The Duke Energy Carolinas 

Integrated Resource Plan 

(Annual Report) 

September 1, 2012 

Public
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TABLE OF CONTENTS 

ABBREVIATIONS 3 

FORWARD 5 

1. EXECUTIVE SUMMARY 7

 Changes from the 2011 IRP 7 

 Overview of Planning Process Results 10

2. SYSTEM OVERVIEW, OBJECTIVES AND PROCESS 17 

 A. System Overview 17 

 B. Objectives 19 

 C. Planning Process 19 

3. ELECTRIC LOAD FORECAST 21 

4. ENERGY EFFICIENCY and DEMAND-SIDE MANAGEMENT 29 

5. SUPPLY-SIDE RESOURCES 43 

 A. Existing Generation Plants in Service 43 

 B. Renewable Resources and Renewable Energy Initiatives 59 

 C. Supply Side Resource Screening 63 

 D. Wholesale and QF Purchased Power Agreements 69 

6. ENVIRONMENTAL COMPLIANCE 73 

7. ELECTRIC TRANSMISSION FORECAST 82 

 A. Transmission System Adequacy 82 

 B. Transmission System Emerging Issues 83

8. SELECTION AND IMPLEMENTATION OF THE PLAN 85

 A. Resource Needs Assessment (Future State) 85 

 B. Overall Planning Process Conclusions 89

APPENDIX A: Quantitative Analysis 101 

APPENDIX B: Electric Load Forecast 113

APPENDIX C: Supply Side Screening 144 

APPENDIX D: Demand Side Management Activation History 148 

APPENDIX E: Proposed Generating Units 153 
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APPENDIX F: Transmission Planned or Under Construction Facilities 154 

APPENDIX G: Economic Development 167 

APPENDIX H: Non-Utility Generation 168 

APPENDIX I: Wholesale 178 

APPENDIX J: Carbon Neutral Plan 180 

APPENDIX K: NCUC Orders 185 

APPENDIX L: Cross-Reference to Duke Energy Carolinas 2012 IRP 196 
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Integrated Resource Plan – abbreviations 

Carbon Dioxide CO2

Central Electric Power Cooperative, Inc. CEPCI 

Certificate of Public Convenience and Necessity CPCN 

Clean Air Interstate Rule CAIR 

Clean Air Mercury Rule CAMR 

Coal Combustion Residuals CCR 

Combined Construction and Operating License COL 

Combined Cycle CC 

Combustion Turbines CTs 

Commercial Operation Date COD 

Compact Fluorescent Light bulbs CFL 

Cross State Air Pollution Rule CSAPR 

Demand Side Management DSM 

Direct Current DC 

Duke Energy Annual Plan The Plan 

Duke Energy Carolinas DEC 

Duke Energy Carolinas The Company 

Eastern Interconnection Planning Collaborative EIPC

Electric Membership Corporation EMC 

Electric Power Research Institute EPRI 

Energy Efficiency EE 

Environmental Protection Agency EPA 

Federal Energy Regulatory Commission FERC 

Federal Loan Guarantee FLG 

Flue Gas Desulphurization FGD 

General Electric GE 

Greenhouse Gas GHG 

Heating, Ventilation and Air Conditioning HVAC 

Information Collection Request ICR 

Integrated Gasification Combined Cycle IGCC 

Integrated Resource Plan IRP 

Interruptible Service IS 

Load, Capacity, and Reserve Margin Table LCR Table 

Maximum Achievable Control Technology MACT 

Nantahala Power & Light NP&L 

National Ambient Air Quality Standards NAAQS 

National Pollutant Discharge Elimination System NPDES 

NC Department of Environment and Natural Resources NCDENR 

NC Green Power NCGP 

New Source Performance Standard NSPS 

Nitrogen Oxide NOx

North American Electric Reliability Corp NERC 

North Carolina NC 

North Carolina Clean Smokestacks Act NCCSA 

North Carolina Division of Air Quality NCDAQ 

North Carolina Electric Membership Corporation NCEMC 

North Carolina Municipal Power Agency #1 NCMPA1 
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Integrated Resource Plan – abbreviations 

North Carolina Utilities Commission NCUC 

Notice of Proposed Rulemaking NOPR 

Nuclear Regulatory Commission NRC 

Palmetto Clean Energy PaCE 

Parts Per Billion PPB 

Photovoltaic PV 

Piedmont Municipal Power Agency PMPA 

Plug-In Electric Vehicles PEV 

Power Delivery PD 

Present Value Revenue Requirements PVRR 

Prevention of Significant Deterioration PSD 

Public Service Commission of South Carolina PSCSC 

Purchase Power Agreement PPA 

Qualifying Facility QF 

Rate Impact Measure RIM 

Renewable Energy and Energy Efficiency Portfolio Standard REPS 

Renewable Energy Certificates REC 

Renewable Portfolio Standard RPS 

Request for Proposal RFP 

Resource Conservation Recovery Act RCRA 

Saluda River Electric Cooperative SR 

Selective Catalytic Reduction SCR 

SERC Reliability Corporation SERC 

South Carolina SC 

Southeastern Power Administration SEPA 

Standby Generation SG 

State Implementation Plan SIP 

Sulfur Dioxide SO2

Technology Assessment Guide TAG 

Total Resource Cost TRC 

United States Department of Energy USDOE 

Utility Cost Test UCT 

Virginia/Carolinas VACAR 

Volt Ampere Reactive VAR 

Western Carolina University WCU 
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FOREWARD 

This Integrated Resource Plan (IRP) is the third biennial report filed by Duke Energy 

Carolinas, LLC (Duke Energy Carolinas or the Company) under the revised Commission 

Rule R8-60. A cross reference identifying the location of each regulatory requirement within 

this IRP is provided in Appendix L. 

Due to the timing of the Duke Energy Corporation and Progress Energy Corporation merger 

closing, Duke Energy Carolinas and Progress Energy Carolinas, Inc. (PEC) were not able to 

coordinate their respective 2012 IRP filings. Input assumptions such as fuel prices, 

environmental inputs, and generation costs, as well as sensitivities and scenarios were 

developed independently. Assumptions around key inputs such as Energy Efficiency (EE), 

Demand Side Management (DSM), renewable resources and carbon dioxide (CO2) regulation 

costs will be reconciled in the next planning cycle. Neither Duke Energy Carolinas nor PEC 

has included any consideration of joint planning of new build capacity or the sharing of 

existing capacity between the operating companies for the purposes of meeting this capacity 

need in their respective 2012 IRPs. 

Post-merger review of the Duke Energy Carolinas and PEC 2012 IRP results indicate 

common themes, such as the inclusion of additional natural gas generation, the viability of 

regional nuclear projects to meet future capacity needs, and the commitment to meet the 

North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (NC REPS) 

requirements. 

The North Carolina Utilities Commission (NCUC) issued three orders since the filing of the 

2011 Duke Energy Carolinas IRP that require Duke Energy Carolinas to address certain new 

requirements in the 2012 IRP. An outline of the three orders and specific requirements are 

shown below. 

Pursuant to its October 26, 2011 Order Approving 2010 Biennial Integrated Resource Plans 

and 2010 REPS Compliance Plans, the NCUC set forth new requirements listed below: 

• Duke Energy Carolinas and PEC should each prepare a comprehensive reserve 

margin requirements study and include the results of such study as part of their 2012 

biennial IRPs; 

• Each IOU and EMC should investigate the value of activating DSM resources during 

times of high system load as a means of achieving lower fuel costs by not having to 

dispatch peaking units with their associated higher fuel costs if it is less expensive to 

activate DSM resources; and 

• Each electric utility should use appropriately updated DSM/EE market potential 

studies. 

Pursuant to its May 30, 2012 Order Approving 2011 Annual Updates to the 2010 Biennial 

Integrated Resource Plan and 2011 REPS Compliance Plans, the NCUC set forth new 

requirements listed below. 
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• Each IOU shall include a discussion of variance of 10% or more in projected Energy 

Efficiency savings from one IRP report to the next; and 

• Each IOU shall include a discussion of the status of market potential studies or 

updates in their 2012 and future IRPs. 

Finally, pursuant to its April 11, 2012 Order Amending Commission Rule R8-60 and 

Adopting Commission Rule R8-60.1 in the Matter of Integrated Resource Planning in North 

Carolina addressing Smart Grid Technology Plans, the NCUC set forth the requirements 

listed below. 

• Smart Grid Impacts – Each utility shall provide information regarding the impacts of 

its smart grid deployment plan on the overall IRP. 

• The Smart Grid Technology Plan – By July 1, 2013 and every two years thereafter, 

each utility subject to Rule R8-60 shall file with the Commission its smart grid 

technology plan. Significant amendments or revisions to a smart grid technology 

plan shall be reported to the commission in each year in which the biennial smart grid 

technology plan is not required to be filed. 

Each of these requirements is addressed the Company’s IRP. 
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1. EXECUTIVE SUMMARY 

Duke Energy Carolinas, a subsidiary of Duke Energy Corporation, utilizes an integrated 

resource planning approach to ensure that it can reliably and economically meet the electric 

energy needs of its customers well into the future. Duke Energy Carolinas considers a 

diverse range of resources to meet such future energy needs including renewable, nuclear, 

coal, gas, EE, and DSM1 resources. 

Consistent with its responsibility to meet customer energy needs in a way that is affordable, 

reliable, and clean, the Company’s resource planning approach includes both quantitative 

analysis and qualitative considerations. Quantitative analysis provides insights on future 

risks and uncertainties associated with fuel prices, load growth rates, capital and operating 

costs, and other variables. Qualitative perspectives, such as the importance of fuel diversity, 

the Company’s environmental profile, the emergence and development of new technologies, 

and regional economic development considerations are also important factors to consider as 

the Company makes long-term decisions regarding new resources to serve its customers. 

Company management utilizes all of these qualitative perspectives in conjunction with its 

quantitative analyses to ensure that Duke Energy Carolinas will meet near-term and longterm customer needs, while maintaining the operational flexibility to adjust to evolving 

economic, environmental, and operating circumstances in the future. As a result, the 

Company’s plan is designed to be robust under many possible future scenarios. 

Changes from the 2011 IRP 

The notable changes from the 2011 IRP to the 2012 IRP are (1) a shift in the Company’s first 

capacity need from 2015 to 2016 and (2) lower projected fundamental natural gas prices 

throughout the planning horizon. 

The shift of the Duke Energy Carolinas’ first capacity need from 2015 to 2016 is primarily 

due to lower forecasted load projections, an increase in projected capacity and energy 

purchases from qualifying facilities (QF) pursuant to the requirements of the Public Utility 

Regulatory Policy Act of 1978 (PURPA), an increase in projected participation in DSM 

programs, a lower planning reserve margin, as well as changes in the Company’s projected 

compliance portfolio relating to the NC REPS. These factors, taken together, result in the 

Company’s first new resource need of 410 MWs in 2016. Each of these contributing factors 

is discussed in greater detail below: 

1

 Throughout this IRP, the term EE will denote conservation programs while the term DSM will denote Demand 

Response programs, consistent with the language of N.C. Gen. Stat. 62-133.8 and 133.9. 
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• Lower Forecasted Load Projection - Short term lower load growth projections in 

the residential and commercial sectors and long term increases in EE projections are 

driving the lower forecasted Company load projections. 

• Increase in Projected QFs - The increase in projected QF capacity and energy arises 

from the potential addition of new solar QF facilities and due to the renewal of the 88 

MW Cherokee Co-Generation QF contract. The Cherokee contract was due to expire 

in 2013, but has now been extended through 2020. The increase in projected solar QF 

facilities not only affects the capacity need, but also impacts the Company’s NC 

REPS compliance strategy. 

• Increase in the Projected DSM Implementation - The Company is also projecting 

additional DSM implementation in the 2012 IRP because the final Environmental 

Protection Agency (EPA) Reciprocating Internal Combustion Engine (RICE) rule, 

which limits hours of non-emergency operation of emergency generators located at 

commercial and industrial facilities, was not as stringent as the original proposed rule 

from 2011. Also, the projected impacts of Distribution Automation, which provides 

the ability to reduce line voltage during periods of peak demand, have been 

incorporated in the DSM program. Distribution Automation is a part of the Duke 

Energy Carolinas Grid Modernization program. The projected increases in DSM 

impacts result in a corresponding 60 MW decrease in our customers’ capacity needs 

by 2015. 

• Increase in the Projected Renewables - The Company’s analysis reflects a shift in 

strategy for NC REPS compliance over the long term. In the 2011 IRP, the NC REPS 

compliance strategy relied primarily on wind and biomass resources during the first 

10 years and a shift to primarily biomass resources for the remainder of the planning 

period. Based upon the increase in recent proposals for solar QF facilities, for the 

2012 IRP, the Company’s strategy has shifted from a reliance on biomass to a greater 

reliance on solar resources. Even though solar facilities have a lower contribution to 

the Company’s peak than biomass resources, the projected increase in volume of 

solar QFs results in a net increase of renewable resources available to meet peak 

demand requirements in 2015 of approximately 40 MWs. 

• Lower Planning Reserve Margin - As part of the NCUC's approval of the utilities’

respective 2010 IRPs, Duke Energy Carolinas and PEC were ordered to perform 

a quantitative analysis of the respective reserve margins and to provide the study 

results in the companies' 2012 IRPs. Based on the results of this analysis, Duke 

Energy Carolinas utilized a target Planning Reserve margin of 15.5% in the 2012 
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IRP. This is a reduction from a 17% target Planning Reserve margin used in the 2011 

IRP, which resulted in approximately 200 MWs of reduced capacity need in 2015. 

The second major change from the 2011 IRP to the 2012 IRP is that anticipated lower natural 

gas prices drove the selection of additional combined cycle generation rather than additional 

combustion turbine generation throughout the 20-year planning period. For example, the 

2012 IRP found that the 2016 resource need would be served most cost-effectively by 

combined cycle resources instead of by the combustion turbine resources identified in the 

2011 IRP. 

Other important factors impacting the 2012 IRP: 

As outlined below, a number of additional environmental and economic factors influence the 

Company’s long-term resource plan. 

• Greenhouse Gas Regulation or Legislation - Greenhouse gas (GHG) regulations or 

legislation also have the potential to impact the Company’s resource planning. From 

2007 to 2009, multiple GHG cap and trade bills were introduced in Congress. More 

recently, Clean Energy Standards (CES) have been discussed in lieu of cap and trade 

legislation or regulation. A CES would require that a certain percentage (e.g. 10% in 

2015 escalating up to 30% in 2030) of a utility’s retail sales be met with combined 

cycle (CC) natural gas, nuclear, EE, or renewable energy. At present, the Company 

does not anticipate that Congress will consider GHG legislation before the end of 

2012. Beyond 2012, the prospects for possible enactment of any legislation 

mandating reductions in GHG emissions are highly uncertain. Although the 

Company continues to believe that Congress will eventually adopt some form of 

mandatory GHG emission reduction or Clean Energy legislation, the timing and form 

of any such legislation remains highly uncertain. 

• EPA GHG Regulation - In the absence of federal GHG or Clean Energy legislation, 

the EPA continues to pursue GHG regulations on new and existing units. In 2011, 

EPA promulgated its Tailoring Rule for existing fossil-fired generating units which 

sets the emission thresholds to 75,000 tons/year of CO2 for determining when a 

source is potentially subject to Prevention of Significant Deterioration (PSD) 

permitting for GHGs. Also in 2012, the EPA proposed a rule to establish GHG new 

source performance standards (NSPS) for new pulverized coal and natural gas units. 

If finalized as proposed, the GHG NSPS would effectively preclude construction of 

new pulverized coal units because the standards were set at a level requiring carbon 

capture and storage (CCS) technology. New natural gas combined cycle facilities 

will be able to meet the proposed standard without CCS technology. The future 
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impacts of these EPA regulations are uncertain at this time, and there are presently no 

cost-effective and demonstrated controls for CO2 for new or existing fossil units. Due 

to the EPA’s continued pursuit of GHG regulation in absence of GHG legislation, the 

Company believes that it is prudent to continue to plan for a carbon-constrained 

future. To address this uncertainty, the Company has evaluated a range of CO2

prices, in addition to potential Clean Energy legislation. 

 

• Impact of Lower Natural Gas Prices - Despite the lower projected natural gas 

prices, on a long-term basis, Duke Energy Carolinas’ analysis continues to support a 

robust portfolio including new nuclear, CC, and CT generation resources. Thus, in 

the 2012 IRP, portfolios consisting of new nuclear and gas generation remain 

competitive with portfolios where all intermediate and base load needs are met with 

natural gas resources. Without new nuclear generation, CO2 emissions for the natural 

gas portfolio are projected to continue to rise throughout the planning period. In 

addition, the Company’s fundamental natural gas prices were developed assuming 

continued operation of the nation’s existing nuclear fleet. The operating licenses of 

many of the country’s existing nuclear units have already been extended and will 

expire within the planning horizon. If these units are replaced with natural gas 

resources, the result would be a projected increase in natural gas prices, which would 

impact the cost-effectiveness of both future natural gas and new nuclear generation. 

As discussed above, although GHG legislation is not believed to be imminent, the 

EPA continues to pursue CO2 regulations on existing and new generation units, which 

will also impact the future cost for any CO2-emitting generation. For these reasons, 

among others, the Company believes it is prudent to continue to preserve the option 

for new nuclear generation in combination with new CC and CT resources. 

Overview of Planning Process Results 

Duke Energy Carolinas’ generation resource needs increase significantly over the 20-year 

planning horizon of the 2012 IRP. Cliffside Unit 6, the Buck and Dan River natural gas CC 

units, the potential conversion of Lee Steam Station Unit 3 to natural gas fuel, along with the 

energy and capacity savings achievements of the Company’s EE and DSM programs, will 

fulfill these needs through 2015. Beginning in 2016, the Company has a capacity need of 

410 MWs to meet its projected capacity requirements including a 15.5% reserve margin. 

Even if the Company fully realizes its goals for EE and DSM, the resource need grows to 

approximately 6,360 MWs by 2032. 

The 2012 Duke Energy Carolinas IRP outlines the Company’s options and plans for meeting 

its projected long-term needs. The general factors that influence the Company’s future 

resource needs are: 
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• Future load growth projections; 

• The amount of EE and DSM that can be achieved; 

• Resources needed to meet the NC REPS requirement; 

• Reductions in existing resources, for example, due to unit retirements and expiration 

of purchased power agreements (PPA); and 

• Meeting the Company’s 15.5% target planning reserve margin over the 20-year 

horizon. 

A key purpose of the IRP is to provide the Company’s management with information to aid 

in making the decisions necessary to ensure that Duke Energy Carolinas has a reliable, 

diverse, environmentally sound, and reasonably priced portfolio of resources over time. 

Both DSM and EE programs play important roles in the Company’s development of a 

balanced, cost-effective and environmentally responsible resource portfolio. Renewable 

generation options are also necessary to meet the NC REPS enacted in 2007. These 

resources will be incorporated more broadly into the Company’s resource portfolio to the 

extent they become more cost-effective in comparison with traditional supply-side resources 

and with consideration of other qualitative issues such as their intermittency and relative 

contribution to meeting peak capacity needs. Energy savings resulting from EE programs 

may also be used to meet, in part, the Company’s REPS obligations. The Company’s REPS 

Compliance Plan is being filed concurrently with the 2012 IRP, pursuant to the requirements 

of NCUC Rule R8-67. 

In the short term, Duke Energy Carolinas’ 2012 IRP analysis results indicate the need for 

intermediate to base load resources in 2016 and 2018 and at various points throughout the 

study period in addition to significant EE, DSM, and renewable resources. The Company 

identified combined cycle generation as the optimal resource to meet its 2016 and 2018 

capacity needs. 

