 Staff assumed federal tax rate at 32 percent revenues. 

3 Staff assumed insurance rate equal to 0.25 percent of net investment. 

4 Net investment is the depreciated project investment allocated to power purposes and 

includes $32,866,883 (2006$) net plant investment for the existing facilities as reported by Duke 

Energy in exhibit D. 

5 Future major capital costs include implementation of measures to maintain present-day 

capability scheduled between 2008 and 2039 and are expressed as a present value.. 

6 Relicensing costs include the administrative, legal/study, and other expenses to date. Staff 

has assumed total project relicensing cost $31,800,000 (2006$) is prorated by the average annual 

energy generation per project to determine the relicensing cost for each project. The Staff 

assumed relicensing cost for the Fishing Creek Development in 2006$ is $3,287,878. 

413 
7 Annual plant operation and maintenance costs reported by Duke are $769,188 (2006$). 

8 Source: application for new license, exhibit D, page D-27, $40.15/MWh in 2006$. 

9 Source: application for new license, exhibit D, page D-27, $40.20/kW-year in 2006$. 

10 Based on Duke Energy’s weighted average cost of capital. Source: application for new 

license, exhibit D. 

11 Assumed by staff to be same as interest rate. 

Note: Staff escalated all 2006 values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent 

(12/31/06 to 12/31/07), and 2.3 percent (12/31/07 to 12/31/08) per year, respectively. The 

escalation rates were reported by the Department of Energy’s Cost Engineering Group 

(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Vari

ous%20Years.xls) 

As currently operated, the 52.1-MW Fishing Creek Development generates an average of 

149,050 MWh annually and has a dependable capacity of 52.1 MW. 

4.8.1 Comparison of Alternatives 

Table 118 summarizes the annual cost, power benefit, and annual net benefit for the three 

alternatives considered in this DEIS: no-action alternative, Duke Energy’s proposal, and the 

staff-recommended alternative. 

Table 118 Summary of the annual cost, power benefits, and annual net benefits for the three 

alternatives for the Fishing Creek Development (Source: Staff). 

No action Duke Energy’s 

Proposal 

Staff-recommended 

alternative 

Installed capacity (MW) 52.1 52.1 52.1 

Annual generation (thousand 

MWh) 149.05 132.65 132.65 

Annual power value, 2008$: 

(mills/kWh): 

8,700,331 

(58.37) 

7,991,195 

(60.24) 

7,991,195 

(60.24) 

Annual cost, 2008$: 

(mills/kWh): 

6,138,685 

(41.19) 

6,551,119 

(49.39) 

6,446,639 

(48.75) 

Annual net benefit, 2008$: 

(mills/kWh): 

2,561,646 

(17.19) 

1,440,076 

(10.86) 

1,524,556 

(11.49) 

4.8.1.1 No-Action Alternative 

Under the no-action alternative, Duke Energy would continue to operate the project under 

the terms and conditions of the existing license, and no new environmental protection, 

mitigation, or enhancement measures would be implemented. 

414 
415 

Based on the above information and an average annual generation of 149,050 MWh, the 

existing project has an annual power value of $8,700,331 and costs $6,138,685 annually to 

operate and maintain. This results in a net annual benefit of $2,561,646 (or $17.19/MWh). In 

other words, the project produces energy at a cost that is less than that of currently available 

alternative generation by $2,561,646 annually.

4.8.1.2 Applicant’s Proposal 

In its license application and CRA, filed on December 22, 2007, Duke Energy proposes 

numerous operational and non-operational measures. 

As proposed by Duke Energy, the Fishing Creek Development would generate an 

average of 132,650 MWh of electricity annually, have an annual power value of $7,991,195 

(60.24 mills/kWh), and total annual costs of $6,551,119 (49.39 mills/kWh). This results in a net 

annual benefit of $1,440,076 (10.86 mills/kWh). In other words, the project produces energy at a 

cost that is less than that of currently available alternative generation by $1,440,076 annually.

4.8.1.3 Staff Alternative 

Resource agencies and nongovernmental organizations recommended the implementation 

of a variety of measures at the project. Staff reviewed each recommendation and determined 

which measures were the most appropriate for implementation. In section 5.0, Comprehensive 

Development and Recommended Alternative, we discuss our reasons for recommending the staff 

alternative and why we conclude that the environmental benefits are worth these costs. 

Table 119 list these proposed measures and identifies the ones that were adopted by staff. 

The staff alternative would generate an average of 132,650 MWh of electricity annually, 

have an annual power value of $7,991,195 (60.24 mills/kWh), and have total annual costs of 

$6,446,639 (48.75 mills/kWh. This results in an annual net benefit of $1,524,556 

(11.49 mills/kWh). In other words, the project produces energy at a cost that is less than that of 

currently available alternative generation by $1,524,556 annually. The staff alternative would 

increase the net annual project benefit by about $84,480 ($11.49/MWh) compared to the project 

as proposed by Duke Energy. 

4.8.2 Cost of Environmental Measures 

Table 119 gives the cost of each of the environmental enhancement measures considered 

in our analysis. We convert all costs to equal annual (levelized) values over a 30-year period to 

give a uniform basis for comparing the benefits of a measure to its cost. All costs were adjusted 

from 2006$ to 2008$.
Table 119 Summary of capital, annual O&M, and annualized costs for environmental measures proposed by Du

by Staff for the Fishing Creek Development for a 30-year license. (Source: Staff) 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(

C

OperationsDrought Mitigation – Low inflow protocol administration Duke Energy 0 0 2,000 Drought Mitigation – Water Management Group Dues Duke Energy 0 0 14,000 

Maintenance and Emergency Protocol Duke Energy 0 0 1,000 

Water Quality and Quantity

Monitoring and Compliance – Installation and maintenance of DO and groundwater monitors 

Duke Energy 108,000 9,974 55,000 

Flow Mitigation – Mitigation Fund Duke Energy 200,000 18,470 0 

Fish, Wildlife, and Botanical Resources

Species Protection Plans Duke Energy 9,000 831 5,000 Habitat Enhancement Fund Duke Energy 200,000 18,470 0 

Terrestrial Invasive Plant Species Management Plan Staff 3,000 277 150 

Cultural Resources

1 Staff escalated those values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent (12/31/06 to 12/31/07), and 2

12/31/08) per year, respectively. The escalation rates were reported by the Department of Energy’s Cost Engineerin(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Various%20Years.xls).