For Duke Energy Carolinas’ longer term need, the Company’s analysis continues to affirm 

the potential benefits of new nuclear capacity in a carbon-constrained future. The 

Company’s analysis considered a portfolio based on full ownership of the 2,234 MW Lee 

Nuclear Station by the summer of 2022 and 2024, as well as a portfolio that reflects regional 

nuclear generation equivalent to the MWs associated with Lee Nuclear Station distributed 

over 2017 to 2028. Regional nuclear is where two or more partners plan collaboratively to 

stage multiple nuclear stations over a period of years and each partner would own a portion 

of each station. The regional nuclear portfolio is illustrative of the potential value to 

customers of a representative regional nuclear generation plan. Duke Energy Carolinas 

continues to strongly support regional nuclear opportunities and is actively pursuing this 
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concept. As the Company announced in 2011, Duke Energy Carolinas has agreements with 

JEA, located in Jacksonville, Florida, and with the Public Service Authority of South 

Carolina (Santee Cooper). Duke Energy Carolinas has an agreement with Santee Cooper to 

perform due diligence and potentially acquire an option for a minority interest (5 to 10% of 

the capacity of the two units) in Santee Cooper’s 45% ownership of the planned new nuclear 

reactors at V.C. Summer Nuclear Generating Station in South Carolina. The new Summer 

units are scheduled to be online in 2017 and 2018. JEA has signed an option agreement to 

potentially purchase up to 20% of Lee Nuclear Station. 

The Company’s analysis indicates that the regional nuclear portfolio is lower cost to 

customers in the base case and in most scenarios. However, the full nuclear portfolio was 

chosen for the 2012 IRP preferred plan because there are no firm commitments in place at 

this time for the regional nuclear portfolio. Although the regional nuclear portfolio assumes 

10% of the Summer station is purchased, the Company’s decision on whether and how much 

to purchase will be based on many factors, including the results of the due diligence related 

to Summer, the capacity need at the time of the decision, and the financial implications of the 

purchase on the Company. Duke Energy Carolinas will continue to assess opportunities to 

benefit from economies of scale and risk reduction in new resource decisions by considering 

the prospects for joint ownership and/or sales agreements for new nuclear generation 

resources. 

The 2012 IRP also includes the Company’s plan for meeting the requirements set forth in the 

Cliffside Unit 6 NCDAQ Air Permit (Cliffside Air Permit). The Cliffside Air Permit 

requires that the Company take specific actions to render Cliffside Unit 6 carbon neutral by 

2018. In its order approving the utilities’ respective 2011 IRPs, the NCUC approved the 

Company’s proposed carbon neutrality plan as required by the Cliffside Air Permit. The 

Company’s plan has been updated in the 2012 IRP to reflect changes in energy efficiency 

projections, NC REPS compliance and other ongoing activities. With the incorporation of 

these updates, the Company’s proposed plan remains robust by projecting to eliminate 

approximately 9.2M tons of CO2, where the emission reduction requirement is approximately 

5.3M tons to render Cliffside Unit 6 as carbon neutral by 2018. 

Duke Energy Carolinas has developed a sustainable strategy to ensure that the Company can 

meet customers’ energy needs reliably and economically over the near and long term. The 

strategic action plan for long-term resources maintains prudent flexibility in the face of 

uncertain and constantly evolving circumstances. 
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Short Term Action Plan 

The Company’s Short Term Action Plan, which identifies accomplishments in the past year 

and actions to be taken over the next five years, is summarized below:

• Take actions to ensure capacity needs beginning in 2016 are met. In addition to 

seeking to meet the Company’s DSM and EE goals and meeting the Company’s 

REPS requirements, actions to secure additional capacity may include purchased 

power or generating capacity or Company-owned generation. 

• Continue to evaluate and plan for the retirement of older coal generation. Buck 

Steam Station Units 3 and 4 were retired in May 2011. Cliffside Units 1 through 4 

and Dan River Units 1 and 2 were retired in October 2011 and April 2012, 

respectively, in advance of the initial testing of new generation at those locations. 

Retirements of the remaining un-scrubbed coal units at Buck, Riverbend and Lee 

Steam Stations are currently planned for April 2015 to correspond with the 

compliance requirements of the Mercury Air Toxic Rule. Duke Energy Carolinas is 

also planning to retire all of its older CTs in October 2012. 

• Continue to execute the Company’s EE and DSM plan, which includes a diverse 

portfolio of EE and DSM programs, and continue on-going collaborative work to 

develop and implement additional cost-effective EE and DSM products and services. 

Over the past year, PowerShare® impacts have increased, offsetting approximately 40

MW of peak capacity need and energy efficiency achievements have reduced energy 

consumption by over 560,000 MWh. 

 

• Completed Bridgewater Hydro Station generating unit upgrades. The units were 

operational November 2011. The previous generating units were replaced by two 15 

MW units and a small 1.5 MW unit representing an 8.5 MW increase in station 

capability. The new generating units will be used to meet continuous release 

requirements and system peak. 

• Completed construction of the new Buck Combined Cycle (CC) unit. The unit was 

operational November 2011. The 620 MW natural gas-fired CC generating station 

achieves high operational flexibility and high thermal efficiency while utilizing stateof-the-art environmental control technology to minimize plant emissions. 

• Complete construction of the 825 MW Cliffside Unit 6, at the existing Cliffside 

Steam Station. As of August 2012, the project is in testing phase with commercial 

operation expected in September 2012. 

• Complete construction of the 620 MW combined-cycle plant at Dan River Steam 
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Station. As of August 2012, the project was over 90% complete. 

• Continue to assess the conversion of Lee Steam Station Unit 3 from coal to natural 

gas fuel. Lee Steam Station Unit 3 is reflected in the 2012 Duke Energy Carolinas 

IRP as a retired coal unit in the fourth quarter of 2014 and converted to natural gas by 

January 1, 2015. Preliminary engineering has been completed and more detailed 

project development and regulatory efforts are ongoing. 

• Continue to pursue the option for new nuclear generating capacity in the 2017 to 2028 

timeframe. 

 The Company submitted an application for a Combined Construction and 

Operating license (COL) and an environmental report to the NRC on December 

12, 2007. A supplement to the environmental report was filed September 24, 

2009. The NRC issued its Draft Environmental Impact Statement for the 

William States Lee III Nuclear plant in December 2011, concluding that the 

NCUC’s evaluation of Duke’s future load demand and its accuracy in historical 

load forecasting within the 2011 IRP was a reasonable basis for planning. 

 The Company plans to continue to support the NRC evaluation of the COL. In 

March of 2012, the NRC issued a request for information letter to operating 

power reactor licensees regarding recommendations of the Near-Term Task 

Force review of insights from the Fukushima Dai-ichi accident. In April 2012, 

the NRC staff subsequently requested that Duke Energy update the W.S. Lee III 

(Lee) plant site-specific seismic analysis. This request impacted the schedule for 

NRC issuance of the Lee Combined Operating License, moving the projected 

Commercial Operation Date (COD) beyond the summer peak of 2021. 

 The Company continues to evaluate the optimal time to file the Certificate of 

Environmental Compatibility and Public Convenience and Necessity (CPCN) in 

South Carolina, as well as pursue other relevant regulatory approvals. 

 The Company will continue to pursue available federal, state and local tax 

incentives and favorable financing options at the federal and state level. 

 The Company will continue to assess opportunities to benefit from economies of 

scale and risk reduction in new resource decisions by considering the prospects 

for joint ownership and/or sales agreements for new nuclear generation 

resources. 
15 

• Continue to evaluate market options for renewable generation and procure capacity, 

as appropriate. PPAs have been signed with developers of solar photovoltaic (PV), 

landfill gas, wind, and thermal resources. Additionally, renewable energy certificate 

(REC) purchase agreements have been executed for purchases of unbundled RECs 

from wind, solar PV, solar thermal and hydroelectric facilities. 

• Continue to investigate the future environmental control requirements and resulting 

operational impacts associated with the Mercury MACT rule, the CCR rule, the 

CSAPR rule and the new Ozone NAAQS and SO2. 

• Continue to pursue existing and potential opportunities for wholesale power sales 

agreements within the Duke Energy Balancing Authority Area. 

• Continue to monitor energy-related statutory and regulatory activities. 

A summarization of the capacity resource changes for the reference plan in the 2012 IRP is 

shown in Table 1.A below. Capacity retirements and additions are presented as incremental 

values in the year in which the change is projected to occur. The values shown for renewable 

resources, DSM, and EE represent cumulative totals. 
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Table 1.A

 

Year Retirements Additions (1) EE DSM (3)

Wind (2) Solar (2) Biomass

2013 34 MW Nuc 0 56 10 62 875

2014 65 MW Nuc 100 135 20 117 960

2015 Lee 1-3 (370 MW) 12 MW Nuc 100 253 30 181 1046

Riverbend 4-7 (454 MW) 170 MW Lee 3 NG 

Buck 5-6 (256 MW)

2016 700 MW CC 134 320 51 247 1097

2017 135 352 60 317 1139

2018 700 MW CC 135 398 68 384 1152

2019 800 MW CT 322 471 90 451 1166

2020 323 495 99 517 1179

2021 324 538 108 585 1193

2022 1117 MW Nuc 376 649 135 652 1199

2023 378 692 133 720 1206

2024 1117 MW Nuc 381 736 142 785 1206

2025 416 840 154 854 1206

2026 419 885 155 921 1206

2027 422 928 156 988 1206

2028 700 MW CC 430 946 163 1053 1206

2029 439 965 166 1123 1206

2030 800 MW CT 448 984 170 1190 1206

2031 457 1004 173 1257 1206

2032 150 MW CT 457 1004 173 1320 1206

Total MW 1080 6365 457 1004 173 1320 1206

(1) Includes 111 MW of nuclear uprates

(2) Capacity is shown in nameplate ratings. For planning purposes, wind presents a 15% contribution to peak 

 and solar has a 40% contribution to peak.

(3) Includes 135 MW impact of grid modernization

Renewable Resources

Duke Energy Carolinas Integrated Resource Plan

(Cumulative Nameplate MW)
17

2. SYSTEM OVERVIEW, OBJECTIVES, AND PROCESS 

A. System Overview 

Duke Energy Carolinas provides electric service to an approximately 24,000-square-mile 

service area in central and western North Carolina and western South Carolina. In addition 

to retail sales to approximately 2.43 million customers, Duke Energy Carolinas also sells 

wholesale electricity to incorporated municipalities and to public and private utilities. 

Duke Energy Carolinas currently meets energy demand, in part, by purchases from the open 

market, through longer-term purchased power contracts and from the following electric 

generation assets: 

• Three nuclear generating stations with a combined net capacity of 6,996 MW 

(including all of Catawba Nuclear Station); 

• Seven coal-fired stations with a combined capacity of 7,057 MW; 

• 29 hydroelectric stations (including two pumped-storage facilities) with a combined 

capacity of 3,229 MW; and

• Nine combustion turbine stations (including one Combined Cycle Station) with a 

combined capacity of 3,740 MW. 

Duke Energy Carolinas’ power delivery system consists of approximately 101,000 miles of 

distribution lines and 13,000 miles of transmission lines. The transmission system is directly 

connected to all of the utilities that surround the Duke Energy Carolinas service area. There 

are 36 circuits connecting with eight different utilities: Progress Energy Carolinas, American 

Electric Power, Tennessee Valley Authority, Southern Company, Yadkin, Southeastern 

Power Administration (SEPA), South Carolina Electric and Gas, and Santee Cooper. These 

interconnections allow utilities to work together to provide an additional level of reliability. 

The strength of the system is also reinforced through coordination with other electric service 

providers in the Virginia-Carolinas (VACAR) sub-region, SERC Reliability Corporation 

(SERC) (formerly Southeastern Electric Reliability Council), and North American Electric 

Reliability Corporation (NERC). 

The map on the following page provides a high-level view of the Duke Energy Carolinas 

system.
18
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B. Objectives 

Duke Energy Carolinas has an obligation to provide reliable and economic electric 

service to its customers in North Carolina and South Carolina. To meet this obligation, 

the Company conducted an integrated resource planning process that serves as the basis 

for its 2012 IRP. 

The purpose of this IRP is to outline a robust strategy to furnish electric energy services 

to Duke Energy Carolinas’ customers in a reliable, efficient, economic, and increasingly 

clean manner while factoring in the uncertainty of the future. 

The planning process itself must be dynamic and constantly adaptable to changing 

conditions. The IRP presented herein represents the most robust and cost effective 

outcome based upon the Company’s analyses under various assumptions and 

sensitivities. Duke Energy Carolinas has performed sensitivity analyses as part of this 

IRP to account for the uncertainty of many factors influencing the business, including 

regulatory, economic, environmental and operational changes. Duke Energy Carolinas 

will continue to monitor these uncertainties and make adjustments as necessary and 

practical in future plans. 

Duke Energy Carolinas’ long-term planning objective is to employ a flexible planning 

process and pursue a resource strategy that considers the costs and benefits to all 

stakeholders (customers, shareholders, employees, suppliers, and community). At times, 

this involves striking a balance between competing objectives. The major objectives of 

the plan presented in this filing are: 

• Provide adequate, reliable, and economic service to customers in an 

uncertain environment. 

• Maintain the flexibility and ability to alter the plan in the future as 

circumstances change. 

• Choose a near-term plan that is robust over a wide variety of possible 

futures. 

• Minimize risks with the development of a balanced portfolio. 

C. Planning Process

The development of the IRP is a multi-step process covering the planning period of 2012-

2032, involving the following key planning functions: 

• Developing planning objectives and assumptions. 
20

• Considering the impacts of anticipated or pending regulations or events on 

existing resources (environmental, renewables, etc.). 

• Developing a regulatory construct to assess the impact of potential CO2 or 

Energy Policy legislation. More details of this step may be found in Appendix 

A. 

• Preparing the electric load forecast. More details of this step may be found in 

Chapter 3. 

• Identifying EE and DSM options. More details concerning this step can be 

found in Chapter 4. 

• Identifying and economically screening for the cost-effectiveness of supplyside resource options. More details concerning this step of the process can be 

found in Chapter 5. 

• Integrating the energy efficiency, renewable, and supply-side options with the 

existing system and electric load forecast to develop potential resource 

portfolios to meet the desired reserve margin criteria. More details concerning 

this step of the process can be found in Chapter 8 and Appendix A. 

• Performing detailed modeling of potential resource portfolios to determine the 

resource portfolio that exhibits the lowest cost (lowest net present value of 

costs) to customers over a wide range of alternative futures. More details 

concerning this step of the process can be found in Chapter 8 and Appendix 

A. 

• Evaluating the ability of the selected resource portfolio to minimize price and 

reliability risks to customers. More details concerning this step of the process 

can be found in Chapter 8 and Appendix A. 

The Company’s analytical methodology for resource planning includes the incorporation 

of sensitivity analysis of variables representing the highest risk going forward, such as the 

load forecast, construction costs, fuel prices, EE, carbon prices and emerging policy. 
21 

3. ELECTRIC LOAD FORECAST 

The following section provides details on the Load Forecast created in the spring of 2012. 

Duke Energy Carolinas’ retail sales have grown at an average annual compound rate of 0.5% 

from 1996 to 2011, non-weather adjusted. The following table shows historical and projected 

major customer class growth, at a compound annual rate. The historical periods are nonweather adjusted. 

Table 3.A

Retail Load Growth (kWh sales) 

Time 

Period 

Total Retail Residential Commercial Industrial 

Textile 

Industrial 

Non-Textile 

1996-2011 0.5% 1.9% 2.3% -6.9% -0.5% 

1996-2006 0.8% 1.9% 2.9% -6.7% 0.3% 

2006-2011 0.1% 1.9% 1.2% -7.2% -2.2% 

2011-2031* 1.4% 1.3% 1.9% -0.9% 1.0% 

*Growth rates from 2011-2031 are derived using weather adjusted values for 2011. This differs 

from the Forecast Book located in Appendix B, which uses actual 2011 values. 

A significant decline in the Industrial Textile class was the key contributor to the Company’s 

low load growth from 2006 to 2011. The recession in 2008-2009 also slowed the Commercial, 

Residential and Other Industrial classes. For example, over the last 5 years an average of 

approximately 22,000 new residential customers per year has been added to the Duke Energy 

Carolinas service area. Before the recession, however, the average growth was 30,000-35,000. 

Duke Energy Carolinas’ total retail load growth over the planning horizon, 2012-2032, is driven 

by projected steady increases in the Residential, Commercial and Other Industrial classes. 

Textiles, however, are projected to experience a slow decline over the forecast horizon. 

 

Retail load growth summaries are shown in the Duke Energy Carolinas Spring 2012 Forecast 

book in Appendix B. 
22

Table 3.B

Retail Customers (Thousands, Annual Average) 

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 

Residential 1,840 1,872 1,901 1,935 1,972 2,016 2,052 2,059 2,072 2,081 

Commercial

300 307 313 319 325 331 334 333 334 336 

Industrial 8 8 8 7 7 7 7 7 7 7 

Other 11 11 12 13 13 13 14 14 14 14 

Total 2,159 2,198 2,234 2,275 2,317 2,368 2,407 2,413 2,427 2,439 

Table 3.C

Electricity Sales (GWh Sold - Years Ended December 31) 

 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 

Residential 24,466 23,947 25,150 26,108 25,816 27,459 27,335 27,273 30,049 28,323 

Commercial 24,242 24,355 25,204 25,679 26,030 27,433 27,288 26,977 27,968 27,593 

Industrial 26,259 24,764 25,209 25,495 24,535 23,948 22,634 19,204 20,618 20,783 

Other 271 270 269 269 271 278 284 287 287 287 

Total Retail 75,238 73,336 75,833 77,550 76,653 79,118 77,541 73,741 78,922 76,985 

Wholesale 1,530 1,448 1,542 1,580 1,694 2,454 3,525 3,788 5,166 4,866 

Total 

System 76,769 74,784 77,374 79,130 78,347 81,572 81,066 77,528 84,088 81,851 

Note: Wholesale sales will vary over time due to new contract agreements. 

Wholesale Power Sales Commitments 

Table 3.D on the following page contains information concerning Duke Energy Carolinas’ 

wholesale contracts. The description ‘Full’ indicates that Duke Energy Carolinas provides all of 

the needs of the wholesale customer. ‘Partial’ refers to those customers where Duke only 

provides some of the customer’s needs. ‘Fixed’ refers to a constant load shape. As a note, the 

values in Table 3.D are net of self-supplied generation. 
23

2012 2013 2014 2015 2016 2017 2018 

Concord, NC Partial 2009-2018 181 180 184 187 190 192 195 Dallas, NC Partial 2009-2028 11 11 11 12 12 12 12 Due West, SC Partial 2009-2018 3 3 3 3 3 3 3 Forest City, NC Partial 2009-2028 15 15 15 15 16 16 16 Greenwood, SC Full 2010-2018 54 54 55 56 57 58 59 Highlands, NC Full 2010-2029 8 8 8 8 8 8 8 Kings Mountain, NC Partial 2009-2018 19 19 20 20 20 21 21 Lockhart Power Partial 2009-2018 54 54 55 56 57 57 58 Prosperity, SC Partial 2009-2028 2 2 2 2 2 2 2 Western Carolina Full 2010-2021 6 6 6 6 6 6 6 UniversityBlue Ridge EMC Full 2010-2031 224 227 230 234 238 242 246 Central EPC Partial 2013-2030 0 123 250 383 521 664 812 Haywood EMC Full 2009-2021 20 20 20 20 21 21 21 NCEMC Fixed 2009-2038 72 72 72 72 72 72 72 Piedmont EMC Full 2010-2031 90 91 92 94 95 97 98 PMPA* Backstand 2014-2020 0 0 47 47 47 47 47 Rutherford EMC Partial 2010-2031 161 193 197 212 216 221 226 NCEMC* Backstand 1985-2043 95 95 116 116 116 116 116 FERC Mitigation** Full 2012-2014 150 150 150 150

Note: For Resource Planning purposes the contracts above are assumed to renew through the end of the planning horizon*Note: All backstand contracts represent the portion that Duke Energy Carolinas commitment.**Note: FERC Mitigation Sale represents the summer peak MW - Sale begins July 3, 2012 and extends through Februar

Customer Product Term

Commitment (MWs)

Table 3.D Wholesale Contracts
24 

The Company’s Spring 2012 Forecast includes projections of the energy needs of new 

future customers and current existing customers in Duke Energy Carolinas territory. 