416 
Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(

C

Historic Properties Management Plan – Annual HPMP review, signs, website, and materials 

Duke Energy 9,000 831 1,000 

Historic Properties Management Plan – Site Monitoring Duke Energy 0 0 25,000 Recreational ResourcesRecreation Management Plan Development Duke Energy 91,000 8,404 1,000 Recreation Use and Needs Update Duke Energy 45,000 4,156 0 

Recreation Enhancements Duke Energy 2,111,000 194,954 39,000 

Recreation Enhancements Duke Energy 508,000 46,915 0 

Recreation Enhancements Duke Energy 0 0 9,000 

Recreation Enhancements Staff 4,500 416 0 Public Information

Recreation Flow Communication – Develop and Maintain Systems Duke Energy 20,000 1,847 5,000 Safety and Security – Signage Duke Energy 10,000 924 1,000 Safety and Security – Revise and implement safety plans Staff 28,500 2,632 1,000 Shoreline ManagementShoreline Management Plan Updates (every 10 years) Duke Energy 26,000 2,401 0 

417 
418 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(

C

Shoreline Management Guidelines Updates (every 10 years) Duke Energy 8,000 738 0 Other EnhancementsLand Conservation Support Duke Energy 1,064,000 98,262 0 Trash Management/Safety Duke Energy 14,000 1,293 4,000 

Trash Rake Duke Energy 1,200,000 110,822 0 Funding for Conservation Easements Duke Energy 300,000 27,706 0 
4.9 POWER AND ECONOMIC BENEFITS OF THE GREAT FALLS AND 

DEARBORN DEVELOPMENTS 

Table 120 summarizes the assumptions and economic information we use in our analysis. 

This information was provided by Duke Energy in its license application. We find that the 

values provided by Duke Energy are reasonable for the purposes of our analysis. Cost items 

common to all alternatives include: taxes and insurance costs; net investment (the total 

investment in power plant facilities remaining to be depreciated); relicensing costs; normal 

operation and maintenance cost; and Commission fees. All dollars are year 2008 unless 

specified otherwise. 

Table 120 Staff assumptions for the economic analysis of the Great Falls and Dearborn 

Developments. 

Parameter Value 

Period of analysis (years) 30 

Local Tax Rate (%)1 3.0 

Federal tax rate (%)2 32 

Insurance Rate (%)3 0.25 

Net investment(2008$)4 18,711,557 

Future major capital cost5 7,726,400 

Relicensing cost (2008$)6 3,237,448 

Operation and maintenance7 1,036,632 

Energy value (2008$/MWh)8 43.32 

Capacity value (2008$/kW-year)9 40.68 

Cost of Capital (%)10 8.5 

Discount rate (%)11 8.5 

1 Staff assumed a local tax rate of 3.0 percent. 

2 Staff assumed federal tax rate at 32 percent revenues. 

3 Staff assumed insurance rate equal to 0.25 percent of net investment. 

4 Net investment is the depreciated project investment allocated to power purposes and 

includes $20,718,638 (2006$) net plant investment for the existing facilities as reported by Duke 

Energy in exhibit D. 

5 Future major capital costs include implementation of measures to maintain present-day 

capability scheduled between 2008 and 2039 and are expressed as a present value. 

6 Relicensing costs include the administrative, legal/study, and other expenses to date. Staff 

has assumed total project relicensing cost $31,800,000 (2006$) is prorated by the average annual 

energy generation per project to determine the relicensing cost for each project. The Staff 

assumed relicensing cost for the Great Falls and Dearborn Developments in 2006$ is $3,006,404. 

419 
7 Annual plant operation and maintenance costs reported by Duke are $962,652 (2006$). 

8 Source: application for new license, exhibit D, page D-27, $40.23/MWh in 2006$. 

9 Source: application for new license, exhibit D, page D-27, $37.78/kW-year in 2006$. 

10 Based on Duke Energy’s weighted average cost of capital. Source: application for new 

license, exhibit D. 

11 Assumed by staff to be same as interest rate. 

Note: Staff escalated all 2006 values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent 

(12/31/06 to 12/31/07), and 2.3 percent (12/31/07 to 12/31/08) per year, respectively. The 

escalation rates were reported by the Department of Energy’s Cost Engineering Group 

(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Vari

ous%20Years.xls) 

As currently operated, the 63.3-MW Great Falls and Dearborn Developments generates 

an average of 136,290 MWh annually and has an installed capacity of 63.3 MW. 

4.9.1 Comparison of Alternatives 

Table 121 summarizes the annual cost, power benefit, and annual net benefit for the three 

alternatives considered in this DEIS: no-action alternative, Duke Energy’s proposal, and the 

staff-recommended alternative. 

Table 121 Summary of the annual cost, power benefits, and annual net benefits for the three 

alternatives for the Great Falls and Dearborn Developments (Source: Staff). 

No action Duke Energy’s 

Proposal 

Staff-recommended 

alternative 

Installed capacity (MW) 63.3 63.3 63.3 

Annual generation 

(thousand MWh) 136.29 121.30 121.30 

Annual power value, 

2008$: 

(mills/kWh): 

8,479,127 

(62.21) 

7,829,760 

(64.55) 

7,829,760 

(64.55) 

Annual cost, 2008$: 

(mills/kWh): 

5,236,999 

(38.43) 

5,846,237 

(48.20) 

5,779,604 

(47.65) 

Annual net benefit, 2008$: 

(mills/kWh): 

3,242,128 

(23.79) 

1,983,523 

(16.35) 

2,050,156 

(16.90) 

420 
421 

4.9.1.1 No-Action Alternative 

Under the no-action alternative, Duke Energy would continue to operate the project under 

the terms and conditions of the existing license, and no new environmental protection, 

mitigation, or enhancement measures would be implemented. 

Based on the above information and an average annual generation of 136,290 MWh, the 

existing project has an annual power value of $8,479,127 and costs $5,236,999 annually to 

operate and maintain. This results in a net annual benefit of $3,242,128 (or $23.79/MWh). In 

other words, the project produces energy at a cost that is less than that of currently available 

alternative generation by $3,242,128 annually.

4.9.1.2 Applicant’s Proposal 

In its license application and CRA, filed on December 22, 2007, Duke Energy proposes 

numerous operational and non-operational measures. 

As proposed by Duke Energy, the Great Falls and Dearborn Developments would 

generate an average of 121,300 MWh of electricity annually, have an annual power value of 

$7,829,760 (64.55 mills/kWh), and total annual costs of $5,846,237 (48.20 mills/kWh). This 

results in a net annual benefit of $1,983,523 (16.35 mills/kWh). In other words, the project 

produces energy at a cost that is less than that of currently available alternative generation by 

$1,933,523 annually. 

4.9.1.3 Staff Alternative 

Resource agencies and nongovernmental organizations recommended the implementation 

of a variety of measures at the project. Staff reviewed each recommendation and determined 

which measures were the most appropriate for implementation. In section 5.0, Comprehensive 

Development and Recommended Alternative, we discuss our reasons for recommending the staff 

alternative and why we conclude that the environmental benefits are worth these costs. 

Tables 122 list these proposed measures and identifies the ones that were adopted by staff. 

The staff alternative would generate an average of 121,300 MWh of electricity annually, 

have an annual power value of $7,829,760 (64.55 mills/kWh), and have total annual costs of 

$5,779,604 (47.65 mills/kWh). This results in an annual net benefit of $2,050,156 

(16.90 mills/kWh). In other words, the project produces energy at a cost that is less than that of 

currently available alternative generation by $2,050,156 annually. The staff alternative would 

increase the net annual project benefit by about $66,633 ($0.55/MWh) compared to the project as 

proposed by Duke Energy. 

4.9.2 Cost of Environmental Measures 

Table 122 gives the cost of each of the environmental enhancement measures considered 

in our analysis. We convert all costs to equal annual (levelized) values over a 30-year period to 

give a uniform basis for comparing the benefits of a measure to its cost. All costs were adjusted 

from 2006$ to 2008$.
Table 122 Summary of capital, annual O&M, and annualized costs for environmental measures proposed by Du

by Staff for the Great Falls and Dearborn Developments for a 30-year license. (Source: Staff) 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

C

OperationsReservoir Level Control – Install flow compliance gage and provide maintenance Duke Energy 215,000 19,855 22,000 Drought Mitigation – Low inflow protocol administration Duke Energy 0 0 2,000 

Drought Mitigation – Water Management Group Dues Duke Energy 0 0 14,000 

Maintenance and Emergency Protocol Duke Energy 0 0 1,000 

Water Quality and Quantity

Monitoring and Compliance – Installation and maintenance of DO and groundwater monitors 

Duke Energy 108,000 9,974 55,000 

Aquatic Habitat Flows – Diversion Dam and Headworks Structural Modifications Duke Energy 3,376,000 311,780 20,000 Flow Mitigation – Mitigation Fund Duke Energy 200,000 18,470 0 

Flow Mitigation – Conservation Easements Duke Energy 168,000 15,515 0 

Fish, Wildlife, and Botanical ResourcesSpecies Protection Plans Duke Energy 12,000 1,108 8,000 1 Staff escalated those values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent (12/31/06 to 12/31/07), and 2

12/31/08) per year, respectively. The escalation rates were reported by the Department of Energy’s Cost Engineerin(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Various%20Years.xls).

422 
Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

C

Habitat Enhancement Fund Duke Energy 200,000 18,470 0 

Terrestrial Invasive Plant Species Management Plan Staff 3,000 277 150 

Cultural Resources

Historic Properties Management Plan – Annual HPMP review, signs, website, and materials 

Duke Energy 159,000 14,684 1,000 

Recreational ResourcesRecreation Management Plan Development Duke Energy 91,000 8,404 1,000 Recreation Use and Needs Update Duke Energy 45,000 4,156 0 

Recreation Enhancements Duke Energy 957,000 88,381 121,000 

Recreation Enhancements Duke Energy 212,000 19,578 0 

Recreation Enhancements Duke Energy 0 0 9,000 

Recreation Enhancements Staff 4,500 416 0 Public Information

Safety and Security – Signage Duke Energy 20,000 1,847 1,000 Safety and Security – Revise and implement safety plans Staff 38,500 3,556 1,000 Shoreline ManagementShoreline Management Plan Updates (every 10 years) Duke Energy 26,000 2,401 0 

423 
424 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

C

Shoreline Management Guidelines Updates (every 10 years) Duke Energy 8,000 738 0 Other EnhancementsLand Conservation Support Duke Energy 1,064,000 98,262 0 Trash Management/Safety Duke Energy 14,000 1,293 4,000 

Funding for Conservation Easements Duke Energy 300,000 27,706 0 
4.10 POWER AND ECONOMIC BENEFITS OF THE ROCKY CREEK AND CEDAR 

CREEK DEVELOPMENTS 

We base our analysis of this project’s net benefits on the economic information and 

parameters shown in Table 123. These values are common to all the licensing alternatives for 

the Rocky Creek and Cedar Creek Developments. All dollars are year 2008 unless specified 

otherwise. 