Certain wholesale customers have the option of obtaining all or a portion of their future 

energy requirements from other suppliers. Although this may reduce Duke Energy 

Carolinas’ obligation to serve those customers, Duke Energy Carolinas assumes for 

planning purposes that the contracts displayed in Table 3.D will be extended through the 

duration of the forecast horizon. 

Pursuant to NCUC Rule R8-60(i)(1), a description of the methods, models and 

assumptions used by the utility to prepare its peak load (MW) and energy sales (MWh) 

forecasts and the variables used in the models is provided in the pages named 

‘Methodology 1’ and ‘Methodology 2’ of the Duke Energy Carolinas 2012 Forecast 

book located in Appendix B. Also, per NCUC Rule R8-60(i)(1)(A), a forecast of 

customers by each customer class and a forecast of energy sales (kWh) by each customer 

class is provided in the 2012 Forecast book located in Appendix B. 

A tabulation of the utility’s forecasts for a 20 year period, including peak loads for 

summer and winter seasons of each year and annual energy forecasts, both with and 

without the impact of utility-sponsored energy efficiency programs are shown below in 

Tables 3.E and 3.F. 

Load duration curves, with and without utility-sponsored energy efficiency programs, 

follow Tables 3.E and 3.F, and are shown as Charts 3.A and 3.B. 

The values in those tables reflect the loads that Duke Energy Carolinas is contractually 

obligated to provide and cover the period from 2012 to 2032. 

The current 20-year forecast of the needs of the retail and wholesale customer classes, 

which does not include the impact of new Duke Energy Carolinas energy efficiency 

programs, projects a compound annual growth rate of 1.9% in the summer peak demand, 

while winter peaks are forecasted to grow at 1.9%. The forecasted compound annual 

growth rate for energy is 2.0% before energy efficiency program impacts are subtracted. 

If the impacts of new Duke Energy Carolinas energy efficiency programs are included, 

the projected compound annual growth rate for the summer peak demand is 1.7%, while 

winter peaks are forecasted to grow at a rate of 1.7%. The forecasted compound annual 

growth rate for energy is 1.6% after the impacts of energy efficiency programs have been 

subtracted. 
25

Table 3.E

Load Forecast without Energy Efficiency Programs (at Generation) 

YEAR SUMMER WINTER ENERGY 

(MW) (MW) (GWH) 

2012 17,745 17,086 90,572 

2013 18,107 17,443 92,210 

2014 18,554 17,868 94,402 

2015 19,003 18,295 96,744 

2016 19,486 18,744 99,147 

2017 19,947 19,224 101,536 

2018 20,386 19,672 103,975 

2019 20,830 20,112 106,233 

2020 21,176 20,474 108,141 

2021 21,552 20,764 110,043 

2022 21,921 21,179 111,979 

2023 22,296 21,527 113,922 

2024 22,673 21,880 115,894 

2025 23,073 22,260 117,910 

2026 23,435 22,585 119,972 

2027 23,859 22,958 122,126 

2028 24,260 23,418 124,352 

2029 24,643 23,816 126,531 

2030 25,051 24,209 128,747 

2031 25,483 24,628 131,042 

2032 25,905 25,005 133,453 
26

Chart 3.A- Load Duration Curves without Energy Efficiency 
27 

Table 3.F

Load Forecast with Energy Efficiency Programs (at Generation) 

YEAR SUMMER WINTER ENERGY 

(MW) (MW) (GWH) 

2012 17,716 17,069 90,416 

2013 18,043 17,383 91,741 

2014 18,437 17,759 93,559 

2015 18,795 18,130 95,499 

2016 19,239 18,526 97,487 

2017 19,630 18,921 99,418 

2018 20,002 19,303 101,399 

2019 20,379 19,677 103,200 

2020 20,638 19,985 104,650 

2021 20,967 20,197 106,093 

2022 21,268 20,546 107,571 

2023 21,577 20,828 109,056 

2024 21,888 21,117 110,570 

2025 22,219 21,446 112,128 

2026 22,499 21,706 113,732 

2027 22,871 21,994 115,427 

2028 23,208 22,391 117,195 

2029 23,520 22,720 118,916 

2030 23,861 23,048 120,674 

2031 24,227 23,425 122,511 

2032 24,585 23,740 124,464 
28

Chart 3.B - Load Duration Curves with Energy Efficiency
29 

4. ENERGY EFFICIENCY AND DEMAND-SIDE MANAGEMENT 

Current Energy Efficiency and Demand-Side Management Programs 

In May 2007, Duke Energy Carolinas filed its application for approval of Energy 

Efficiency and Demand Side Management programs under its save-a-watt initiative. The 

Company received the final order for approval for these programs from the NCUC in July 

2010 and from the Public Service Commission of South Carolina (PSCSC) in May 2009. 

Duke Energy Carolinas uses EE and DSM programs to help manage customer demand in 

an efficient, cost-effective manner. These programs can vary greatly in their dispatch 

characteristics, size and duration of load response, certainty of load response, and level 

and frequency of customer participation. In general, programs are offered in two primary 

categories: EE programs that reduce energy consumption and DSM programs that reduce 

energy demand (demand-side management or demand response programs and certain rate 

structure programs). The following are the current EE and DSM programs in place in the 

Carolinas: 

 

Demand Response – Direct Load Control Curtailment Programs 

These programs can be dispatched by the utility and have the highest level of certainty. 

Once a customer agrees to participate in a demand response load control curtailment 

program, the Company controls the timing, frequency, and nature of the load response. 

Duke Energy Carolinas’ current direct load control curtailment programs are: 

• Power Manager® - Power Manager® is a residential direct load control program. 

Participants receive billing credits during the billing months of July through October 

in exchange for allowing Duke Energy Carolinas the right to cycle their central air 

conditioning systems and, additionally, to interrupt the central air conditioning when 

the Company has capacity needs. 

Demand Response – Interruptible and Related Rate Structures

These programs rely either on the customer’s ability to respond to a utility-initiated signal 

requesting curtailment or on rates with price signals that provide an economic incentive 

to reduce or shift load. Timing, frequency and nature of the load response depend on 

customers’ actions after notification of an event or after receiving pricing signals. Duke 

Energy Carolinas’ current interruptible and time-of-use curtailment programs include: 

• Interruptible Power Service (IS) (North Carolina Only) - Participants agree 

contractually to reduce their electrical loads to specified levels upon request by Duke 

Energy Carolinas. If customers fail to do so during an interruption, they receive a 

penalty for the increment of demand exceeding the specified level. 
30

• Standby Generator Control (SG) (North Carolina Only) - Participants agree 

contractually to transfer electrical loads from the Duke Energy Carolinas source to 

their standby generators upon request by Duke Energy Carolinas. The generators in 

this program do not operate in parallel with the Duke Energy Carolinas system and 

therefore, cannot “backfeed” (i.e., export power) into the Duke Energy Carolinas 

system. Participating customers receive payments for capacity and/or energy, based 

on the amount of capacity and/or energy transferred to their generators. 

• PowerShare® is a non-residential curtailment program consisting of four options: an 

emergency only option for curtailable load (PowerShare® Mandatory), an emergency 

only option for load curtailment using on-site generators (PowerShare® Generator), 

an economic based voluntary option (PowerShare® Voluntary), and a combined 

emergency and economic option that allows for increased notification time of events 

(PowerShare® CallOption). 

• PowerShare® Mandatory: Participants in this emergency only option will 

receive capacity credits monthly based on the amount of load they agree to 

curtail during utility-initiated emergency events. Participants also receive 

energy credits for the load curtailed during events. Customers enrolled may 

also be enrolled in PowerShare® Voluntary and eligible to earn additional 

credits. 

• PowerShare® Generator: Participants in this emergency only option will 

receive capacity credits monthly based on the amount of load they agree to 

curtail (i.e. transfer to their on-site generator) during utility-initiated 

emergency events and their performance during monthly test hours. 

Participants also receive energy credits for the load curtailed during events. 

• PowerShare® Voluntary: Enrolled customers will be notified of pending 

emergency or economic events and can log on to a Web site to view a posted 

energy price for that particular event. Customers will then have the option to 

participate in the event and will be paid the posted energy credit for load 

curtailed. 

• PowerShare® CallOption: This DSM program offers a participating customer 

the ability to receive credits when the customer agrees, at the Company’s 

request, to reduce and maintain its load by a minimum of 100 kW during 

Emergency and/or Economic Events. Credits are paid for the load available 

for curtailment, and charges are applicable when the customer fails to reduce 

load in accordance with the participation option it has selected. Participants 
31

are obligated to curtail load during emergency events. CallOption offers four 

participation options to customers: PS 0/5, PS 5/5, PS 10/5 and PS 15/5. All 

options include a limit of five Emergency Events and set a limit for Economic 

Events to 0, 5, 10 and 15 respectively. 

• Rates using price signals 

• Residential Time-of-Use (including a Residential Water Heating rate) 

 This category of rates for residential customers incorporates differential 

seasonal and time-of-day pricing that encourages customers to shift electricity 

usage from on-peak time periods to off-peak periods. In addition, there is a 

Residential Water Heating rate for off-peak water heating electricity use. 

• General Service and Industrial Optional Time-of-Use rates 

This category of rates for general service and industrial customers 

incorporates differential seasonal and time-of-day pricing that encourages 

customers to use less electricity during on-peak time periods and more during 

off-peak periods. 

• Hourly Pricing for Incremental Load 

This category of rates for general service and industrial customers 

incorporates prices that reflect Duke Energy Carolinas’ estimation of hourly 

marginal costs. In addition, a portion of the customer’s bill is calculated 

under their embedded-cost rate. Customers on this rate can choose to modify 

their usage depending on hourly prices. 

Energy Efficiency Programs 

These programs are typically non-dispatchable education or incentive programs. Energy 

and capacity savings are achieved by changing customer behavior or through the 

installation of more energy-efficient equipment or structures. All effects of these existing 

programs are reflected in the customer load forecast. Duke Energy Carolinas’ existing 

EE programs include: 

• Residential Energy Assessments 

The Residential Energy Assessments program includes two separate measures: (1) 

Personalized Energy Report (PER) and (2) Home Energy House Call. 

The PER program is a residential energy efficiency program that provides single 

family home customers with a customized report about their home and family and 
32

how they use energy. In addition, the customer receives compact fluorescent 

lights (CFLs) as an incentive to participate in the program. 

The PER program requires customers to provide information about their home, 

number of occupants, equipment and energy usage and has two variations: 

• A mailed offer where customers are asked to complete an included energy 

survey and mail it back to Duke Energy or complete the same survey 

online. Customers mailing the energy survey receive their PER in the 

mail and those completing it online receive their PER online as a printable 

PDF document. 

• An online offer to our customers that have signed into Duke Energy’s 

Online Services (OLS) bill pay and view environment. Online 

participants complete their energy survey online get their PER online as a 

printable PDF. 

Home Energy House Call (HEHC) is a free in-home assessment designed to help 

our customers learn about home energy usage and how to save on monthly bills. 

The program provides personalized information unique to the customer's home 

and energy practices. An energy specialist visits the customer's home to analyze 

the total home energy usage and to pinpoint energy saving opportunities. An 

energy specialist will also explain how to improve the heating and cooling 

comfort levels, check for air leaks, examine insulation levels, review appliances, 

help the customer preserve the environment for the future and keep electric costs 

low. A customized report is prepared, explaining the steps the customer can take 

to increase efficiency. As a part of the Home Energy House Call program, 

customers receive an Energy Efficiency Starter Kit. At the request of the 

customer, the energy specialist can install the efficiency items to allow the 

customer to begin saving immediately. 

• Low Income Energy Efficiency and Weatherization Program 

The purpose of this program is to assist low income residential customers with 

energy efficiency measures to reduce energy usage through energy efficiency kits 

or through assistance in the cost of energy efficient equipment or weatherization 

measures. 

• Energy Efficiency Education Program for Schools 

The purpose of this program is to educate students about sources of energy and 

energy efficiency in homes and schools through a curriculum provided to public 

and private schools. This curriculum includes lesson plans, energy efficiency 
33

materials, and energy audits. 

• Residential Smart $aver® Energy Efficient Products Program 

The Smart $aver®

 Program provides incentives to residential customers who 

purchase energy-efficient equipment. The program has three components – CFLs, 

high-efficiency air conditioning equipment and tune and seal measures. 

CFLs 

The CFL program is designed to offer incentives to customers and increase 

energy efficiency by installing CFLs in high use fixtures in the home. The 

incentives have been offered in a variety of ways. The first deployment of this 

program distributed free coupons to be redeemed by the customer at a variety of 

retail stores. Later deployments used business reply cards and a web-based ondemand ordering tool where CFLs were shipped directly to the customer’s home. 

Heating Ventilation & Air Conditioning (HVAC) and Heat Pump 

The residential air conditioning program provides incentives to customers, 

builders, and heating contractors (HVAC dealers) to promote the use of highefficiency air conditioners and heat pumps. The program is designed to increase 

the efficiency of air conditioning systems in new homes and for replacements in 

existing homes. 

Tune and Seal Measures (Approved in South Carolina only)

Partnering with HVAC dealers, the program pays incentives to partially offset the 

cost of air conditioner and heat pump tune ups and duct sealing. This is a new 

program and has not been previously offered in any of Duke Energy’s 

jurisdictions. Projected impacts of this program were included in the analysis of 

generation needs. 

• Residential Neighborhood Program 

Program that targets low income neighborhoods providing high impact direct 

install measures (CFLs, pipe and water heater wrap, low flow aerators and 

showerheads, HVAC filters and air infiltration sealing) and energy efficiency 

education. Projected impacts of this program were included in the analysis of 

generation needs. 

• Appliance Recycling Program (Approved in South Carolina only) 

This is a program to incentivize households to remove old inefficient refrigerators 

and freezers and have those units properly recycled. Projected impacts of this 

program were included in the analysis of generation needs. 
34

• My Home Energy Report (Approved in South Carolina only) 

The purpose of this program is to provide comparative usage data for similar 

residences in the same geographic area to motivate customers to better manage 

and reduce energy usage. The program assists residential customers in assessing 

their energy usage and provides recommendations for more efficient use of 

energy in their homes. The program also helps to identify those customers who 

could benefit most by investing in new energy efficiency measures, undertaking 

more energy efficient practices and participating in Duke Energy programs.

• Smart $aver® for Non-Residential Customers 

The purpose of this program is to encourage the installation of high-efficiency 

equipment in new and existing non-residential establishments. The program 

provides incentive payments to offset a portion of the higher cost of energyefficient equipment. The following types of equipment are eligible for incentives 

as part of the Prescriptive program: high-efficiency lighting, high-efficiency air 

conditioning equipment, high-efficiency motors, high-efficiency pumps, variable 

frequency drives, food services and process equipment. Customer incentives may 

be paid for other high-efficiency equipment as determined by the Company to be 

evaluated on a case-by-case basis through the Custom program. 

The projected impacts from these programs are included in this year’s assessment of 

generation needs. 

Additional Programs Being Considered 

A high-level overview is provided below. 

• PowerShare® CallOption 200

This new CallOption, high involvement offer is targeted at customers with very 

flexible load with load curtailment potential of up to 200 hours of economic load 

curtailment each year. This option will function essentially in the same manner as 

the Company’s other CallOption offers. However, customers who participate will 

experience considerably more requests for load curtailment for economic 

purposes. Participants will remain obligated to curtail load during up to 5 

emergency events. 

The following pilot programs have been approved: 

• Residential Retrofit 

This program was approved in North Carolina in Docket E-7, Sub 952 on January 

25, 2011. The Residential Retrofit program is designed to assist residential 
35

customers in assessing their energy usage, to provide recommendations for more 

efficient use of energy in their homes and to encourage the installation of energy 

efficient improvements by offsetting a portion of the cost of implementing the 

recommendations from the assessment. Projected impacts of this pilot program 

were included in the Company’s analysis of generation needs. 

• Smart Energy Now (SEN)

The SEN pilot program was approved by the NCUC in Docket E-7, Sub 961 on 

February 14, 2011 and is designed to reduce energy consumption within the 

commercial office space located in Charlotte City Center through community 

engagement leading to behavioral modification. In order to enable building 

managers and occupants to effectively make these behavioral modifications, they 

will be provided with additional energy consumption information and actionable 

efficiency recommendations. Projected impacts of this pilot were also included in 

the Company’s analysis of generation needs. 

The following pilot program is being proposed: 

• My Energy Manager (MyEM)

MyEM is a residential energy management solution designed for home owners 

with broadband internet service. The product offers energy efficiency and demand 

response benefits through a Wi-Fi enabled thermostat that will manage a 

customer’s air conditioning system by providing schedules, modes (such as 

home/away/vacation), energy savings tips, messages, and alerts. The customer 

will have the tools to access and control their thermostat through any web browser 

or by downloading an “app” on their smart phone. In addition, it will provide 

customers with the opportunity to participate in demand response events. Overall, 

this product will provide simple, intuitive, and effective tools that will enable the 

customer to reduce and manage their overall energy usage. 

Future EE and DSM programs 

In addition to the programs and pilots listed above, Duke Energy Carolinas is actively 

working to add new programs to our portfolio that have not yet been developed. 

Estimates of the impacts of these yet-to-be-developed programs have been included in 

this year’s analysis of generation needs. 
36

EE and DSM Program Screening 

The Company uses the DSMore model to evaluate the costs, benefits, and risks of DSM 

and EE programs and measures. DSMore is a financial analysis tool designed to estimate 

the value of DSM and EE measures at an hourly level across distributions of weather 

conditions and/or energy costs or prices. By examining projected program performance 

and cost effectiveness over a wide variety of weather and cost conditions, the Company is 

in a better position to measure the risks and benefits of employing DSM and EE measures 

versus traditional generation capacity additions, and further, to ensure that DSM 

resources are compared to supply side resources on a level playing field. 

The analysis of energy efficiency and demand side management cost-effectiveness has 

traditionally focused primarily on the calculation of specific metrics, often referred to as 

the California Standard tests: Utility Cost Test (UCT), Rate Impact Measure (RIM) Test, 

Total Resource Cost (TRC) Test, and Participant Test (PCT). DSMore provides the 

results of those tests for any type of EE or DSM program. 

• The UCT compares utility benefits (avoided costs) to the costs incurred by the 

utility to implement the program, and does not consider other benefits such as 

participant savings or societal impacts. This test compares the cost (to the utility) 

to implement the measures with the savings or avoided costs (to the utility) 

resulting from the change in magnitude and/or the pattern of electricity 

consumption caused by implementation of the program. Avoided costs are 

considered in the evaluation of cost-effectiveness based on the projected cost of 

power, including the projected cost of the utility’s environmental compliance for 

known regulatory requirements. The cost-effectiveness analyses also incorporate 

avoided transmission and distribution costs, and load (line) losses. 