Table 123 Staff assumptions for the economic analysis of the Rocky Creek and Cedar Creek 

Developments. 

Parameter Value 

Period of analysis (years) 30 

Local Tax Rate (%)1 3.0 

Federal tax rate (%)2 32 

Insurance Rate (%)3 0.25 

Net investment(2008$)4 21,795,730 

Future major capital cost5 5,187,190 

Relicensing cost (2008$)6 3,679,753 

Operation and maintenance7 704,608 

Energy value (2008$/MWh)8 43.29 

Capacity value (2008$/kW-year)9 41.38 

Cost of Capital (%)10 8.5 

Discount rate (%)11 8.5 

1 Staff assumed a local tax rate of 3.0 percent. 

2 Staff assumed federal tax rate at 32 percent revenues. 

3 Staff assumed insurance rate equal to 0.25 percent of net investment. 

4 Net investment is the depreciated project investment allocated to power purposes and 

includes $24,076,918 (2006$) net plant investment for the existing facilities as reported by Duke 

Energy in exhibit D. 

5 Future major capital costs include implementation of measures to maintain present-day 

capability scheduled between 2008 and 2039 and are expressed as a present value. 

6 Relicensing costs include the administrative, legal/study, and other expenses to date. Staff 

has assumed total project relicensing cost $31,800,000 (2006$) is prorated by the average annual 

energy generation per project to determine the relicensing cost for each project. The Staff 

assumed relicensing cost for the Rocky Creek and Cedar Creek Developments in 2006$ is 

$3,417,143. 

7 Annual plant operation and maintenance costs reported by Duke are $654,323 (2006$). 

425 
8 Source: application for new license, exhibit D, page D-27, $40.20/MWh in 2006$. 

9 Source: application for new license, exhibit D, page D-27, $38.43/kW-year in 2006$. 

10 Based on Duke Energy’s weighted average cost of capital. Source: application for new 

license, exhibit D. 

11 Assumed by staff to be same as interest rate. 

Note: Staff escalated all 2006 values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent 

(12/31/06 to 12/31/07), and 2.3 percent (12/31/07 to 12/31/08) per year, respectively. The 

escalation rates were reported by the Department of Energy’s Cost Engineering Group 

(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Vari

ous%20Years.xls) 

As currently operated, the 56.6-MW Rocky Creek and Cedar Creek Developments 

generate an average of 154,910 MWh annually and have a dependable capacity of 56.6 MW. 

4.10.1 Comparison of Alternatives 

Table 124 summarizes the annual cost, power benefit, and annual net benefit for the three 

alternatives considered in this DEIS: no-action alternative, Duke Energy’s proposal, and the 

staff-recommended alternative. 

Table 124 Summary of the annual cost, power benefits, and annual net benefits for the three 

alternatives for the Rocky Creek and Cedar Creek Developments (Source: Staff). 

No action Duke Energy’s 

Proposal 

Staff-recommended 

alternative 

Installed capacity (MW) 56.6 56.6 56.6 

Annual generation 

(thousand MWh) 154.91 137.87 137.87 

Annual power value, 

2008$: 

(mills/kWh): 

9,048,162 

(58.41) 

8,310,500 

(60.28) 

8,310,500 

(60.28) 

Annual cost, 2008$: 

(mills/kWh): 

5,485,529 

(35.41) 

5,756,826 

(41.76) 

5,690,192 

(41.27) 

Annual net benefit, 2008$: 

(mills/kWh): 

3,562,633 

(23.00) 

2,553,675 

(18.52) 

2,620,308 

(19.01) 

4.10.1.1 No-Action Alternative 

 Under the no-action alternative, Duke Energy would continue to operate the 

project under the terms and conditions of the existing license, and no new environmental 

protection, mitigation, or enhancement measures would be implemented. 

426 
427 

Based on the above information and an average annual generation of 154,910 MWh, the 

existing project has an annual power value of $9,048,162 and costs $5,485,529 annually to 

operate and maintain. This results in a net annual benefit of $3,562,633 (or $23.00/MWh). In 

other words, the project produces energy at a cost that is less than that of currently available 

alternative generation by $3,562,633 annually.

4.10.1.2 Applicant’s Proposal 

In its license application and CRA, filed on December 22, 2007, Duke Energy proposes 

numerous operational and non-operational measures. 

As proposed by Duke Energy, the Rocky Creek and Cedar Creek Developments would 

generate an average of 137,870 MWh of electricity annually, have an annual power value of 

$8,310,500 (60.28 mills/kWh), and total annual costs of $5,756,826 (41.76 mills/kWh). This 

results in a net annual benefit of $2,553,675 (18.52 mills/kWh). In other words, the project 

produces energy at a cost that is less than that of currently available alternative generation by 

$2,553,675 annually.

4.10.1.3 Staff Alternative 

Resource agencies and nongovernmental organizations recommended the implementation 

of a variety of measures at the project. Staff reviewed each recommendation and determined 

which measures were the most appropriate for implementation. In section 5.0, Comprehensive 

Development and Recommended Alternative, we discuss our reasons for recommending the staff 

alternative and why we conclude that the environmental benefits are worth these costs. 

Table 125 list these proposed measures and identifies the ones that were adopted by staff. 

The staff alternative would generate an average of 137,870 MWh of electricity 

annually, have an annual power value of $8,310,500 (60.28 mills/kWh), and have total 

annual costs of $5,690,192 (41.27 mills/kWh). This results in an annual net benefit of 

$2,620,308 (19.01 mills/kWh). In other words, the project produces energy at a cost that is less 

than that of currently available alternative generation by $2,620,308 annually. The staff 

alternative would increase the net annual project benefit by about $66,633 ($0.49/MWh) 

compared to the project as proposed by Duke Energy. 

4.10.2 Cost of Environmental Measures 

Table 125 gives the cost of each of the environmental enhancement measures considered 

in our analysis. We convert all costs to equal annual (levelized) values over a 30-year period to 

give a uniform basis for comparing the benefits of a measure to its cost. All costs were adjusted 

from 2006$ to 2008$.
Table 125 Summary of capital, annual O&M, and annualized costs for environmental measures proposed by Duk

by Staff for the Rocky Creek and Cedar Creek Developments for a 30-year license. (Source: Staff) 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) T

C

OperationsDrought Mitigation – Low inflow protocol administration Duke Energy 0 0 2,000 Drought Mitigation – Water Management Group Dues Duke Energy 0 0 14,000 Maintenance and Emergency Protocol Duke Energy 0 0 1,000 

Water Quality and Quantity

Monitoring and Compliance – Installation and maintenance of DO and groundwater monitors 

Duke Energy 108,000 9,974 55,000 

Flow Mitigation – Mitigation Fund Duke Energy 200,000 18,470 0 

Fish, Wildlife, and Botanical Resources

Species Protection Plans Duke Energy 5,000 461 5,000 Habitat Enhancement Fund Duke Energy 200,000 18,470 0 

Terrestrial Invasive Plant Species Management Plan Staff 3,000 277 150 

Cultural Resources

Historic Properties Management Plan – Duke Energy 9,000 831 1,000 1 Staff escalated those values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent (12/31/06 to 12/31/07), and 2

12/31/08) per year, respectively. The escalation rates were reported by the Department of Energy’s Cost Engineerin(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Various%20Years.xls).

428 
429 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) T

C

Annual HPMP review, signs, website, and materials Recreational ResourcesRecreation Management Plan Development Duke Energy 91,000 8,404 1,000 Recreation Use and Needs Update Duke Energy 45,000 4,156 0 

Recreation Enhancements Duke Energy 1,473,000 136,034 20,000 

Recreation Enhancements Duke Energy 1,254,000 115,809 0 

Recreation Enhancements Duke Energy 0 0 9,000 

Recreation Enhancements Staff 4,500 416 0 Public Information

Safety and Security – Signage Duke Energy 20,000 1,847 1,000 Safety and Security – Revise and implement safety plans Staff 38,500 3,556 1,000 Shoreline ManagementShoreline Management Plan Updates (every 10 years) Duke Energy 26,000 2,401 0 Shoreline Management Guidelines Updates (every 10 years) Duke Energy 8,000 738 0 

Other Enhancements

Land Conservation Support Duke Energy 1,064,000 98,262 0 Trash Management/Safety Duke Energy 14,000 1,293 4,000 

Funding for Conservation Easements Duke Energy 300,000 27,706 0 
4.11 POWER AND ECONOMIC BENEFITS OF THE WATEREE DEVELOPMENT 

Table 126 summarizes the assumptions and economic information we use in our analysis. 

This information was provided by Duke Energy in its license application. We find that the 

values provided by Duke Energy are reasonable for the purposes of our analysis. Cost items 

common to all alternatives include: taxes and insurance costs; net investment (the total 

investment in power plant facilities remaining to be depreciated); relicensing costs; normal 

operation and maintenance cost; and Commission fees. All dollars are year 2008 unless 

specified otherwise. 

Table 126 Staff assumptions for the economic analysis of the Wateree Development. 

Parameter Value 

Period of analysis (years) 30 

Local Tax Rate (%)1 3.0 

Federal tax rate (%)2 32 

Insurance Rate (%)3 0.25 

Net investment(2008$)4 33,106,816 

Future major capital cost5 26,208,390 

Relicensing cost (2008$)6 5,541,307 

Operation and maintenance7 962,347 

Energy value (2008$/MWh)8 43.29 

Capacity value (2008$/kW-year)9 38.83 

Cost of Capital (%)10 8.5 

Discount rate (%)11 8.5 

1 Staff assumed a local tax rate of 3.0 percent. 

2 Staff assumed federal tax rate at 32 percent revenues. 

3 Staff assumed insurance rate equal to 0.25 percent of net investment. 

4 Net investment is the depreciated project investment allocated to power purposes and 

includes $36,410,989 (2006$) net plant investment for the existing facilities as reported by Duke 

Energy in exhibit D. 

5 Future major capital costs include implementation of measures to maintain present-day 

capability scheduled between 2008 and 2039 and are expressed as a present value. 

6 Relicensing costs include the administrative, legal/study, and other expenses to date. Staff 

has assumed total project relicensing cost $31,800,000 (2006$) is prorated by the average annual 

energy generation per project to determine the relicensing cost for each project. The Staff 

assumed relicensing cost for the Wateree Development in 2006$ is $5,145,845. 

7 Annual plant operation and maintenance costs reported by Duke are $893,668 (2006$). 

430 
8 Source: application for new license, exhibit D, page D-27, $40.20/MWh in 2006$. 

9 Source: application for new license, exhibit D, page D-27, $36.06/kW-year in 2006$. 

10 Based on Duke Energy’s weighted average cost of capital. Source: application for new 

license, exhibit D. 