• The RIM Test, or non-participants test, indicates if rates increase or decrease over 

the long-run as a result of implementing the program. 

• The TRC Test compares the total benefits to the utility and to participants relative 

to the costs to the utility to implement the program along with the costs to the 

participant. The benefits to the utility are the same as those computed under the 

UCT. The benefits to the participant are the same as those computed under the 

Participant Test, however, customer incentives are considered to be a passthrough benefit to customers. As such, customer incentives or rebates are not 

included in the TRC. 
37

• The Participant Test evaluates programs from the perspective of the program’s 

participants. The benefits include reductions in utility bills, incentives paid by the 

utility and any state, federal or local tax benefits received. 

The use of multiple tests can ensure the development of a reasonable set of DSM and EE 

programs and indicate the likelihood that customers will participate. 

Energy Efficiency and Demand-Side Management Programs 

Duke Energy Carolinas has made a strong commitment to EE and DSM. The Company 

recognizes EE and DSM as a reliable, valuable resource that is an option in the 

portfolio available to meet customers’ growing need for electricity along with coal, 

nuclear, natural gas, and renewable energy. These EE and DSM programs help 

customers meet their energy needs with less electricity, less cost and less environmental 

impact. The Company will manage EE and DSM to provide customers with universal 

access to these services and new technology. Duke Energy Carolinas has the expertise, 

infrastructure, and customer relationships to produce results and make it a significant 

part of its resource mix. Duke Energy Carolinas is committed to develop, implement, 

adjust as needed, and verify the results of innovative EE programs for the benefit of its 

customers. 

In 2011, Duke Energy commissioned an independent Market Potential Study for both the 

North Carolina and South Carolina service territories. This study was prepared by 

Forefront Economics Inc. and was completed in December of 2011. The results of this 

Market Potential Study were incorporated into the Energy Efficiency forecasts included 

in the 2012 IRP. 

The Duke Energy Carolinas’ approved EE plan is consistent with the requirement set 

forth in the Cliffside Unit 6 CPCN Order to invest 1% of annual retail electricity 

revenues in EE and DSM programs, subject to the results of ongoing collaborative 

workshops and appropriate regulatory treatment. For the period between the deployment 

of the Company’s save-a-watt portfolio in 2009 and December 31, 2011, Duke Energy’s 

EE and DSM programs have reduced overall demand, including line losses, by 

approximately 1,159,000 MWh and have added the capability to reduce the Summer Peak 

by over 800 MW. However, pursuing EE and DSM initiatives will not meet all growing 

demands for electricity. The Company still envisions the need to secure additional 

nuclear and natural gas generation, as well as cost-effective renewable generation, but the 

EE and DSM programs offered by Duke Energy Carolinas could address approximately 

half of the Company’s projected 2016 new resource need, if such programs perform as 

expected.
38

Table 4.A provides the base case projected load impacts of the EE and DSM programs 

through 2032. These load impacts were included in the base case IRP analysis. The 

Company assumes total EE savings will continue to grow on an annual basis through 

2032, however the components of future programs are uncertain at this time and will be 

informed by the experience gained under the current plan. This table also includes a 

separate column showing the total annual MWh load reductions associated with EE 

programs that have been added since the inception of the EE programs in 2009. The 

projected MW load impacts from the DSM programs are based upon the Company’s 

continuing, as well as the new, DSM programs. The MW capacity projections have 

increased from last year due to stronger projected growth in the PowerShare® programs. 

 

The projected total annual MWh load reductions associated with EE programs included 

in this base case are more than 10% higher than those included in the 2011 IRP base case, 

primarily due to updated expectations of the performance of the EE programs beyond the 

initial 5 year planning period. The projected base case for this 2012 IRP reaches 

approximately the same total cumulative achievements, including actual achievements 

since 2009, by 2023 that were projected to be achieved by 2031 in the 2011 IRP. 

Table 4.B provides a high case load impact scenario from the Company’s EE and DSM 

programs. Compared to the 2011 IRP, the new high case represents a significant increase 

in the amount of EE and DSM impacts that are modeled, consistent with the Company’s 

merger settlement, under which the Company will aspire to more aggressive cumulative 

EE achievement over the period 2014-20182

 and annual incremental achievement 

beginning in 2015 of 1% of prior year retail electricity sales. The impacts in this high 

case are assumed to level off after 2031 because the projection reaches the theoretical 

economic potential as determined in the Market Potential Study completed in 2011. 

However, Duke Energy Carolinas is committed to ongoing efforts to add incremental 

savings to the extent they are cost effective and customers embrace those measures. For 

DSM programs, the load impacts are increased to reflect higher participation projections 

in the Company’s demand response programs. 

The level of energy efficiency impacts are not ultimately the decision of the Company. 

Driven by the structure of cost recovery and incentive mechanisms and the commitment 

to minimize overall costs to customers, the Company is committed to maximizing the 

implementation of cost-effective energy efficiency and demand response measures in its 

territory. However, while the Company will seek to make programs maximally attractive 

to customers, customers make individual participation decisions based on a variety of 

2

 The Duke-Progress merger commitment regarding energy efficiency requires that Duke make a good faith 

effort to achieve a cumulative savings target of 7% of retail electricity sales over the five-year time 

period of 2014-2018. 
39

factors. Therefore, for planning purposes, the Company models the base EE/DSM case 

assuming limited customer participation until the rate of program adoption is confirmed. 

The high EE/DSM case reflects more aggressive program achievements consistent with 

the merger settlement. 

Table 4.C incorporates December 31, 2011 participation levels for all demand response 

programs and the capability of these programs projected for the summer of 2012. 

Table 4.A Load Impacts of EE and DSM Programs – Base Case

Year

Total Annual 

MWh Load 

Reduction 

(including 

measures added 

in 2012 and 

beyond)

Total Annual 

MWh Load 

Reduction 

(including 

measures added 

since 2009 EE 

program 

inception)

Summer 

Peak MW IS SG PowerShare PowerManager Total

Total 

Summer 

Peak MW 

Impacts

2009 70,782 

2010 591,969 

2011 1,159,117 

2012 312,067 1,471,184 29 119 44 390 261 814 843 

2013 626,576 1,785,693 62 95 5 470 305 875 937 

2014 1,059,768 2,218,885 117 90 5 500 357 953 1,070 

2015 1,430,299 2,589,416 181 85 5 527 409 1,026 1,207 

2016 1,888,405 3,047,522 247 81 5 549 416 1,050 1,297 

2017 2,346,512 3,505,629 317 77 4 571 419 1,071 1,388 

2018 2,804,618 3,963,735 384 77 4 571 419 1,071 1,455 

2019 3,262,725 4,421,842 451 77 4 571 419 1,071 1,523 

2020 3,720,831 4,879,948 517 77 4 571 419 1,071 1,588 

2021 4,178,938 5,338,055 585 77 4 571 419 1,071 1,657 

2022 4,637,044 5,796,161 652 77 4 571 419 1,071 1,724 

2023 5,095,151 6,254,268 720 77 4 571 419 1,071 1,791 

2024 5,553,257 6,712,374 785 77 4 571 419 1,071 1,856 

2025 6,011,363 7,170,481 854 77 4 571 419 1,071 1,925 

2026 6,469,470 7,628,587 921 77 4 571 419 1,071 1,992 

2027 6,927,576 8,086,693 988 77 4 571 419 1,071 2,060 

2028 7,385,683 8,544,800 1,053 77 4 571 419 1,071 2,124 

2029 7,843,789 9,002,906 1,123 77 4 571 419 1,071 2,194 

2030 8,301,896 9,461,013 1,190 77 4 571 419 1,071 2,261 

2031 8,760,002 9,919,119 1,257 77 4 571 419 1,071 2,328 

2032 9,218,109 10,377,226 1,320 77 4 571 419 1,071 2,392 

Energy Efficiency Demand Response Peak MW

Summer Peak MW

Energy Efficiency and Demand Side Management Programs
40 

Table 4.B Load Impacts of EE and DSM Programs – High Case

Year

Total Annual 

MWh Load 

Reduction 

(including 

measures 

added in 2012 

and beyond)

Total Annual 

MWh Load 

Reduction 

(including 

measures 

added since 

2009 EE 

program 

inception)

Summer 

Peak MW IS SG PowerShare PowerManager Total

Total 

Summer 

Peak MW 

Impacts

2009 70,782 

2010 591,969 

2011 1,159,117 

2012 312,067 1,471,184 29 119 44 390 261 815 844 

2013 626,576 1,785,693 62 100 11 470 307 888 950 

2014 1,366,576 2,525,693 139 95 10 523 362 990 1,129 

2015 2,186,219 3,345,336 257 90 10 576 416 1,091 1,349 

2016 3,014,102 4,173,219 387 86 9 613 425 1,133 1,520 

2017 3,850,654 5,009,771 514 81 9 651 430 1,171 1,684 

2018 4,696,074 5,855,191 637 81 9 651 431 1,172 1,809 

2019 5,550,159 6,709,276 762 81 9 651 431 1,172 1,934 

2020 6,412,955 7,572,072 885 81 9 651 431 1,172 2,057 

2021 7,284,387 8,443,504 1,015 81 9 651 431 1,172 2,187 

2022 8,164,725 9,323,842 1,143 81 9 651 431 1,172 2,315 

2023 9,054,089 10,213,206 1,273 81 9 651 431 1,172 2,445 

2024 9,952,555 11,111,672 1,401 81 9 651 431 1,172 2,573 

2025 10,860,095 12,019,212 1,537 81 9 651 431 1,172 2,709 

2026 11,776,729 12,935,846 1,671 81 9 651 431 1,172 2,843 

2027 12,703,074 13,862,191 1,806 81 9 651 431 1,172 2,978 

2028 13,639,302 14,798,419 1,937 81 9 651 431 1,172 3,109 

2029 14,586,209 15,745,326 2,081 81 9 651 431 1,172 3,253 

2030 15,544,266 16,703,383 2,220 81 9 651 431 1,172 3,392 

2031 16,513,125 17,672,242 2,361 81 9 651 431 1,172 3,533 

2032 16,513,125 17,672,242 2,426 81 9 651 431 1,172 3,598 

Energy Efficiency and Demand Side Management Programs

Energy Efficiency Demand Response Peak MW

Summer Peak MW
41 

Table 4.D Current DSM Program Information

Programs Evaluated but Rejected 

Duke Energy Carolinas has not rejected any programs as a result of its EE and DSM 

program screening. 

Looking to the Future 

DSM Implementation Effectiveness – The Company performed an initial review of the 

effectiveness of varying amounts of demand response in 2011. The review is ongoing to 

help shape Duke Energy Carolinas’ portfolio perspective of demand response programs. 

Grid Modernization – Duke Energy is pursuing implementation of grid modernization 

throughout the enterprise. The recent $200 million grant awarded to Duke Energy from 

the US DOE helps further that goal. Grid modernization is a mechanism to further enable 

adoption and market penetration of EE, DSM and plug-in electric vehicle (PEVs) 

programs. In order to meet and support EE and DSM goals, the NCUC proposed a 

requirement to include grid modernization impacts in the IRP for North Carolina electric 

utilities (including Duke Energy Carolinas) in Docket E-100, Sub 126. On April 11, 

2012, the NCUC issued its Order Amending Commission Rule R8-60 and Adopting 

Commission Rule R8-60.1 in the matter of Integrated Resource Planning in North 

Carolina addressing Smart Grid Technology Plans, where the NCUC ordered that each 

DSM Program Participation and Capability

DSM Program Name

Participation as of 12/31/11 

(# of participants)

2012 Estimated Summer IRP 

Capability (MW)

IS 64 119

SG 93 44

PowerShare Mandatory 151 373

PowerShare Generator 8 17

PowerShare Voluntary 6 N/A

PowerShare CallOption

 Level 0/5 0 0

 Level 5/5 0 0

 Level 10/5 0 0

 Level 15/5 0 0

Power Manager 192,062 261

Total 192,384 814
42

utility provide information regarding the impacts of its smart grid deployment plan on the 

overall IRP. Distribution Automation is a part of Duke Energy Carolinas grid 

modernization program. The projected increases in DSM impacts due to grid 

modernization impacts incorporated into the 2012 IRP results in a corresponding 40 MW 

decrease in customers’ capacity needs by 2015. Over a 10 year period beginning in 2014, 

the projected impacts rise to 135 MW. 

Also per the above NCUC order, by July 1, 2013 and every two years thereafter, each 

utility subject to Rule R8-60 shall file with the NCUC its smart grid technology plan. 

Significant amendments or revisions to a smart grid technology plan shall be reported to 

the NCUC in each year in which the biennial smart grid technology plan is not required 

to be filed. Duke Energy Carolinas will comply with this requirement and a discussion 

of its smart grid technology plan will be included in the 2013 IRP. 
43 

5. SUPPLY-SIDE RESOURCES 

A. Existing Generation Plants in Service 

Duke Energy Carolinas’ generation portfolio includes a balanced mix of resources with 

different operating and fuel characteristics. This mix is designed to provide energy at the 

lowest reasonable cost to meet the Company’s obligation to serve its customers. Duke 

Energy Carolinas owned generation, as well as purchased power, is evaluated on a realtime basis in order to select and dispatch the lowest-cost resources to meet system load 

requirements. In 2011, Duke Energy Carolinas’ nuclear and coal-fired generating units 

met the vast majority of customer needs by providing 52.2% and 45.7%, respectively, of 

Duke Energy Carolinas’ energy from generation. Hydroelectric generation, CT 

generation, solar generation, long term PPAs, and economical purchases from the 

wholesale market supplied the remainder. 

Existing Resources 

The tables below list the Duke Energy Carolinas plants in service in North Carolina (NC) 

and South Carolina (SC) with plant statistics, and the system’s total generating capability. 
44 

Table 5.A 

North Carolina a,b,c,d,e

NAME UNIT SUMMER 

CAPACITY 

MW 

WINTER 

CAPACITY 

MW 

LOCATION PLANT TYPE 

Allen 1 162.0 167.0 Belmont, N.C. Conventional Coal

Allen 2 162.0 167.0 Belmont, N.C. Conventional Coal

Allen 3 261.0 270.0 Belmont, N.C. Conventional Coal

Allen 4 276.0 282.0 Belmont, N.C. Conventional Coal

Allen 5 266.0 275.0 Belmont, N.C. Conventional Coal

Allen Steam Station 1127.0 1161.0 

Belews Creek 1 1110.0 1135.0 Belews Creek, 

N.C. 

Conventional Coal 

Belews Creek 2 1110.0 1135.0 Belews Creek, 

N.C. 

Conventional Coal 

Belews Creek Steam 

Station 

 2220.0 2270.0 

Buck 5 128.0 131.0 Salisbury, N.C. Conventional Coal 

Buck 6 128.0 131.0 Salisbury, N.C. Conventional Coal 

Buck Steam Station 256.0 262.0 

Cliffside 5 552.0 556.0 Cliffside, N.C. Conventional Coal 

Cliffside Steam Station 552.0 556.0 

Marshall 1 380.0 380.0 Terrell, N.C. Conventional Coal 

Marshall 2 380.0 380.0 Terrell, N.C. Conventional Coal 

Marshall 3 658.0 658.0 Terrell, N.C. Conventional Coal 

Marshall 4 660.0 660.0 Terrell, N.C. Conventional Coal 

Marshall Steam 

Station 

 2078.0 2078.0 

Riverbend 4 94.0 96.0 Mt. Holly, N.C. Conventional Coal 

Riverbend 5 94.0 96.0 Mt. Holly, N.C. Conventional Coal 

Riverbend 6 133.0 136.0 Mt. Holly, N.C. Conventional Coal 

Riverbend 7 133.0 136.0 Mt. Holly, N.C. Conventional Coal 

Riverbend Steam 

Station 

 454.0 464.0 

TOTAL N.C. 

CONVENTIONAL 

COAL 

 6687.0 MW 6791.0 MW 

 

Buck 7C 25.0 30.0 Salisbury, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Buck 8C 25.0 30.0 Salisbury, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Buck 9C 12.0 15.0 Salisbury, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Buck Station CTs 62.0 75.0 

Dan River 4C 0.0 0.0 Eden, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Dan River 5C 24.0 31.0 Eden, N.C. Natural Gas/Oil-Fired 
45

NAME UNIT SUMMER 

CAPACITY 

MW 

WINTER 

CAPACITY 

MW 

LOCATION PLANT TYPE 

Combustion Turbine 

Dan River 6C 24.0 31.0 Eden, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Dan River Station CTs 48.0 62.0 

Lincoln 1 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln 2 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln 3 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln 4 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln 5 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln 6 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln 7 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln 8 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln 9 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln 10 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln 11 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln 12 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln 13 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln 14 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln 15 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln 16 79.2 93.0 Stanley, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Lincoln Station CTs 1267.2 1488.0 

Riverbend 8C 0.0 0.0 Mt. Holly, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Riverbend 9C 22.0 30.0 Mt. Holly, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Riverbend 10C 22.0 30.0 Mt. Holly, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Riverbend 11C 20.0 30.0 Mt. Holly, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 
46

NAME UNIT SUMMER 

CAPACITY 

MW 

WINTER 

CAPACITY 

MW 

LOCATION PLANT TYPE 

Riverbend Station CTs 64.0 90.0 

Rockingham 1 165.0 165.0 Rockingham, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Rockingham 2 165.0 165.0 Rockingham, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Rockingham 3 165.0 165.0 Rockingham, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Rockingham 4 165.0 165.0 Rockingham, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Rockingham 5 165.0 165.0 Rockingham, N.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Rockingham CTs 825.0 825.0 

Buck CT11 165.0 170.0 Salisbury, N.C. Natural Gas CT 

Combined Cycle 

Buck CT12 165.0 170.0 Salisbury, N.C. Natural Gas CT 

Combined Cycle 

Buck ST10 290.0 300.0 Salisbury, N.C. Natural Gas CT 

Combined Cycle 

Buck CTCC 620.0 640.0 

Total N.C. COMB. 

TURBINE 

2886.2 MW 3180.0 MW 

 

McGuire 1 1100.0 1156.0 Huntersville, N.C. Nuclear 

McGuire 2 1100.0 1156.0 Huntersville, N.C. Nuclear 

McGuire Nuclear 

Station 

 2200.0 2312.0 

TOTAL N.C. 

NUCLEAR

2200.0 MW 2312.0 MW 

 

Bridgewater 1 15.0 15.0 Morganton, N.C. Hydro 

Bridgewater 2 15.0 15.0 Morganton, N.C. Hydro 

Bridgewater 3 1.5 1.5 Morganton, N.C. Hydro 

Bridgewater Hydro 

Station 

 31.5 31.5 

Bryson City 1 0.48 0.48 Whittier, N.C. Hydro 

Bryson City 2 0 0 Whittier, N.C. Hydro 

Bryson City Hydro 

Station 

0.48 0.48 

Cowans Ford 1 81.3 81.3 Stanley, N.C. Hydro 

Cowans Ford 2 81.3 81.3 Stanley, N.C. Hydro 

Cowans Ford 3 81.3 81.3 Stanley, N.C. Hydro 

Cowans Ford 4 81.3 81.3 Stanley, N.C. Hydro 

Cowans Ford Hydro 

Station 

 325.2 325.2 

Lookout Shoals 1 9.3 9.3 Statesville, N.C. Hydro 

Lookout Shoals 2 9.3 9.3 Statesville, N.C. Hydro 
47

NAME UNIT SUMMER 

CAPACITY 

MW 

WINTER 

CAPACITY 

MW 

LOCATION PLANT TYPE 

Lookout Shoals 3 9.3 9.3 Statesville, N.C. Hydro 

Lookout Shoals Hydro 

Station 

 27.9 27.9 

Mountain Island 1 14 14 Mount Holly, N.C. Hydro 

Mountain Island 2 14 14 Mount Holly, N.C. Hydro 

Mountain Island 3 17 17 Mount Holly, N.C. Hydro 

Mountain Island 4 17 17 Mount Holly, N.C.