11 Assumed by staff to be same as interest rate. 

Note: Staff escalated all 2006 values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent 

(12/31/06 to 12/31/07), and 2.3 percent (12/31/07 to 12/31/08) per year, respectively. The 

escalation rates were reported by the Department of Energy’s Cost Engineering Group 

(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Vari

ous%20Years.xls) 

As currently operated, the 88.5-MW Wateree Development generates an average of 

233,280 MWh annually and has a dependable capacity of 88.5 MW. 

4.11.1 Comparison of Alternatives 

Table 127 summarizes the annual cost, power benefit, and annual net benefit for the three 

alternatives considered in this DEIS: no-action alternative, Duke Energy’s proposal, and the 

staff-recommended alternative. 

Table 127 Summary of the annual cost, power benefits, and annual net benefits for the three 

alternatives for the Wateree Development (Source: Staff). 

No action Duke Energy’s 

Proposal 

Staff-recommended 

alternative 

Installed capacity (MW) 88.5 88.5 88.5 

Annual generation (thousand 

MWh) 233.28 207.62 207.62 

Annual power value 2008$: 

(mills/kWh): 

13,514,151 

(57.93) 

12,405,639 

(59.75) 

12,405,639 

(59.75) 

Annual cost2008$: 

(mills/kWh): 

8,181,437 

(35.07) 

10,139,869 

(48.84) 

9,905,480 

(47.71) 

Annual net benefit2008$: 

(mills/kWh): 

5,332,714 

(22.86) 

2,265,770 

(10.91) 

2,500,159 

(12.04) 

4.11.1.1 No-Action Alternative 

Under the no-action alternative, Duke Energy would continue to operate the project under 

the terms and conditions of the existing license, and no new environmental protection, 

mitigation, or enhancement measures would be implemented. 

431 
432 

Based on the above information and an average annual generation of 233,280 MWh, the 

existing project has an annual power value of $13,514,151 and costs $8,181,437 annually to 

operate and maintain. This results in a net annual benefit of $5,332,714 (or $22.86/MWh). In 

other words, the project produces energy at a cost that is less than that of currently available 

alternative generation by $5,332,714 annually.

4.11.1.2 Applicant’s Proposal 

In its license application and CRA, filed on December 22, 2007, Duke Energy proposes 

numerous operational and non-operational measures. 

As proposed by Duke Energy, the Wateree Development would generate an average 

of 207,620 MWh of electricity annually, have an annual power value of $12,405,639 

(59.75 mills/kWh), and total annual costs of $10,139,869 (48.84 mills/kWh). This results in a 

net annual benefit of $2,265,770 (10.91 mills/kWh). In other words, the project produces energy 

at a cost that is less than that of currently available alternative generation by $2,265,770 

annually. 

4.11.1.3 Staff Alternative 

Resource agencies and nongovernmental organizations recommended the implementation 

of a variety of measures at the project. Staff reviewed each recommendation and determined 

which measures were the most appropriate for implementation. In section 5.0, Comprehensive 

Development and Recommended Alternative, we discuss our reasons for recommending the staff 

alternative and why we conclude that the environmental benefits are worth these costs. 

Table 128 list these proposed measures and identifies the ones that were adopted by staff. 

The staff alternative would generate an average of 207,620 MWh of electricity 

annually, have an annual power value of $12,405,639 (59.75 mills/kWh), and have total 

annual costs of $9,905,480 (47.71 mills/kWh). This results in an annual net benefit of 

$2,500,159 (12.04 mills/kWh). In other words, the project produces energy at a cost that is less 

than that of currently available alternative generation by $2,500,159 annually. The staff 

alternative would increase the net annual project benefit by about $234,389 ($1.13/MWh) 

compared to the project as proposed by Duke Energy. 

4.11.2 Cost of Environmental Measures 

Table 128 gives the cost of each of the environmental enhancement measures considered 

in our analysis. We convert all costs to equal annual (levelized) values over a 30-year period to 

give a uniform basis for comparing the benefits of a measure to its cost. All costs were adjusted 

from 2006$ to 2008$. 
Table 128 Summary of capital, annual O&M, and annualized costs for environmental measures proposed by Du

by Staff for the Wateree Development for a 30-year license. (Source: Staff) 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

C

OperationsReservoir Level Stabilization (Spring Lake Stabilization) Duke Energy 0 0 1,000 Drought Mitigation – Low inflow protocol administration Duke Energy 0 0 2,000 

Drought Mitigation – Water Management Group Dues Duke Energy 0 0 14,000 

Maintenance and Emergency Protocol Duke Energy 0 0 1,000 

Flow and Reservoir Elevation Monitoring – USGS gage installation and maintenance Duke Energy 0 0 30,000 Water Quality and Quantity

Monitoring and Compliance – Installation and maintenance of DO and groundwater monitors Duke Energy 108,000 9,974 55,000 Water Quality Enhancement – minimum flow unit with aerating runner Duke Energy 4,045,000 373,563 12,000 Flow Mitigation – Conservation Easements Duke Energy 168,000 15,515 0 

Flow Mitigation – Mitigation Fund Duke Energy 200,000 18,470 0 

1 Staff escalated those values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent (12/31/06 to 12/31/07), and 2

12/31/08) per year, respectively. The escalation rates were reported by the Department of Energy’s Cost Engineerin(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Various%20Years.xls).

433 
Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

C

Fish, Wildlife, and Botanical Resources

Species Protection Plans Duke Energy 15,000 1,385 8,000 Habitat Enhancement Fund Duke Energy 200,000 18,470 0 

Terrestrial Invasive Plant Species Management Plan 

Staff 3,000 277 150 

Cultural Resources

Historic Properties Management Plan – Annual HPMP review, signs, website, and materials Duke Energy 9,000 831 1,000 Historic Properties Management Plan – Archaeological Site Data Recovery, Site Monitoring, and Plan 

Duke Energy 540,000 49,870 0 

Recreational ResourcesRecreation Management Plan Development Duke Energy 91,000 8,404 1,000 Recreation Use and Needs Update Duke Energy 45,000 4,156 0 

Recreation Enhancements Duke Energy 2,580,000 238,267 63,000 

Recreation Enhancements Duke Energy 6,712,000 619,864 0 

Recreation Enhancements Duke Energy 0 0 9,000 

Recreation Enhancements Staff 4,500 416 0 Public Information

Recreation Flow Communication – Develop and Maintain Systems Duke Energy 20,000 1,847 5,000 Safety and Security – Signage Duke Energy 10,000 924 1,000 

434 
435 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) To

(L

C

Safety and Security – Revise and implement safety plans Staff 28,500 2,632 1,000 Shoreline ManagementShoreline Management Plan Updates (every 10 years) Duke Energy 26,000 2,401 0 Shoreline Management Guidelines Updates (every 10 years) Duke Energy 8,000 738 0 Other Enhancements Land Conservation Support Duke Energy 1,064,000 98,262 0 Trash Management/Safety Duke Energy 14,000 1,293 4,000 

Funding for Conservation Easements Duke Energy 300,000 27,706 0 

Conservation Easements -67 Duke Energy 503,000 46,453 0 

Flood Management at Wateree Duke Energy 7,680,000 709,261 0 

Flood Management at Wateree Staff 6,000,000 554,110 0 
4.12 POWER AND ECONOMIC BENEFITS OF THE CATAWBA-WATEREE 

PROJECT 

Table 129 summarizes the assumptions and economic information we use in our analysis. 

This information was provided by Duke Energy in its license application. We find that the 

values provided by Duke Energy are reasonable for the purposes of our analysis. Cost items 

common to all alternatives include: taxes and insurance costs; net investment (the total 

investment in power plant facilities remaining to be depreciated); estimated future capital 

investment required to maintain and extend the life of plant equipment and facilities; relicensing 

costs; normal operation and maintenance cost; and Commission fees. All dollars are year 2008 

unless specified otherwise. 

Table 129 Staff assumptions for the economic analysis of the Catawba-Wateree Project. 

Parameter Value 

Period of analysis (years) 30 

Local Tax Rate (%)1 3.0 

Federal tax rate (%)2 32 

Insurance Rate (%)3 0.25 

Net investment(2008$)4 244,464,467 

Future major capital cost (2008$)5 115,435,160 

Relicensing cost (2008$)6 34,243,853 

Operation and maintenance (2008$)7 10,966,206 

Energy value (2008$/MWh)8 43.20 

Capacity value (2008$/kW-year)9 22.64 

Cost of Capital (%)10 8.5 

Discount rate (%)11 8.5 

1 Staff assumed a local tax rate of 3.0 percent. 

2 Staff assumed federal tax rate at 32 percent revenues. 

3 Staff assumed insurance rate equal to 0.25 percent of net investment. 

4 Net investment is the depreciated project investment allocated to power purposes and 

includes $270,553,226 (2006$) net plant investment for the existing facilities, as reported by 

Duke Energy in exhibit D. 

5 Future major capital costs include implementation of measures to maintain present-day 

capability scheduled between 2008 and 2039 and are expressed as a present value. 

6 Relicensing costs include the administrative, legal/study, and other expenses to date. As 

reported by Duke the cost for relicensing Catawba-Wateree is $31,800,000 (2006$). 

7 Annual plant operation and maintenance costs reported by Duke are $10,183,590 (2006$).

436 
8 Source: application for new license, exhibit D, page D-27, $40.12/MWh in 2006$. 

9 Source: application for new license, exhibit D, page D-27, $21.02/kW-year in 2006$. 

10 Based on Duke Energy’s weighted average cost of capital. Source: application for new 

license, exhibit D. 

11 Assumed by staff to be same as interest rate. 

Note: Staff escalated all 2006 values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent 

(12/31/06 to 12/31/07), and 2.3 percent (12/31/07 to 12/31/08) per year, respectively. The 

escalation rates were reported by the Department of Energy’s Cost Engineering Group 

(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Vari

ous%20Years.xls) 

As currently operated, the 923.8-MW Bridgewater Development generates an average of 

1,441,590 MWh annually and has a dependable capacity of 921.90 MW. 

4.12.1 Comparison of Alternatives 

Table 130 summarizes the combined annual cost, power benefit, and annual net benefit of 

the alternatives considered in this DEIS for all eleven of the hydroelectric developments in the 

Catawba-Wateree Project. The power benefit in Table 130 is the combined annual value of the 

energy generation and capacity value for the Bridgewater Development. 

Table 130 Summary of the annual cost, power benefits, and annual net benefits for the three 

alternatives for the Catawba-Wateree Project (Source: Staff). 

No action Duke Energy’s 

Proposal 

Staff-recommended 

alternative 

Installed capacity (MW) 923.80 923.80 923.80 

Annual generation (thousand 

MWh) 1,441.59 1,283.01 1,283.01 

Annual power value, 2008$: 

(mills/kWh): 

83,148,504 

(57.68) 

76,297,848 

(59.47) 

76,297,848 

(59.47) 

Annual cost, 2008$: 

(mills/kWh): 

57,159,248 

(39.65) 

66,068,715 

(51.50) 

63,089,564 

(49.17) 

Annual net benefit, 2008$: 

(mills/kWh): 

25,989,256 

(18.03) 

10,229,133 

(7.97) 

13,208,284 

(10.29) 

4.12.1 No-Action Alternative 

Under the no-action alternative, Duke Energy would continue to operate as it does now. 