Mountain Island 

Hydro Station 

 62.0 62.0 

Oxford 1 20.0 20.0 Conover, N.C. Hydro 

Oxford 2 20.0 20.0 Conover, N.C. Hydro 

Oxford Hydro Station 40.0 40.0 

Rhodhiss 1 9.5 9.5 Rhodhiss, N.C. Hydro 

Rhodhiss 2 11.5 11.5 Rhodhiss, N.C. Hydro 

Rhodhiss 3 9.0 9.0 Rhodhiss, N.C. Hydro 

Rhodhiss Hydro 

Station 

 30.0 30.0 

Tuxedo 1 3.2 3.2 Flat Rock, N.C. Hydro 

Tuxedo 2 3.2 3.2 Flat Rock, N.C. Hydro 

Tuxedo Hydro Station 6.4 6.4 

Bear Creek 1 9.45 9.45 Tuckasegee, N.C. Hydro 

Bear Creek Hydro 

Station 

 9.45 9.45 

Cedar Cliff 1 6.4 6.4 Tuckasegee, N.C. Hydro 

Cedar Cliff Hydro 

Station 

 6.4 6.4 

Franklin 1 0 0 Franklin, N.C. Hydro 

Franklin 2 .6 .6 Franklin, N.C. Hydro 

Franklin Hydro 

Station 

 .6 .6 

Mission 1 0 0 Murphy, N.C. Hydro 

Mission 2 0 0 Murphy, N.C. Hydro 

Mission 3 0.6 0.6 Murphy, N.C. Hydro 

Mission Hydro Station 0.6 0.6 

Nantahala 1 50.0 50.0 Topton, N.C. Hydro 

Nantahala Hydro 

Station 

 50.0 50.0 

Tennessee Creek 1 9.8 9.8 Tuckasegee, N.C. Hydro 

Tennessee Creek 

Hydro Station 

 9.8 9.8 

Thorpe 1 19.7 19.7 Tuckasegee, N.C. Hydro 

Thorpe Hydro Station 19.7 19.7 

Tuckasegee 1 2.5 2.5 Tuckasegee, N.C. Hydro 

Tuckasegee Hydro 

Station 

 2.5 2.5 

Queens Creek 1 1.44 1.44 Topton, N.C. Hydro 
48

NAME UNIT SUMMER 

CAPACITY 

MW 

WINTER 

CAPACITY 

MW 

LOCATION PLANT TYPE 

Queens Creek Hydro 

Station 

1.44 1.44 

TOTAL N.C. HYDRO 623.97 MW 623.97 MW 

TOTAL N.C. SOLAR 8.43 MW 8.43 MW N.C. Solar 

TOTAL N.C. 

CAPABILITY

12,405.60 

MW

12,915.40 

MW

 
49 

Table 5.B 

South Carolina a,b,c,d,e

NAME UNIT SUMMER 

CAPACITY 

MW 

WINTER 

CAPACITY 

MW 

LOCATION PLANT TYPE 

Lee 1 100.0 100.0 Pelzer, S.C. Conventional Coal 

Lee 2 100.0 102.0 Pelzer, S.C. Conventional Coal 

Lee 3 170.0 170.0 Pelzer, S.C. Conventional Coal 

Lee Steam Station 370.0 372.0 

TOTAL S.C. 

CONVENTIONAL 

COAL 

 370.0 MW 372.0 MW 

 

Buzzard Roost 6C 20.0 20.0 Chappels, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Buzzard Roost 7C 20.0 20.0 Chappels, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Buzzard Roost 8C 20.0 20.0 Chappels, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Buzzard Roost 9C 20.0 20.0 Chappels, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Buzzard Roost 10C 16.0 16.0 Chappels, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Buzzard Roost 11C 16.0 16.0 Chappels, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Buzzard Roost 12C 16.0 16.0 Chappels, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Buzzard Roost 13C 16.0 16.0 Chappels, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Buzzard Roost 14C 16.0 16.0 Chappels, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Buzzard Roost 15C 16.0 16.0 Chappels, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Buzzard Roost Station 

CTs 

 176.0 176.0 

Lee 7C 41.0 41.0 Pelzer, S.C. Natural Gas/Oil-Fired

Combustion Turbine 

Lee 8C 41.0 41.0 Pelzer, S.C. Natural Gas/Oil-Fired

Combustion Turbine 

Lee Station CTs 82.0 82.0 

Mill Creek 1 74.42 92.4 Blacksburg, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Mill Creek 2 74.42 92.4 Blacksburg, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Mill Creek 3 74.42 92.4 Blacksburg, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Mill Creek 4 74.42 92.4 Blacksburg, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Mill Creek 5 74.42 92.4 Blacksburg, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 
50

NAME UNIT SUMMER 

CAPACITY 

MW 

WINTER 

CAPACITY 

MW 

LOCATION PLANT TYPE 

Mill Creek 6 74.42 92.4 Blacksburg, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Mill Creek 7 74.42 92.4 Blacksburg, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Mill Creek 8 74.42 92.4 Blacksburg, S.C. Natural Gas/Oil-Fired 

Combustion Turbine 

Mill Creek Station CTs 595.4 739.2 

TOTAL S.C. COMB 

TURBINE 

853.4 MW 997.2 MW 

 

Catawba 1 1129.0 1163.0 York, S.C. Nuclear 

Catawba 2 1129.0 1163.0 York, S.C. Nuclear 

Catawba Nuclear 

Station 

 2258.0 2326.0 

Oconee 1 846.0 865.0 Seneca, S.C. Nuclear 

Oconee 2 846.0 865.0 Seneca, S.C. Nuclear 

Oconee 3 846.0 865.0 Seneca, S.C. Nuclear 

Oconee Nuclear 

Station 

2538.0 2595.0 

TOTAL S.C. 

NUCLEAR 

4796.0 MW 4921.0 MW 

 

Jocassee 1 195.0 195.0 Salem, S.C. Pumped Storage 

Jocassee 2 195.0 195.0 Salem, S.C. Pumped Storage 

Jocassee 3 195.0 195.0 Salem, S.C. Pumped Storage 

Jocassee 4 195.0 195.0 Salem, S.C. Pumped Storage 

Jocassee Pumped 

Hydro Station 

 780.0 780.0 

Bad Creek 1 340.0 340.0 Salem, S.C. Pumped Storage 

Bad Creek 2 340.0 340.0 Salem, S.C. Pumped Storage 

Bad Creek 3 340.0 340.0 Salem, S.C. Pumped Storage 

Bad Creek 4 340.0 340.0 Salem, S.C. Pumped Storage 

Bad Creek Pumped 

Hydro Station 

1360.0 1360.0 

TOTAL PUMPED 

STORAGE 

2140.0 MW 2140.0 MW 

 

Cedar Creek 1 15.0 15.0 Great Falls, S.C. Hydro 

Cedar Creek 2 15.0 15.0 Great Falls, S.C. Hydro 

Cedar Creek 3 15.0 15.0 Great Falls, S.C. Hydro 

Cedar Creek Hydro 

Station 

 45.0 45.0 

Dearborn 1 14.0 14.0 Great Falls, S.C. Hydro 

Dearborn 2 14.0 14.0 Great Falls, S.C. Hydro 

Dearborn 3 14.0 14.0 Great Falls, S.C. Hydro 

Dearborn Hydro 

Station 

 42.0 42.0 
51

NAME UNIT SUMMER 

CAPACITY 

MW 

WINTER 

CAPACITY 

MW 

LOCATION PLANT TYPE 

Fishing Creek 1 11.0 11.0 Great Falls, S.C. Hydro 

Fishing Creek 2 9.5 9.5 Great Falls, S.C. Hydro 

Fishing Creek 3 9.5 9.5 Great Falls, S.C. Hydro 

Fishing Creek 4 11.0 11.0 Great Falls, S.C. Hydro 

Fishing Creek 5 8.0 8.0 Great Falls, S.C. Hydro 

Fishing Creek Hydro 

Station 

 49.0 49.0 

Gaston Shoals 3 0 0 Blacksburg, S.C. Hydro 

Gaston Shoals 4 1.0 1.0 Blacksburg, S.C. Hydro 

Gaston Shoals 5 1.0 1.0 Blacksburg, S.C. Hydro 

Gaston Shoals 6 0 0 Blacksburg, S.C. Hydro 

Gaston Shoals Hydro 

Station 

 2.0 2.0 

Great Falls 1 3.0 3.0 Great Falls, S.C. Hydro 

Great Falls 2 3.0 3.0 Great Falls, S.C. Hydro 

Great Falls 3 0 0 Great Falls, S.C. Hydro 

Great Falls 4 0 0 Great Falls, S.C. Hydro 

Great Falls 5 3.0 3.0 Great Falls, S.C. Hydro 

Great Falls 6 3.0 3.0 Great Falls, S.C. Hydro 

Great Falls 7 0 0 Great Falls, S.C. Hydro 

Great Falls 8 0 0 Great Falls, S.C. Hydro 

Great Falls Hydro 

Station 

 12.0 12.0 

Rocky Creek 1 0 0 Great Falls, S.C. Hydro 

Rocky Creek 2 0 0 Great Falls, S.C. Hydro 

Rocky Creek 3 0 0 Great Falls, S.C. Hydro 

Rocky Creek 4 0 0 Great Falls, S.C. Hydro 

Rocky Creek 5 0 0 Great Falls, S.C. Hydro 

Rocky Creek 6 0 0 Great Falls, S.C. Hydro 

Rocky Creek 7 0 0 Great Falls, S.C. Hydro 

Rocky Creek 8 0 0 Great Falls, S.C. Hydro 

Rocky Creek Hydro 

Station 

 0 0 

Wateree 1 17.0 17.0 Ridgeway, S.C. Hydro 

Wateree 2 17.0 17.0 Ridgeway, S.C. Hydro 

Wateree 3 17.0 17.0 Ridgeway, S.C. Hydro 

Wateree 4 17.0 17.0 Ridgeway, S.C. Hydro 

Wateree 5 17.0 17.0 Ridgeway, S.C. Hydro 

Wateree Hydro Station 85.0 85.0 

Wylie 1 18.0 18.0 Fort Mill, S.C. Hydro 

Wylie 2 18.0 18.0 Fort Mill, S.C. Hydro 

Wylie 3 18.0 18.0 Fort Mill, S.C. Hydro 

Wylie 4 18.0 18.0 Fort Mill, S.C. Hydro 

Wylie Hydro Station 72.0 72.0 

99 Islands 1 1.6 1.6 Blacksburg, S.C. Hydro 

99 Islands 2 1.6 1.6 Blacksburg, S.C. Hydro 

99 Islands 3 1.6 1.6 Blacksburg, S.C. Hydro 
52

NAME UNIT SUMMER 

CAPACITY 

MW 

WINTER 

CAPACITY 

MW 

LOCATION PLANT TYPE 

99 Islands 4 1.6 1.6 Blacksburg, S.C. Hydro 

99 Islands 5 0 0 Blacksburg, S.C. Hydro 

99 Islands 6 0 0 Blacksburg, S.C. Hydro 

99 Islands Hydro 

Station 

 6.4 6.4 

Keowee 1 76.0 76.0 Seneca, S.C. Hydro 

Keowee 2 76.0 76.0 Seneca, S.C. Hydro 

Keowee Hydro Station 152.0 152.0 

TOTAL S.C. HYDRO 465.4 MW 465.4 MW 

TOTAL S.C. 

CAPABILITY 

8,624.8 MW 8,895.6 MW 

NAME UNIT SUMMER 

CAPACITY 

MW 

WINTER 

CAPACITY 

MW 

LOCATION PLANT TYPE 

Table 5.C 

Total Generation Capability a,b,c,d,e

NAME SUMMER CAPACITY 

MW

WINTER CAPACITY 

MW

TOTAL DUKE ENERGY CAROLINAS 

GENERATING CAPABILITY 

21,030.4 21,811.0

Note a: Unit information is provided by State, but resources are dispatched on a system-wide basis. 

Note b: Summer and winter capability does not take into account reductions due to future environmental 

emission controls. 

Note c: Summer and winter capability reflects system configuration as of April 4, 2012. 

Note d: Catawba Units 1 and 2 capacity reflects 100% of the station’s capability, and does not factor in the 

North Carolina Municipal Power Agency #1’s (NCMPA#1) decision to sell or utilize its 832 MW retained 

ownership in Catawba. 

Note e: The Catawba units’ multiple owners and their effective ownership percentages are: 

CATAWBA OWNER PERCENT OF OWNERSHIP 

Duke Energy Carolinas 19.246% 

North Carolina Electric 

Membership Corporation 

(NCEMC) 

30.754% 

NCMPA#1 37.5% 

Piedmont Municipal Power 

Agency (PMPA) 

12.5% 
53

Changes to Existing Resources 

Retirements of generating units, system capacity uprates and derates, purchased power 

contract expirations, and adjustments in EE and DSM capability affect the amount of 

resources Duke Energy Carolinas will need to meet its load obligation. Thus, Duke 

Energy Carolinas will need to adjust the capabilities of its resource mix over the 20-year 

planning horizon. Below are the known and/or anticipated changes and their respective 

impacts on the resource mix. 

New Cliffside Pulverized Coal Unit 

Cliffside Unit 6 pulverized coal plant is expected to operate at 50-100% output for 

systems and equipment guarantee testing through the summer of 2012. The unit is 

expected to be declared commercial in September of 2012. 

Bridgewater Hydro Powerhouse Upgrade 

Bridgewater Hydro Station generating unit upgrades were operational November 2011. 

The previous generating units were replaced by two 15 MW units and a small 1.5 MW 

unit representing an 8.5 MW increase in station capability. The new generating units will 

be used to meet continuous release requirements and system peak. 

Buck Combined Cycle Natural Gas Unit 

The new Buck Combustion Turbine Combined Cycle (CTCC) unit was operational 

November 2011. The 620 MW natural gas-fired CTCC generating station achieves high 

operational flexibility, high thermal efficiency, utilizing state-of-the-art environmental 

control technology to minimize plant emissions. 

 

Dan River Combined Cycle Natural Gas Unit 

The 620 MW Dan River CC unit is scheduled to be operational by the end of 2012. 

Construction is underway and the project is currently over 90% complete. 

Lee Steam Station Natural Gas Conversion 

Lee Steam Station was originally designed to generate with natural gas or coal as a fuel 

source. Switching fuel sources from coal to natural gas could prove to be an economic 

solution to avoid adding costly pollution control equipment or replacing the 370 MW of 

capacity with a more costly alternative. Previous plans were for conversion of all three 

Lee units to natural gas. However upon further evaluation, for IRP planning purposes, 

Lee Units 1 and 2 will be retired as coal units with no plans for conversion to natural gas 

in 2015. Lee Unit 3 is assumed to be retired as a coal unit in the fourth quarter of 2014 

and converted to natural gas by January 1, 2015. Preliminary engineering and analysis 

has been completed. Detailed project development and regulatory efforts began in 2011, 

and will continue into 2012. 
54

Generating Units Projected To Be Retired 

Various factors have an impact on decisions to retire existing generating units. These 

factors, including the investment requirements necessary to support ongoing operation of 

generation facilities, are continuously evaluated as future resource needs are considered. 

Table 5.D reflects current assessments of generating units with identified decision dates 

for retirement or major refurbishment. 

There are two requirements related to the Company’s retirement of 800 MWs of older 

coal units. The first, a condition set forth in the NCUC Order in Docket No. E-7, Sub 

790, granting a CPCN to build Cliffside Unit 6, requires the retirement of the existing 

Cliffside Units 1-4 no later than the commercial operation date of the new unit, and 

retirement of older coal-fired generating units (in addition to Cliffside Units 1-4) on a 

MW-for-MW basis, considering the impact on the reliability of the system, to account for 

actual load reductions realized from the new EE and DSM programs up to the MW level 

added by the new Cliffside unit3

. In addition to retiring Cliffside Units 1-4, the air permit 

for the new Cliffside unit requires the retirement of 350 MWs of older coal generation by 

2015, a further 200 MWs by 2016, and an additional 250 MWs by 2018. If the NCUC 

determines that the scheduled retirement of any unit identified for retirement pursuant to 

the IRP will have a material adverse impact of the reliability of electric generating 

system, Duke Energy Carolinas may seek modification of this plan. 

Additionally, multiple environmental regulatory issues are presently converging as the 

EPA has proposed new rules to regulate multiple areas relating to generation resources. 

These new rules, if implemented, will increase the need for the installation of additional 

control technology or retirement of coal fired generation in the 2014 to 2018 timeframe. 

Anticipating that there will be increased control requirements, the Carolinas 2012 IRP 

continues to include a planning assumption that all coal-fired generation that does not 

have an installed SO2 scrubber will be retired in 2015. 

Table 5.D shows the assumptions used for planning purposes rather than firm 

commitments concerning the specific units to be retired and/or their exact retirement 

dates. The conditions of the units are evaluated at least annually and decision dates are 

revised as appropriate. Duke Energy Carolinas will develop orderly retirement plans that 

consider the implementation, evaluation, and achievement of EE goals, system reliability 

considerations, long-term generation maintenance and capital spending plans, workforce 

allocations, long-term contracts including fuel supply and contractors, long-term 

transmission planning, and major site retirement activities. 

3

 NCUC Docket No. E-7, Sub 790 Order Granting CPCN with Conditions, March 21, 2007. 
55

Table 5.D

Projected Unit Retirements 

 

STATION CAPACITY 

IN MW 

LOCATION EXPECTED 

RETIREMENT 

PLANT TYPE 

Buck 3* 75 Salisbury, N.C. RETIRED Conventional Coal 

Buck 4* 38 Salisbury, N.C. RETIRED Conventional Coal 

Cliffside 1* 38 Cliffside, N.C. RETIRED Conventional Coal 

Cliffside 2* 38 Cliffside, N.C. RETIRED Conventional Coal 

Cliffside 3* 61 Cliffside, N.C. RETIRED Conventional Coal 

Cliffside 4* 61 Cliffside, N.C. RETIRED Conventional Coal 

Dan River 1* 67 Eden, N.C. RETIRED Conventional Coal 

Dan River 2* 67 Eden, N.C. RETIRED Conventional Coal 

Dan River 3* 142 Eden, N.C. RETIRED Conventional Coal 

Buzzard Roost 6C** 22 Chappels, S.C. 10/1/2012 Combustion Turbine

Buzzard Roost 7C** 22 Chappels, S.C. 10/1/2012 Combustion Turbine

Buzzard Roost 8C** 22 Chappels, S.C. 10/1/2012 Combustion Turbine

Buzzard Roost 9C** 22 Chappels, S.C. 10/1/2012 Combustion Turbine

Buzzard Roost 10C** 18 Chappels, S.C. 10/1/2012 Combustion Turbine

Buzzard Roost 11C** 18 Chappels, S.C. 10/1/2012 Combustion Turbine

Buzzard Roost 12C** 18 Chappels, S.C. 10/1/2012 Combustion Turbine

Buzzard Roost 13C** 18 Chappels, S.C. 10/1/2012 Combustion Turbine

Buzzard Roost 14C** 18 Chappels, S.C. 10/1/2012 Combustion Turbine

Buzzard Roost 15C** 18 Chappels, S.C. 10/1/2012 Combustion Turbine

Riverbend 8C** 0 Mt. Holly, N.C. 10/1/2012 Combustion Turbine

Riverbend 9C** 22 Mt. Holly, N.C. 10/1/2012 Combustion Turbine

Riverbend 10C** 22 Mt. Holly, N.C. 10/1/2012 Combustion Turbine

Riverbend 11C** 20 Mt. Holly, N.C. 10/1/2012 Combustion Turbine

Buck 7C** 25 Spencer, N.C. 10/1/2012 Combustion Turbine

Buck 8C** 25 Spencer, N.C. 10/1/2012 Combustion Turbine

Buck 9C** 12 Spencer, N.C. 10/1/2012 Combustion Turbine

Dan River 4C** 0 Eden, N.C. 10/1/2012 Combustion Turbine

Dan River 5C** 24 Eden, N.C. 10/1/2012 Combustion Turbine

Dan River 6C** 24 Eden, N.C. 10/1/2012 Combustion Turbine

Riverbend 4* 94 Mt. Holly, N.C. 4/15/2015 Conventional Coal 

Riverbend 5* 94 Mt. Holly, N.C. 4/15/2015 Conventional Coal 

Riverbend 6*** 133 Mt. Holly, N.C. 4/15/2015 Conventional Coal 

Riverbend 7*** 133 Mt. Holly, N.C. 4/15/2015 Conventional Coal 

Buck 5*** 128 Spencer, N.C. 4/15/2015 Conventional Coal 

Buck 6*** 128 Spencer, N.C. 4/15/2015 Conventional Coal 

Lee 1*** 100 Pelzer, S.C. 4/15/2015 Conventional Coal 

Lee 2*** 100 Pelzer, S.C. 4/15/2015 Conventional Coal 

Lee 3**** 170 Pelzer, S.C. 1/1/2015 Conventional Coal 

Notes: 

* Retirement assumptions associated with the conditions in the NCUC Order in Docket No. E-7, 

Sub 790, granting a CPCN to build Cliffside Unit 6. 
56

** The old fleet combustion turbines retirement dates were accelerated in 2009 based on derates, 

availability of replacement parts and the general condition of the remaining units. 

*** For the 2012 IRP process, remaining coal units without scrubbers were assumed to be retired by 

4/15/2015. Based on the continued increased regulatory scrutiny from an air, water and waste 

perspective, these units will likely either be required to install additional controls or retire. If final 

regulations or new legislation allows for latitude in the retirement date if a retirement commitment 

is made, versus adding controls, the retirement date may be adjusted. For example, per the MATS 

rule, if new generation will be located at a retired facility site, the retirement of the existing facility 

may be extended to 4/15/2016. 

**** Analysis has been performed to determine the feasibility of the conversion of the Lee 3 coal unit

to a natural gas unit. As this project is further evaluated, this date is subject to change. 

Fuel Supply 

Duke Energy Carolinas’ current fuel usage consists primarily of coal and uranium. Oil 

and gas have traditionally been used for peaking generation, but natural gas has begun to 

play a more important role in the fuel mix due to lower pricing and the addition of the 

Buck Combined Cycle plant. The addition of the Dan River Combined Cycle plant later 

this year will further increase the importance of gas to the Company’s generation 

portfolio. 

Coal 

Until the economic downturn in 2008, Duke Energy Carolinas had burned approximately 

18 million tons of coal annually. In 2009, the burn dropped substantially and has 

remained in the range of 14 to 16 million tons of coal. The projected coal burn for the 

near-term is declining further due to lower gas prices, the addition of the Buck CC plant, 

more stringent environmental regulations on coal units, and lower load growth. 

The Company continues to procure coal primarily from Central Appalachian (CAPP) 

coal mines that is delivered by the Norfolk Southern and CSX railroads. Although CAPP 

coal market prices are currently below the marginal mining costs for many mines, due to 

this year’s unseasonably mild winter and the resulting low gas prices, CAPP prices are 

projected to recover over the next couple of years. Longer term, CAPP prices are 

expected to rise due to a continuing decline in CAPP reserves quality, increasingly 

stringent safety requirements, and longer and increasingly difficult environmental 

permitting for CAPP mines. 

For this reason, the Company has been testing Northern Appalachian (NAPP) and Illinois 

Basin (ILB) coals at its scrubbed stations. These tests will continue into the future and 

will provide valuable information on operational and environmental impacts of burning 

these coals in various blends. This information will assist the Company in determining 

which coal blends can be burned without requiring additional capital investment, as well 
57

as the capital investments required to consume even greater amounts of non-CAPP coal. 

The purpose of this work is not to lock the Company’s plants into new fuel types, but to 

increase the fuel flexibility of each station so that the Company can nimbly respond to 

changes in the relative coal prices of different coal types. 

Natural Gas 

The issues affecting natural gas supply and demand are numerous and complex. An 

unusually warm winter has resulted in oversupply within the US gas market. Actions and 

reactions associated with attempts to bring this market into balance are projected to carry 

some long term consequences for the entire domestic energy industry. While the low 

market prices for gas have helped reduce industrial production costs, boost 

manufacturing output and demand for power, producers and pipelines are cutting back on 

investments in future gas drilling and redirecting capital to higher price margins in oil and 

petroleum liquids. Gas directed drillings rigs are down to 542, a ten-year low. In spite of 

the falling prices, the size of the economic reserve basis has increased due to significant 

gains in rig efficiency, improvements in wellhead productivity, and several other factors. 

Among these is the fact that gas is also being produced in the process of drilling for oil 

and liquids, drilling cost carries from asset sales, and a backlog of previously drilled but 

uncompleted wells that are holding gas supplies higher. Once again, the US is on course 

to set another record in total marketed US production of natural gas. These market 

responses have managed to stabilize the wholesale gas prices at around $2.50 - 

$3.00/mmbtu for now, and they are not likely to push prices significantly higher in the 

near term. Substantial producer discipline going forward or additional new sources of 

demand will be required to pull the higher marginal cost supplies back into this market. 

 

The US shale boom was partially the result of innovation in the face of high marginal 

domestic gas prices and the threat of a future marked by a globally linked and high 

volatile liquefied natural gas (LNG) pricing. Today, the consensus view is that the US 

will enjoy a competitive price advantage over Asian and European competitors for the 

foreseeable future. This is driving massive energy investments. New or expanded 

industrial demand, calls for natural gas vehicle subsidies and fueling infrastructure, and 

preparations for exportation of LNG are coupled with critical decisions that have to be 

made in the US power industry. Utilities are making investment decisions today which 

will have lasting impacts on their generation fleets. They cannot simply defer these 

decisions either, as various environmental deadlines now loom large with 2015 EPA 

regulatory compliance dates. Given the relatively low pricing in the NYMEX forward 

curve and weak fundamentals, much of the coal displacement projections will soon 

become reality as utilities retire existing uncontrolled coal facilities instead of installing 

emissions controls. Natural gas has become the default option for new generation. 

While the US has ample economic gas reserves for at least the next two decades, natural 
58

gas should still be viewed as a bridge fuel, rather than a final solution. The US will need 

to start addressing its nuclear end of life decisions within the next decade. This could put 

an enormous strain on US gas supplies if gas is the only replacement. New federal 

regulations are likely to be proposed in 2013 which will govern permitting, wastewater 

disposal and fugitive methane emissions. These regulations will add to the cost of gas 

production and should allow coal to recover some of its lost market share, but new 

regulations are unlikely to be so stringent that they become game changers. A significant 

price on carbon in the US has the potential to change the equation, but these indications 

are not currently on the horizon. Shale has already begun to reshape the US energy 

industry, but the currently low market prices will elicit changes in investment and 

demand that over time will pressure prices to move higher. 

Nuclear Fuel 

To provide fuel for Duke Energy Carolinas’ nuclear fleet, the Company maintains a 

diversified portfolio of natural uranium and downstream services supply contracts from 

around the world. 

Requirements for uranium concentrates, conversion services and enrichment services are 

primarily met through a portfolio of long-term supply contracts. The contracts are 

diversified by supplier, country of origin and pricing. In addition, Duke Energy 

Carolinas staggers its contracting so that its portfolio of long-term contracts covers the 

majority of fleet fuel requirements in the near-term and decreasing portions of the fuel 

requirements over time thereafter. By staggering long-term contracts over time, the 

Company’s purchase price for deliveries within a given year consists of a blend of 

contract prices negotiated at many different periods in the markets, which has the effect 

of smoothing out the Company’s exposure to price volatility. Diversifying fuel suppliers 

reduces the Company’s exposure to possible disruptions from any single source of 

supply. Near-term requirements not met by long-term supply contracts have been and are 

expected to be fulfilled with spot market purchases. 

Due to the technical complexities of changing suppliers of fuel fabrication services, Duke 

Energy Carolinas generally sources these services to a single domestic supplier on a 

plant-by-plant basis using multi-year contracts. 

As fuel with a low cost basis is used and lower-priced legacy contracts are replaced with 

contracts at higher market prices, nuclear fuel expense is expected to increase in the 

future. Although the costs of certain components of nuclear fuel are expected to increase 

in future years, nuclear fuel costs on a kWh basis will likely continue to be a fraction of 

the kWh cost of fossil fuel. Therefore, customers will continue to benefit from the 

Company’s diverse generation mix and the strong performance of its nuclear fleet 

through lower fuel costs than would otherwise result absent the significant contribution of 
59

nuclear generation to meeting customers’ demands.

B. Renewable Resources and Renewable Energy Initiatives 

1. Overview of Planning Assumptions 

Duke Energy Carolinas’ plans regarding renewable energy resources within this IRP 

are based primarily upon the presence of existing renewable energy requirements, as 

well as the potential introduction of additional renewable energy requirements in the 

future. 

Regarding existing renewable requirements, the Company is committed to meeting the 

requirements of the NC REPS. This is a statutory requirement enacted in 2007 

mandating that Duke Energy Carolinas supply the equivalent of 12.5% of retail 

electricity sales in North Carolina from eligible renewable energy resources and/or EE 

savings by 2021. NC REPS allows for compliance utilizing not only renewable energy 

resources supplying bundled energy and renewable energy certificates (RECs) and EE, 

but also the purchase of unbundled RECs (both in-state and out-of-state) and thermal 

RECs. Therefore, the actual energy delivered to the Duke Energy Carolinas system is 

impacted by the amount of EE, unbundled RECs and thermal RECs utilized for 

compliance. 

With respect to potential new renewable energy portfolio standard requirements, the 

Company’s plans in this IRP account for the possibility of future requirements that will 

result in additional renewable resource development beyond the NC REPS 

requirements. Renewable requirements have been adopted in many states across the 

nation, and have also been contemplated as a federal measure and by members of the 

General Assembly in South Carolina. As such, the Company believes it is reasonable 

to plan for additional renewable requirements within the IRP beyond what presently 

exists with the NC REPS requirements. 

Although many reasonable assumptions could be made regarding such future renewable 

requirements, the Company has assumed for purposes of the 2012 IRP that a new 

legislative requirement (imposed by either federal or state level legislation) would be 

implemented in the future that would result in additional renewable resource 

development in South Carolina. For planning purposes, Duke Energy Carolinas has 

assumed that the requirement would be similar in many respects to the NC REPS 

requirement, but with a different implementation schedule. Specifically, the Company 

has assumed that this requirement would have an initial 3% milestone in 2016 and 

would gradually increase to a 12.5% level by 2025. Similar to NC REPS, this assumed 
60

legislative requirement would incorporate both renewable energy and EE, as well as a 

limited capability to utilize out of state unbundled purchases of RECs. Further, this 

assumed requirement would have a solar set-aside requirement comparable to that in 

NC REPS, but would not contain any additional set-asides such as the poultry waste or 

swine waste set-aside requirements that are part of NC REPS. Finally, no assumptions 

related to a cost-cap feature that may limit development of renewables and ultimate cost 

to customers were made with this assumed legislation, whereas the Company’s 

projections of renewable resource development for NC REPS are governed by the 

statutory cost caps within the law. 

The Company has assessed the current and potential future costs of renewable and 

traditional technologies and, based on this analysis, the IRP modeling process shows 

that, for the most part, the amount of renewable energy resources that will be developed 

over the planning horizon will be defined by the existing and anticipated statutory 

renewable energy requirements described above. In other words, the IRP modeling 

does not indicate any material quantity of renewable resource development over and 

above the required levels, unless incentivized with state and federal tax incentives. 

The increased level of QF solar facilities due to these incentives has been incorporated 

into the IRP modeling. 

2. Summary of Expected Renewable Resource Capacity Additions 

Based on the planning assumptions noted above regarding current and potential future 

renewable energy requirements, the Company projects that a total of approximately 970 

MWs (nameplate) of renewable energy resources will be interconnected to the Duke 

Energy Carolinas system by 2021, with that figure growing to approximately 1,665 

MWs by the end of the planning horizon in 2032. Actual results could vary 

substantially, with key drivers of different outcomes being future legislative 

requirements; relative costs of various renewable technologies in relation to traditional 

technologies; and various impediments impacting resource development, including 

permitting requirements, transmission and interconnection issues, or other matters. 

It should be noted that many renewable technologies are intermittent in nature and that 

such resources therefore may not be contributing energy or capacity benefits to the 

Company’s load requirements at any particular point in time. The details of the 

forecasted capacity additions, including both nameplate capacity and the expected 

contribution towards the Company’s peak load needs, are summarized in Table 5.E 

below. 

 
61

Table 5.E Expected Renewable Resource Capacity Additions 

3. Changes in Renewable Planning Assumptions Since 2011 

The Company’s assumptions relating to renewable energy requirements (existing and 

anticipated) included in the 2012 IRP are largely similar to the assumptions within the 

Company’s 2011 IRP. However, the Company’s expectations regarding how those 

requirements will be met have evolved. Changes from the prior year are summarized 

below. 

As compared to last year’s IRP, the Company has assumed the development and 

interconnection of more solar resources over the planning horizon, along with 

corresponding reductions in the development of wind and biomass resources. 

The installed cost of solar resources has fallen dramatically over the past few years, 

driven by increased industry scale, standardization, and technological innovation. Many 

industry participants expect the cost of solar to continue a steady decline through the end 

of the decade, albeit at a slower pace than in recent years. Solar resources benefit from 

generous supportive federal and state policies that are expected to be in place through the 

Year Wind Solar Biomass Total Wind Solar Biomass Total

2012 6 8 1 16 40 17 1 58

2013 0 28 10 38 0 56 10 66

2014 15 68 20 103 100 135 20 256

2015 15 127 30 171 100 253 30 383

2016 20 160 51 231 134 320 51 505

2017 20 176 60 256 135 352 60 546

2018 20 199 68 288 135 398 68 602

2019 48 235 90 374 322 471 90 883

2020 48 247 99 395 323 495 99 917

2021 49 269 108 426 324 538 108 970

2022 56 324 135 516 376 649 135 1160

2023 57 346 133 536 378 692 133 1204

2024 57 368 142 567 381 736 142 1258

2025 62 420 154 637 416 840 154 1411

2026 63 443 155 661 419 885 155 1459

2027 63 464 156 684 422 928 156 1507

2028 65 473 163 701 430 946 163 1540

2029 66 483 166 715 439 965 166 1571

2030 67 492 170 729 448 984 170 1602

2031 69 502 173 743 457 1004 173 1633

2032 69 502 173 758 457 1004 173 1665

Renewables

MW Contribution to Summer Peak MW Nameplate
62

middle of this decade or longer. In combination with declining costs, such supportive 

policies have made solar resources increasingly competitive with other renewable 

resources, including wind and biomass, at least in the near-term. While uncertainty 

remains around possible alterations or extensions of policy support, as well as the pace of 

future cost declines, the Company fully expects solar resources to contribute to our RPS 

compliance efforts beyond the solar set-aside minimum threshold for NC REPS, and 

correspondingly in SC. 

The Company recognizes that several land-based wind developers are presently pursuing 

projects of significant size in North Carolina. The Company believes it is reasonable to 

expect that land-based wind will be developed in both North and South Carolina within 

the planning horizon. However, land-based wind in the US has benefitted from 

supportive federal tax policies set to decline at the end of 2012. Although the Company 

expects to rely upon wind resources for our RPS compliance effort, the extent and timing 

of that reliance will likely vary commensurately with changes to supporting policies and 

prevailing market prices. The Company also has observed that opportunities currently 

exist, and may continue to exist, to transmit land-based wind energy resources into the 

Carolinas from other regions, which could supplement the amount of wind that could be 

developed within the Carolinas. 

The Company’s expectations regarding biomass resources for the 2012 IRP are more 

modest than its assumptions within its prior two IRPs. Duke Energy Carolinas has 

reduced its reliance upon biomass resources in part due to continued uncertainties around 

the developable amount of such resources in the Carolinas, uncertainties related to the 

EPA’s various rulemaking proceedings, and the projected availability of other forms of 

renewable resources to offset the needs for biomass. 

The changes in the renewable strategy discussed above have an impact on the Company’s 

projected resource need in the future. Even though solar facilities have a lower 

contribution to the Company’s peak than biomass resources, the projected increase in 

volume of solar facilities results in a net increase of renewable resources available to 

meet peak demand requirements in 2015 of approximately 40 MW. 

In general, the Company expects a mix of resources will ultimately be used for RPS 

compliance, with the specifics of that mix determined in large part by policy 

developments over the coming 5-10 years. Costs for all the resources discussed above 

are highly dependent upon future subsidies, or lack thereof, and the Company’s 

procurement efforts will vary accordingly. Furthermore, the Company values portfolio 

diversification from a resource perspective, particularly in light of the varying load 

profiles of the resources in question. 

 
63

4. Further Details on Compliance with NC REPS 

A more detailed discussion of the Company’s plans to comply with the NC REPS 

requirements can be found in the Company’s NC REPS Compliance Plan (Compliance 

Plan), which the Company submits to the NCUC as a separate document within the 

same docket as this IRP. 

Details of that Compliance Plan are not duplicated here, although it is important to note 

that various details of the NC REPS law have impacts on the amount of energy and 

capacity that the Company projects to obtain from renewable resources to help meet the 

Company’s long term resource needs. For instance, NC REPS contains several detailed 

parameters, including technology specific set-aside requirements for solar, swine waste, 

and poultry waste resources; capabilities to utilize EE savings and unbundled REC 

purchases from in-state or out-of-state resources, and RECs derived from thermal (nonelectrical) energy; and a statutory spending limit to protect customers from cost 

increases stemming from renewable energy procurement or development. Each of 

these features of NC REPS has implications on the amount of renewable energy and 

capacity the Company forecasts to obtain over the planning horizon of this IRP. 

Additional details on NC REPS compliance can be found in the Company’s 

Compliance Plan. 

C. Supply-Side Resource Screening 

For purposes of the 2012 IRP, the Company considered a diverse range of technology 

choices utilizing a variety of different fuels, including supercritical pulverized coal 

(SCPC) units with carbon capture and sequestration (CCS), Integrated Gasification 

Combined Cycle (IGCC) with carbon capture and sequestration, combustion turbines 

(CTs), combined cycle (CC) with duct firing units, and nuclear units. In addition, Duke 

Energy Carolinas considered renewable technologies such as wind, landfill gas, and solar 

in this year’s screening analysis. 