The project generates an average of 1,441,590 MWh of electricity annually. The average annual 

power value would be $83,148,504 (57.68/MWh). The average annual cost of producing this 

power would be $57,159,248 (39.65/MWh), resulting in a net annual benefit of $25,989,256 

437 
438 

(18.03/MWh). In other words, the project produces energy at a cost that is less than that of 

currently available alternative generation by $25,989,256 annually. 

4.12.2 Applicant’s Proposal 

As discussed in the previous sections for each of the hydroelectric development in the 

Catawba-Wateree Project, Duke Energy proposes numerous operational and non-operational 

measures. As proposed by Duke Energy, all of the developments in the Catawba-Wateree 

Project would generate a combined average of 1,283,010 MWh of electricity annually, have an 

annual power value of $76,297,848, and total annual costs of $66,068,715, resulting in a net 

annual benefit of negative $10,229,133 (7.97 mills/kWh). In other words, the project produces 

energy at a cost that is less than that of currently available alternative generation by $10,229,133 

annually. 

4.12.3 Staff Alternative 

The staff alternative would generate an average of 1,283,010 MWh of electricity 

annually, have an annual power value of $76,297,848 (59.47 mills/kWh) and have total annual 

costs of $63,089,564 (49.17 mills/kWh). This results in an annual net benefit of $13,208,284 

(10.29 mills/kWh). In other words, the project produces energy at a cost that is less than that of 

currently available alternative generation by $13,208,284 annually. 

4.12.4 Cost of Environmental Measures 

Table 131 summarizes the cost of each of the environmental enhancement measures 

considered in our analysis. We convert all costs to equal annual (levelized) values over a 30-

year period to give a uniform basis for comparing the benefits of a measure to its cost. All costs 

were adjusted from 2006$ to 2008$. 
Table 131 Summary of capital, annual O&M, and annualized costs for environmental measures proposed by Du

by Staff for the Catawba-Wateree Project for a 30-year license. (Source: Staff) 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) Tot

(L

cos

OperationsReservoir Level Control – Install flow compliance gage and provide maintenance 

Duke Energy 539,000 49,777 55,000 1

Reservoir Level Stabilization (Spring Lake Stabilization) 

Duke Energy 0 0 4,000 

Drought Mitigation – Low inflow protocol administration 

Duke Energy 0 0 22,000 

Drought Mitigation – Water Management Group Dues 

Duke Energy 0 0 154,000 1

Maintenance and Emergency Protocol Duke Energy 0 0 11,000 

Flow and Reservoir Elevation Monitoring - USGS gage maintenance 

Duke Energy 21,000 1,939 120,000 1

Water Quality and Quantity

Monitoring and Compliance – Installation and maintenance of DO and groundwater monitors 

Duke Energy 1,188,000 109,714 605,000 7

Water Quality Enhancement – Aerating Runners, bypass Flow Valve, Diversion Dam 

Duke Energy 18,943,000 1,749,418 60,000 1

1 Staff escalated those values to 2008 by 2.0 percent (12/31/05 to 12/31/06), 3.2 percent (12/31/06 to 12/31/07), and 2

12/31/08) per year, respectively. The escalation rates were reported by the Department of Energy’s Cost Engineerin(http://www.oecm.energy.gov/Portals/2/Inflators%20to%20Constant%20Dollars%20for%20Various%20Years.xls).

439 
Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) Tot

(L

cos

and Headworks Modification Flow Mitigation - Conservation Easements Duke Energy 3,076,000 284,074 0 2

Flow Mitigation - Mitigation Fund Duke Energy 1,000,000 92,352 0 

Fish, Wildlife, and Botanical Resources

Species Protection Plans Duke Energy 104,000 9,604 65,000 Terrestrial Invasive Plant Species Management Plan 

Staff 33,000 3,048 1,650 

Cultural ResourcesHistoric Properties Management Plan – Annual HPMP review, signs, website, and materials 

Duke Energy 798,000 73,697 37,000 1

Recreational ResourcesRecreation Management Plan Development Duke Energy 1,000,000 92,352 11,000 1Recreation Use and Needs Update Duke Energy 495,000 45,714 0 

Recreation Enhancements Duke Energy 24,182,000 2,233,248 948,000 3Recreation Enhancements Duke Energy 25,023,000 2,310,917 0 2

Recreation Enhancements Staff 2,523,500 233,049 22,600 2

Public Information

Recreation Flow Communication – Develop and Maintain Systems 

Duke Energy 100,000 9,236 25,000 

Safety and Security – Signage and Warning Duke Energy 150,000 13,853 11,000 

Safety and Security – Device Modification Duke Energy 30,000 2,771 0 

440 
441 

Mitigation measure Recommending entities Capital costs (2006$)1 Annualized capital costs (2008$) Annualized O&M (2008$) Tot

(L

cos

Safety and Security – Warning Device Installation 

Duke Energy 150,000 13,853 11,000 

Safety and Security – Revise and implement safety plans 

Staff 573,500 52,963 11,000 

Shoreline Management

Shoreline Management Plan Review Duke Energy 0 0 11,000 Shoreline Management Plan Updates (every 10 years) 

Duke Energy 286,000 26,413 0 

Shoreline Management Guidelines Updates (every 10 years) 

Duke Energy 88,000 8,127 0 

Other Enhancements 

Land Conservation Support Duke Energy 9,322,000 860,902 0 8Trash Management/Safety Duke Energy 154,000 1,293 4,000 

Trash Rake Duke Energy 1,200,000 110,822 0 1

Funding for Conservation Easements Duke Energy 4,125,000 380,951 0 3

Funding for Conservation Easements – 67 Duke Energy 503,000 46,453 0 

Flood Management at Wateree Duke Energy 7,680,000 709,261 0 7

Flood Management at Wateree – Bladder Dam 

Staff 6,000,000 554,110 0 5
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