For the 2012 IRP screening analyses, the Company screened technology types within 

their own respective general categories of base load, peaking/intermediate, and 

renewable, with the ultimate goal of screening to pass the best alternatives from each of 

these three categories to the integration process. As in past years, the reason for the 

initial screening analysis is to determine the most viable and cost-effective resources for 

further evaluation. This initial screening evaluation is necessary to narrow down options 

to be further evaluated in the quantitative analysis process. 
64

 

1. Process Description 

Information Sources 

The cost and performance data for each technology being screened is based on research 

and information from several sources. These sources include, but may not be limited to 

the following: Duke Energy’s New Generation Project Development, Emerging 

Technologies, and Analytical Engineering; the EPRI Technology Assessment Guide 

(TAG®); and studies performed by and/or information gathered from external sources. 

In addition, fuel and operating cost estimates are developed internally by Duke Energy, 

or from other sources such as those mentioned above, or a combination of the two. EPRI 

information or other information or estimates from external studies are not site-specific, 

but generally reflect the costs and operating parameters for installation in the Carolinas. 

Finally, every effort is made to ensure that cost and other parameters are current and 

include similar scope across the technologies being screened. While this has always been 

important, keeping cost estimates across a variety of technology types consistent in 

today’s markets for commodities, construction materials, and manufactured equipment, 

remains very difficult. 

 

Technical Screening 

The first step in the Company’s supply-side screening process for the IRP is a technical 

screening of the technologies to eliminate those that have technical limitations, 

commercial availability issues, or are not feasible in the Duke Energy Carolinas service 

territory. A brief explanation of the technologies excluded at this point and the basis for 

their exclusion follows: 

• Geothermal was eliminated because there are no suitable geothermal 

resources in the region to develop into a power generation project. 

• Advanced energy storage technologies (Lead acid, Li-ion, Sodium Ion, Zinc 

Bromide, Fly wheels, pumped storage, etc) remain relatively expensive, as 

compared to conventional generation sources, but the benefits to a utility such 

as the ability to shift load and firm renewable generation are obvious. 

Research, development, and demonstration continue within Duke Energy 

Corporation (Duke Energy). Currently, Duke Energy Generation Services is 

installing a 36 MW advanced acid lead battery at the Notrees wind farm in 

Texas that is scheduled for start-up in late 2012. Duke Energy is also 

installing a 75 kW battery in Indiana which will be integrated with solar 

generation and electric vehicle charging stations. Duke Energy also has other 

storage system tests within its Envision Energy demonstration in Charlotte, 

which includes two Community Energy Storage (CES) systems of 24 kW, and 
65

three substation demonstrations less than 1 MW each. 

• Compressed Air Energy Storage (CAES), although demonstrated on a utility 

scale and generally commercially available, is not a widely applied 

technology and remains relatively expensive. The high capital requirements 

for these resources arise from the fact that suitable sites that possess the 

proper geological formations and conditions necessary for the compressed air 

storage reservoir are relatively scarce. 

• Small modular nuclear reactors (SMR) are generally defined as having 

capabilities of less than 300 MW. In 2012, U.S. Department of Energy (DOE) 

solicited bids for companies to participate in a small modular reactor grant 

program with the intent to “promote the accelerated commercialization of 

SMR technologies to help meet the nation’s economic energy security and 

climate change objectives.” The focus of the grant is the first-of-a-kind 

engineering associated with NRC design certification and licensing efforts in 

order to demonstrate the ability to achieve NRC design certification and 

licensing to support SMR plant deployment on a domestic site by 2022. 

• Fuel Cells, although originally envisioned as being a competitor for 

combustion turbines and central power plants, are now targeted to mostly 

distributed power generation systems. The size of the distributed generation 

applications ranges from a few kW to tens of MW in the long-term. Cost and 

performance issues have generally limited their application to niche markets 

and/or subsidized installations. While a medium level of research and 

development continues, this technology is not commercially available for 

utility-scale application. 

• Poultry waste and Swine waste digesters remain relatively expensive and are 

often faced with operational and/or permitting challenges. Research, 

development, and demonstration continue, but these technologies remain 

generally too expensive or face obstacles that make them impractical energy 

choices outside of specific mandates calling for use of these technologies. 

• Off-shore wind, although demonstrated on a utility scale and commercially 

available, is not a widely applied technology and not easily permitted. This 

technology remains expensive and has yet to actually be constructed anywhere 

in the United States. Currently, the Cape Wind project in Massachusetts has 

been approved with assistance from the federal government but has not begun 

construction. 
66

• Although commercially available, a 3x3x1 1200 MW natural gas combined 

cycle unit was modeled as sensitivity. The 2x2x1 700 MW combined cycle 

option more closely mirrored the resource needs for new generation in the 

near term. Review of the 3x3x1 combined cycle unit revealed that even 

though these units are efficient and cost-effective, the limits on operational 

flexibility outweighed the benefits of this unit. This unit will be considered in 

more detail in 2013. 

Economic Screening 

The supply-side screening analysis uses the same fuel prices for coal and natural gas, and 

NOx, SO2, and CO2 allowance prices as those utilized downstream in the System 

Optimizer analysis (discussed in Chapter 8). 

The Company screens all technologies using relative dollar per kilowatt-year ($/kW-yr) 

versus capacity factor screening curves. The screening within each general class, as well 

as the final screening across the general classes uses a spreadsheet-based screening curve 

model developed by Duke Energy. This model is considered proprietary, confidential 

and competitive information by Duke Energy. 

This screening curve analysis model includes the total costs associated with owning and 

maintaining a technology type over its lifetime and computes a levelized $/kW-year value 

over a range of capacity factors. 

The Company repeats this process for each supply technology to be screened resulting in 

a family of lines (curves). The lower envelope along the curves represents the least 

costly supply options for various capacity factors or unit utilizations. Some technologies 

have screening curves limited to their expected operating range on the individual graphs. 

Lines that never become part of the lower envelope, or those that become part of the 

lower envelope only at capacity factors outside of their relevant operating ranges, have a 

very low probability of being part of the least cost solution, and generally can be 

eliminated from further analysis. 

2. Screening Results 

The results of the screening within each category are shown in Appendix C. 

In the quantitative analysis phase, the Company further evaluates those technologies from 

each of the three general categories screened (Base load, Peaking/Intermediate, and 

Renewables) which had the lowest levelized busbar cost for a given capacity factor range 

within each of these categories. 
67

While EPA’s MATS and GHG New Source regulations may effectively preclude new 

coal-fired generation, Duke Energy Carolinas has included supercritical pulverized coal 

(SCPC) and integrated gasification combined cycle (IGCC) technologies with carbon 

capture sequestration (CCS) of 1000 pounds/net MWH and 800 pounds/net MWH as 

options for base load analysis consistent with the proposed EPA NSPS rules. Additional 

detail on the expected impacts from EPA regulations to new coal-fired options is 

included in Chapter 6. 

With lower gas prices, larger capacities and increased efficiency, combined cycle units 

have become more cost-effective at higher capacity factors and have been included as a 

base load option. 

The Company selected the following technologies for the quantitative analysis: 

• Base load – 825 MW Supercritical Pulverized Coal with CCS 

• Base load – 618 MW IGCC with CCS 

• Base load – 2 x 1,117MW Nuclear units (AP1000) 

• Base load – 700 MW – 2x2x1 Combined Cycle (Inlet Chiller and Fired) 

• Peaking/Intermediate – 800 MW 4-7FA CTs 

• Peaking/Intermediate – 600 MW 3-7FA CTs 

• Peaking/Intermediate – 627 MW 8-7EA CTs 

• Renewable – 150 MW Wind - On-Shore 

• Renewable – 5 MW Landfill Gas 

• Renewable – 25 MW Solar PV 

3. Unit Size 

The unit sizes selected for planning purposes generally are the larger technologies 

available today because they generally offer lower $/kW installed capital costs due to 

economies of scale. However, the true test of whether a resource is economical depends 

on the economics of an overall resource plan that contains all costs associated with that 

resource (fuel costs, O&M costs, emission costs, etc.), not merely on the capital $/kW 

cost. In the case of very large unit sizes such as those utilized for the nuclear and/or 

IGCC technology types, if these are routinely selected as part of a least cost plan, joint 

ownership can and may be evaluated and pursued. 

4. Cost, Availability, and Performance Uncertainty 

Supply-side alternative project scope and estimated costs used for planning purposes for 

conventional technology types, such as simple-cycle CT units and CC units, are relatively 

well-known and are estimated in the TAG® and may be obtained from architect and 

engineering (A&E) firms and/or equipment vendors. The Company also uses its 

experience with the scope and costs for such resources to confirm the reasonableness of 
68

the estimates. The cost estimates include step-up transformers and a substation to 

connect with the transmission system. Since any additional transmission costs would be 

site-specific and specific sites are unknown at this time, typical values for additional 

transmission costs were also added to the alternatives. For natural gas units, gas pipeline 

costs were also included in the cost estimates. The unit availability and performance of 

conventional supply-side options are also relatively well-known and the TAG®, A&E 

firms and/or equipment vendors are sources of estimates of these parameters. 

5. Lead Time for Construction 

The estimated lead time for construction and permitting for modeling purposes for the 

proposed simple-cycle CT and combined cycle units is four to five years. For coal units, 

the lead time is assumed to be longer, approximately five to six years. For nuclear units, 

the lead time is assumed to be twelve to thirteen years or longer. However, the time 

required to obtain regulatory approvals and environmental permits adds uncertainty to the 

process, so Company judgment is incorporated into the analysis, as necessary. 

6. RD&D Efforts and Technology Advances 

New energy and technology alternatives will be necessary to ensure a long-term 

sustainable electric future. Duke Energy Carolinas’ research, development, and delivery 

(RD&D) activities enable Duke Energy Carolinas to track new options including small 

modular nuclear reactors, advanced CTs, advanced fossil technologies, distributed energy 

sources, and energy storage technologies. To assure a strategic advantage in electricity 

supply and delivery, the Company places emphasis on providing information, assessment 

tools, validated technology, demonstration/deployment support, and RD&D investment 

opportunities for planning and implementing projects utilizing new power generation 

technology. 

Within the planning horizon of this forecast, Duke Energy Carolinas expects that 

significant advances will continue to be made in CT technology. Advances in stationary 

industrial CT technology should result from ongoing research and development efforts to 

improve both commercial and military aircraft engine efficiency and power density, as 

well as expanding research efforts to burn more hydrogen-rich fuels derived from the 

IGCC process. The ability to burn hydrogen-rich fuels will enable very high levels of 

CO2 removal, thereby enabling a major portion of the advancement necessary for a 

significant reduction in the carbon footprint of this coal-based technology. 

Duke Energy Carolinas is evaluating more natural gas-fueled new generation because of 

the increase in available fuel sources, such as shale gas. Despite the lower greenhouse 

gas emission impact of natural gas-fired generation, carbon capture remains an issue 

when utilized in conjunction with natural gas resources. Most recent studies of carbon 

capture have been focused on coal-fired generation, as opposed to natural gas generation. 
69

Duke Energy Carolinas’ research and development groups have been evaluating various 

means of capturing carbon from natural gas fired generation through post-combustion 

capture and oxy-fuel combustion technologies. Through its partnerships with 

governmental agencies, non-governmental agencies, academia, and other companies, 

Duke Energy Carolinas is evaluating the technical and economic impacts of adding such 

systems to its existing and future generation. With the increased focus on natural gas 

generation, it is anticipated that a greater focus will be placed on natural gas carbon 

capture technology. 

7. Coordination with Other Utilities 

Decisions concerning coordinating the construction and operation of new units with other 

utilities or entities are dependent on a number of factors including the size of the unit 

versus each utility’s capacity requirement and whether the timing of the need for facilities 

is the same. To the extent that units larger than Duke Energy Carolinas’ needs become 

economically viable as part of a plan, co-ownership can be considered at that time. 

Coordination with other utilities can also be achieved through purchases and sales in the 

bulk power market. 

D. Wholesale and QF Purchased Power Agreements 

Duke Energy Carolinas is an active participant in the wholesale market for capacity and 

energy. The Company has issued RFPs for purchased power capacity in the past, and has 

entered into purchased power arrangements for over 2,000 MWs over the past 10 years. 

In addition, Duke Energy Carolinas has contracts with a growing number of Qualifying 

Facilities (QF or QFs). Table 5.F shows both the purchased power capacity obtained 

through RFPs, as well as the larger QF agreements. There are numerous contracts in 

various stages of negotiation and contracting, and the listing is constantly changing. 

Table 5.F is intended to represent only a snapshot of signed contracts as of August 1, 

2012. See Appendix I for additional information on purchases from QFs. 
70 

Table 5.F 

Wholesale Purchase & Purchased Power Commitments 

 

Planning Philosophy with Regard to Purchased Power 

Opportunities for the purchase of wholesale power from suppliers and marketers are an 

important resource option for meeting the electricity needs of Duke Energy Carolinas’ 

SUPPLIER CITY STATE

SUMMER 

FIRM 

CAPACITY 

(MW)

WINTER 

FIRM 

CAPACITY 

(MW)

CONTRACT 

START

CONTRACT 

EXPIRATION

Cargill Power Marketing

Various 

Counties ND / SD 6 6 1/1/2012 1 year

Catawba County Newton NC 3.7 3.7 8/23/1999 8/22/2014

Cherokee County Cogeneration 

Partners, L.P. Gaffney SC 88 88 7/1/1996 6/30/2013

Concord Energy, LLC Concord NC 9.2 9.2 2/5/2012 12/31/2031

Davidson Gas Producers, LLC Lexington NC 1.6 1.6 12/1/2010 12/31/2030

Gas Recovery Systems, LLC Concord NC 3 4 2/1/2010 12/31/2030

Gaston County Dallas NC 3.2 3.2 3/31/2011 12/31/2021

Greenville Gas Producers, LLC Greer SC 3.2 3.2 8/1/2008 Ongoing

Lockhart Power Company Wellford SC 1.6 1.6 4/1/2011 12/31/2020

MP Durham, LLC Durham NC 3.2 3.2 9/18/2009 12/31/2029

Northbrook Carolina Hydro, 

LLC Various NC & SC 5.9 5.9 12/4/2006 Ongoing

Salem Energy Systems, LLC

WinstonSalem NC 4.3 4.3 7/10/1996 Ongoing

SunEd DEC1, LLC Lexington NC 7.8 7.8 12/1/2009 12/31/2030

Town of Lake Lure Lake Lure NC 2.5 2.5 2/21/2006 2/20/2011

WMRE Energy, LLC Kernersville NC 2.4 2.4 3/31/2011 12/31/2026

Misc. Small PV* Various NC & SC 8.2 8.2 Various Various

Misc. Small Hydro/Other Various NC & SC 6.4 6.5 Various

Assumed 

Evergreen

Summary of Wholesale Purchased Power Commitments

(as of August 1, 2012)

SUMMER 2012

Non-Utility Generation

 Traditional 109 MW

 Renewable * 73MW

Duke Energy Carolinas allocation 

 of SEPA capacity 8 MW

Other-Wholesale 107.2 MW

Total Firm Purchases 297.2 MW
71

retail and wholesale customers. Duke Energy Carolinas has been active in the wholesale 

purchased power market and has entered into contracts totaling approximately 2500 

MWs since 2001 to meet customer needs. The use of supply side requests for proposal 

(RFPs) continues to be an essential component of Duke Energy Carolinas’ resource 

procurement strategy. In particular, the purchased power agreements that the Company 

has entered into have allowed customers to enjoy the benefits of discounted market 

capacity prices and have provided flexibility in meeting target planning reserve margin 

requirements. 

The Company’s approach to resource selection is as follows: 

The IRP process is used to identify the type, size, and timing of the resource need. In 

selecting the optimal resource plan, Duke Energy Carolinas begins with an optimization 

model that selects the resource mix that minimizes the present value of revenue 

requirements (PVRR) for a given set of assumptions. The levelized cost method used for 

generation options serves as a proxy for either self-build or long-term purchased power 

opportunities. From the optimization step, several diverse portfolios of resources are 

selected for further detailed production cost modeling and ultimate selection of a resource 

plan for the IRP. 

 

Once a resource need is identified, the Company determines the options to satisfy that 

need and determines the near-term and long-term actions necessary to secure the 

resource. The options could include a self-build Duke Energy Carolinas-owned resource, 

a Duke Energy Carolinas-owned acquired resource (new or existing), or a purchased 

power resource. The Company consistently has issued RFPs for peaking and 

intermediate resource needs. For example, following the identification of peaking and 

intermediate resource needs, the Company issued a RFP in May 2007 for conventional 

intermediate and peaking resource proposals of up to 800 MW beginning in the 2009-

2010 timeframe and up to 2000 additional MW beginning in the 2013 timeframe. 

Potential bidders could submit bids for purchased power or for the acquisition of existing 

or new facilities. Ten bidders submitted a total of forty-five bids spanning time periods 

of two to thirty years. The bid evaluation considered price, operational flexibility, and 

location benefits. Ultimately, the Company determined that none of the proposed bids 

provided sufficient advantages to offset the multiple benefits of the proposed Buck and 

Dan River CC projects. The consideration of purchased power options was described in 

the Company’s CPCN application for these facilities and addressed in testimony. The 

NCUC issued the CPCNs for the Buck and Dan River CC projects in June 2008. 

The Company also issued an RFP for renewable energy proposals in 2007. This RFP 

process produced proposals for approximately 1,900 megawatts of electricity from 
72

alternative sources from 26 different companies. The bids included wind, solar, biomass, 

biodiesel, landfill gas, hydro, and biogas projects. The Company entered into PPAs for a 

large solar project and several landfill gas facilities. In addition, the Company continues 

to receive unsolicited proposals for renewable purchased power resources and has entered 

into several PPAs as a result of unsolicited proposals. 

 

The 2012 IRP plan includes approximately 2,100 MWs of new CC capacity, 1,800 MWs 

of new CT capacity, in addition to existing and committed resources for the Cliffside 

Modernization project and Buck and Dan River combined cycle projects, as well as new 

nuclear generation. The new CC resources meet an identified need for intermediate/base 

load capacity, whereas the new CT resources meet an identified need for peaking 

capacity. However, new CCs as an intermediate/base load resource remains uncertain as 

the capacity factor of these units are highly dependent on the price of natural gas and 

carbon legislation assumptions. Even though CC is projected to operate in a base load 

capacity in the near-term, by 2016, the units are projected to operate in a more 

intermediate manner. These needs will be refined in future IRPs and could be met 

through new self-build capacity, purchased power, additional DSM or any combination 

of the three. 

Although Duke Energy Carolinas evaluates the competitive wholesale market for peaking 

and intermediate resources, the Company’s purchased power philosophy does not 

currently include soliciting purchased power bids for base load capacity. Duke Energy 

Carolinas views base load capacity as fundamentally different from peaking and 

intermediate capacity. Currently, there are two key concerns with relying upon the 

wholesale market for base load capacity. First, generation outside the control area could 

be subject to interruption due to transmission issues more so than generation within the 

control area. Second, supplier default could jeopardize the ability to provide reliable 

service. The Company therefore believes that Duke Energy Carolinas-owned base load 

resources are the most reliable means for Duke Energy Carolinas to meet its service 

obligations in a cost-effective and reliable manner. 

 

In addition, the Company examines unsolicited bids for purchased power or resource 

acquisitions and is alert to opportunities to purchase power or resources. 
73 

6. ENVIRONMENTAL COMPLIANCE 

Legislative and Regulatory Issues 

Duke Energy Carolinas, which is subject to the jurisdiction of federal agencies including 

the Federal Energy Regulatory Commission (FERC), EPA, and the NRC, as well as state 

commissions and agencies, is potentially impacted by state and federal legislative and 

regulatory actions. This section provides a high-level description of several issues Duke 

Energy Carolinas is actively monitoring or engaged in that could potentially influence the 

Company’s existing generation portfolio and choices for new generation resources. 

Air Quality

Duke Energy Carolinas is required to comply with numerous state and federal air 

emission regulations, including the current Clean Air Interstate Rule (CAIR) NOx and 

SO2 cap-and-trade program, and the 2002 North Carolina Clean Smokestacks Act (NC 

CSA). 

As a result of complying with the NC CSA, Duke Energy Carolinas will reduce SO2

emissions by approximately 75% by 2013 from 2000 levels. The law also required 

additional reductions in NOx emissions in 2007 and 2009, beyond those required by the 

CAIR rule, which Duke Energy Carolinas has achieved. This landmark legislation, 

which was passed by the North Carolina General Assembly in June of 2002, calls for 

some of the lowest state-mandated emission levels in the nation, and was passed with 

Duke Energy Carolinas’ input and support.

The following Charts 6.A and 6.B show Duke Energy Carolinas’ NOx and SO2 emissions 

reductions to comply with the 2002 NC CSA requirements and actual emissions through 

2011. 
74 

Chart 6.A 

Chart 6.B 
75

In addition to current programs and regulatory requirements, several new regulations are 

in various stages of implementation and development that will impact operations for 

Duke Energy Carolinas in the coming years. Some of the major rules include: 

Cross-State Air Pollution Rule and the Clean Air Interstate Rule (CAIR) 

The EPA finalized its CAIR in May 2005. The CAIR limits total annual and summertime 

NOx emissions and annual SO2 emissions from electric generating facilities across the 

Eastern U.S. through a two-phased cap-and-trade program. Phase 1 began in 2009 for 

NOx and in 2010 for SO2. Phase 2 of CAIR would begin in 2015. In July 2008, the U.S. 

Court of Appeals for the District of Columbia (D.C. Circuit) issued its decision in North 

Carolina v. EPA vacating the CAIR. In December 2008, the D.C. Circuit issued a 

decision remanding the CAIR to the EPA, allowing CAIR to remain in effect until EPA 

develops new regulations. 

In August 2010, EPA published a proposed replacement rule for CAIR, known as the 

Transport Rule (TR). The rule was finalized as the Cross-State Air Pollution Rule 

(CSAPR) on July 6, 2011. The CSAPR, which establishes state-level annual SO2 and 

NOX budgets and ozone-season NOX budgets was to take effect on January 1, 2012; 

however on December 30, 2011 the rule was stayed by the U.S. Court of Appeals for the 

DC Circuit. Oral arguments on the rule occurred in April 2012 and on August 21, 2012, 

the court ruled to vacate the CSAPR. In the opinion, the court holds that the CSAPR 

exceeds EPA’s statutory authority and directs EPA to continue administering the CAIR 

pending completion of a remand rulemaking to replace CSAPR with a valid rule. At this 

time, there is no schedule for when a new replacement rule may occur, however, if the 

court decision were reversed on appeal, the earliest CSAPR could likely be implemented 

in 2015. 

Duke Energy Carolinas will continue to implement and comply with CAIR. No 

significant impacts are expected for Duke Energy Carolinas’ continued compliance with 

CAIR. 

Mercury and Air Toxics Standard (MATS) 

In May 2005, the EPA issued the Clean Air Mercury Rule (CAMR). The rule established 

mercury emission-rate limits for new coal-fired steam generating units, as defined in 

Clean Air Act (CAA) section 111(d). It also established a nationwide mercury cap-andtrade program covering existing and new coal-fired power units. 

In February 2008, the D.C. Circuit Court of Appeals issued its opinion, vacating the 

CAMR. EPA announced a proposed Utility Boiler Maximum Achievable Control 
76

Technology (MACT) rule in March 2011 to replace the CAMR. The EPA published 

the final rule, known as the Mercury and Air Toxics Standard (MATS), in the Federal 

Register on February 16, 2012. MATS regulates Hazardous Air Pollutants (HAP) and 

establishes unit-level emission limits for mercury, acid gases, and non-mercury metals as 

well as organics standards for coal and oil-fired electric generating units. Compliance 

with the emission limits will be required within three years of the effective date of the 

rule (April 16, 2012). The rule gives permitting authorities the discretion to grant up to a 

1-year compliance extension, on a case-by-case basis, for sources that are unable to 

install emission controls before the compliance deadline. The one-year extension to meet 

compliance is not to be granted for units set to retire, unless replacement generation is 

located at the site. 

Based on the emission limits established by the MATS rule, the Company expects its 

compliance with the MATS rule to drive the retirement of several non-scrubbed facilities 

in the Carolinas, as well as various changes to units that have been modified over the last 

several years, to meet the emission requirements of the NC CSA. 

In addition to the limits imposed by the MATS rule on Duke Energy Carolinas’ existing 

power plants, the rule also establishes emissions standards for any new pulverized coal or 

IGCC power plant that may start construction in the future. The emission limits 

established for any new pulverized coal plant are significantly more stringent than those 

imposed on the existing power plant fleet. Thus, future construction of pulverized coal 

units would not currently be considered technologically feasible relative to MATS 

compliance. On July 20, 2012, EPA did announce plans to reconsider certain new source 

issues with the MATS rule. This reconsideration rulemaking is expected to be completed 

by March of 2013. 

National Ambient Air Quality Standards (NAAQS) 

8 Hour Ozone Standard

In March 2008 EPA revised the 8-hour ozone standard by lowering it from 84 to 75 parts 

per billion (ppb). In September 2009, EPA announced a decision to reconsider the 75 

ppb standard. The decision was in response to a court challenge from environmental 

groups and EPA’s belief that a lower standard was justified. However, after much 

debate, EPA announced in September 2011 that it would retain the 75 ppb primary 

standard until it is reconsidered under the next 5-year review, which is expected to be 

proposed in October 2013 and finalized in July 2014 (possibly in the 60 to 70 ppb range). 

The earliest attainment date for a standard revised in 2014 would likely be 2019, and 

would depend on a nonattainment area’s classification. 
77

On April 30, 2012 EPA finalized the area designations for the 2008 75 ppb 8-hour ozone 

standard. The Charlotte area is now classified as a “marginal” nonattainment area, which 

establishes December 31, 2015 as its attainment date. For marginal nonattainment areas, 

states are not required to prepare an attainment demonstration. EPA in its final rule states 

that it performed an analysis that indicates that the majority of areas classified as 

marginal will be able to attain the 75 ppb standard in 2015 due to federal and state 

emission reduction programs already in place. If the Charlotte area’s 2013-2015 air 

quality does not qualify it to be reclassified as attainment, the area can still qualify for the 

first of two possible one-year extensions of the attainment date if it has no more than one 

exceedance of the standard in 2015. Alternatively, should the Charlotte area not attain 

the standard by its attainment date and thus not qualify for an extension, it will be 

bumped up to the next higher classification. For Charlotte, this would be moderate, 

which would then establish a 6-year attainment schedule and require NC to develop an 

attainment SIP. 

SO2 Standards 

In November 2009, EPA proposed a rule to replace the 24-hour and annual primary SO2

NAAQS with a 1-hour SO2 standard. EPA finalized its new 1-hr standard of 75 ppb in 

June 2010. The SO2 NAAQS designation process is different from all previous NAAQS 

in that EPA will not designate an area as attainment based solely on monitored air quality 

data. To support a recommended designation of attainment the state must also have 

dispersion modeling of major SO2 sources at their potential-to-emit rate that shows no 

violation of the standard. In the absence of such modeling, areas with monitored clean 

air and areas without a monitor will be designated unclassifiable. EPA plans to 

designate an area as nonattainment if it has monitoring data or modeling results showing 

a violation of the standard. 

 

However, in a letter dated April 12, 2012, EPA announced that it would not require 

modeling as part of the states’ June 2013 SIP submissions for unclassifiable areas. EPA 

further said that it would convene stakeholder outreach on modeling and that afterwards 

it expects to outline further SIP requirements in a future rulemaking process. Oral 

arguments were heard on May 3, 2012 in the DC Circuit Court. The court focused on 

whether EPA’s modeling-based implementation approach is final agency action subject 

to challenge, especially in light of EPA’s April 12 letters. On July 20, 2012, the Court 

upheld the EPA’s 1-hour SO2 NAAQS and at the same time ruled that EPA statements in 

the preamble of the final rule regarding the use of modeling are not final agency action 

and are therefore not reviewable by the court. The court indicated that petitioners can 

challenge the use of modeling if or when EPA takes final action that imposes an 
78

obligation that petitioners must meet. 

It remains unclear whether EPA will require states to perform source-specific modeling 

of major SO2 emission sources (greater than 100 TPY) in unclassifiable areas to either 

demonstrate that a source is not causing or contributing to an exceedance of the standard 

or if it does, to determine the amount of emission reduction necessary to eliminate the 

modeled exceedance. Should modeling not be required for unclassifiable areas, the risk 

for additional SO2 reductions or permit changes at Carolinas stations would likely be 

reduced. EPA is delaying final designations for most areas until June 2013. As such, the 

Company estimates any required controls could need to be in place sometime in 2017. A 

major SO2 source located in a designated nonattainment area would most likely be 

modeled by the state and therefore could be at a high risk of being required to lower 

emissions if the modeling shows an exceedance of the 1-hour standard. 

 

In addition, EPA is proposing to require states to relocate some existing monitors and to 

add new monitors. While these monitors will not be used by EPA to make the initial 

nonattainment designations, they will play a role in identifying possible future 

nonattainment areas. 

Particulate Matter (PM) Standard

In September 2006, the EPA announced its decision to revise the PM2.5 NAAQS standard. 

The daily standard was reduced from 65 ug/m3

 (micrograms per cubic meter) to 35 

ug/m3

. The annual standard remained at 15 ug/m3. 

 

EPA finalized designations for the 2006 daily standard in October 2009, which did not 

include any nonattainment areas in the Duke Energy Carolinas service territory. In 

February 2009, the D.C Circuit unanimously remanded to EPA the Agency’s decision to 

retain the annual 15 ug/m3 primary PM2.5 NAAQS and to equate the secondary PM2.5

NAAQS with the primary NAAQS. EPA began undertaking new rulemaking to revise 

the standards consistent with the Court’s decision. The current annual and daily PM2.5 

standards alone are not driving any emission reductions at Duke Energy Carolinas 

facilities. The reduction in SO2 and NOx emissions to address the current annual standard 

are being addressed through CAIR. Reductions to address the current daily standard will 

be addressed as part of the CSAPR, when implemented (the CSAPR will continue to 

address reductions needed for the current annual standard). 

On June 14, 2012, the EPA proposed to lower the current 15 ug/m3

 PM2.5 annual standard 

to a level within the range of 12 ug/m3

 to 13 ug/m3. The EPA plans to finalize a new 

annual standard by December 2012, and finalize area designations by December 2014. 

States with nonattainment areas will be required to submit SIPs to EPA in early 2018, 
79

with the initial attainment date in 2020. The EPA has indicated that it will likely use 

2011 – 2013 air quality data to make final designations, which could show improved air 

quality compared to current data. It is unclear if the lower standard will trigger the EPA 

to develop a new transport rule. If EPA were to do so, such a rule could result in a 

requirement for reduced SO2 and/or NOx emissions at Carolinas generating units. The 

potential timing of such a rulemaking is uncertain.

Greenhouse Gas Regulation 

The EPA has been active in the regulation of greenhouse gases (GHGs). In May 2010, 

the EPA finalized what is commonly referred to as the Tailoring Rule, which sets the 

emission thresholds to 75,000 tons/year of CO2 for determining when a source is 

potentially subject to Prevention of Significant Deterioration (PSD) permitting for GHGs. 

The Tailoring Rule went into effect beginning January 2, 2011. Being subject to PSD 

permitting requirements for CO2 will require a Best Available Control Technology 

(BACT) analysis and the application of BACT for GHGs. BACT will be determined by 

the state permitting authority. Since it is not known if, or when, a Duke Energy Carolinas 

generating unit might undertake a modification that triggers PSD permitting requirements 

for GHGs and exactly what might constitute BACT at a particular point in time, the 

potential implications of this regulatory requirement are presently unknown. In addition, 

EPA announced in July 2011 that it was undertaking a three year study of CO2 emissions 

from stationary bio-energy sources. This study is expected to yield a determination 

regarding the use of biomass as a carbon neutral source of generation and its potential use 

as BACT. 

 

On April 13, 2012, the EPA proposed new rules to establish GHG new source 

performance standards (NSPS) for new electric utility steam generating units (EGUs). 

The proposed GHG NSPS applies only to new pulverized coal, IGCC and natural gas 

combined cycle units. The proposed NSPS is an output-based emission standard of 1,000 

lb CO2/gross MWh of electricity generation. At the present, carbon capture and storage 

(CCS) is the only technology capable of attaining this standard on pulverized coal or 

IGCC units. However, new pulverized coal and IGCC with CCS are currently not 

economically competitive technologies as new generation options. In addition, the 

geology in the Carolinas is not conducive to the sequestration of CO2. With respect to 

new natural gas combined cycle facilities, the proposed standard will not require the 

installation of CCS technology. 

The proposal excludes new simple cycle turbines from the regulation. EPA is not 

proposing an emission standard for NSPS modified or reconstructed units. EPA states in 

the proposal that its current definition of an NSPS modification specifically exempts 
80

pollution control projects on an existing unit (for example, projects to comply with 

MATS or CSAPR). EPA has not given any indication when it might propose a GHG 

NSPS rule for existing sources. 

 

It is currently not known if or when any federal climate change legislation limiting GHG 

emissions might be enacted. 

Water Quality and By-product Issues 

CWA 316(b) Cooling Water Intake Structures 

Federal regulations in Section 316(b) of the Clean Water Act may necessitate cooling 

water intake modifications and/or cooling towers for existing facilities to minimize 

impingement and entrainment of aquatic organisms. All Duke Energy Carolina’s coal 

and nuclear generating stations are potentially affected sources under that rule. 

 

EPA issued a proposed rule on April 20, 2011 and is expected to finalize the rule by June 

2013. Depending upon a station’s National Pollutant Discharge Elimination System 

(NPDES) permit renewal schedule, compliance with the rule could begin as early as 

2016. 

EPA’s proposed rule lists four options with a preference for one option. The preferred 

option impacts all facilities with a design intake flow greater than 2 million gallons per 

day (mgd) from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters 

that utilize at least 25% of the water withdrawn for cooling purposes. In order to meet 

fish impingement standards, intake screen modifications are likely to be needed for 

nearly all plant intakes. EPA has not mandated the use of cooling towers as “Best 

Technology Available” to address entrainment requirements. However, site specific 

studies are proposed by the rule in order to address best technology options for 

complying with the entrainment requirements. These studies could begin as early as late 

2013. 

 

Steam Electric Effluent Guidelines 

In September 2009, EPA announced plans to revise the steam electric effluent guidelines. 

The regulation is to be technology-based, in that limits are based on the capability of 

technology. The primary focus of the revised regulation is on coal-fired generation, thus 

the major areas likely to be impacted are FGD wastewater treatment systems and ash 

handling systems. The EPA may set limits that dictate certain FGD wastewater treatment 

technologies for the industry and may require dry ash handling systems be installed. 
81

According to a joint stipulation filed by EPA and environmental groups on April 3, 2012, 

EPA now plans to issue a draft rule by November 20, 2012 and a final rule by April 28, 

2014. After the final rulemaking, effluent guideline requirements will be included in a 

station’s NPDES permit renewals. Thus, requirements to comply with NPDES permit 

conditions may begin as early as 2017 for some facilities. The length of time allowed to 

comply will be determined through the permit renewal process. Steam electric effluent 

guidelines may also revise thermal discharge requirements. 

Coal Combustion Residuals 

 

Following Tennessee Valley Authority’s Kingston ash dike failure in December 2008, 

EPA began an effort to assess the integrity of ash dikes nationwide and to develop a rule 

to manage coal combustion residuals (CCRs). CCRs include fly ash, bottom ash and 

FGD byproducts (gypsum). Since the 2008 dike failure, numerous ash dike inspections 

have been completed by EPA and an enormous amount of input has been received by 

EPA, as it developed proposed regulations. 

In June 2010, EPA issued its proposed rule regarding CCRs. The proposed rule offers 

two options: (1) a hazardous waste classification under Resource Conservation and 

Recovery Act (RCRA) Subtitle C; and (2) a non-hazardous waste classification under 

RCRA Subtitle D, along with dam safety and alternative rules. Both options would 

require strict new requirements regarding the handling, disposal and potential re-use 

ability of CCRs. The proposal could result in more conversions to dry handling of ash, 

more landfills, closure of existing ash ponds and the addition of new wastewater 

treatment systems. Final regulations are not expected until sometime in 2013 or later. 

EPA’s regulatory classification of CCRs as hazardous or non-hazardous will be critical in 

developing plans for handling CCRs in the future. The impact to Duke Energy Carolinas 

of this regulation as proposed is likely to be significant. The schedule for compliance 

will depend upon when EPA finalizes a rule, but is currently anticipated in the 2018 – 

2021 timeframe. 
82 

7. TRANSMISSION AND DISTRIBUTION 

A. Transmission System Adequacy 

 

Duke Energy Carolinas monitors the adequacy and reliability of its transmission system 

and interconnections through internal analysis and participation in regional reliability 

groups. Internal transmission planning looks 10 years ahead at available generating 

resources and projected load to identify transmission system upgrade and expansion 

requirements. Corrective actions are planned and implemented in advance to ensure 

continued cost-effective and high-quality service. The Duke Energy Carolinas’ 

transmission model is incorporated into models used by regional reliability groups in 

developing plans to maintain interconnected transmission system reliability. Duke 

Energy Carolinas works with PEC, NCEMC and ElectriCities to develop an annual NC 

Transmission Planning Collaborative (NCTPC) plan for the Duke Energy Carolinas and 

PEC systems in both North and South Carolina. In addition, transmission planning is 

coordinated with neighboring systems including South Carolina Electric & Gas (SCE&G) 

and Santee Cooper under a number of mechanisms including legacy interchange 

agreements between SCE&G, Santee Cooper, PEC, and Duke Energy Carolinas. 

The Company monitors transmission system reliability by evaluating changes in load, 

generating capacity, transactions and topography. A detailed annual screening ensures 

compliance with Duke Energy Carolinas’ Transmission Planning Guidelines for voltage 

and thermal loading. The annual screening uses methods that comply with SERC policy 

and NERC Reliability Standards and the screening results identify the need for future 

transmission system expansion and upgrades and are used as inputs into the Duke Energy 

Carolinas – Power Delivery optimization process. The Power Delivery optimization 

process evaluates problem-solution alternatives and their respective priority, scope, cost, 

and timing. The optimization process enables Power Delivery to produce a multi-year 

work plan and budget to fund a portfolio of projects which provides the greatest benefit 

for the dollars invested. 

Duke Energy Carolinas currently evaluates all transmission reservation requests for 

impact on transfer capability, as well as compliance with the Company’s Transmission 

Planning Guidelines and the FERC Open Access Transmission Tariff (OATT). The 

Company performs studies to ensure transfer capability is acceptable to meet reliability 

needs and customers’ expected use of the transmission system. The Power Delivery 

optimization process is also used to manage projects for improvement of transfer 

capability. 

SERC audits Duke Energy Carolinas every three years for compliance with NERC 

Reliability Standards. Specifically, the audit requires Duke Energy Carolinas to 
83

demonstrate that its transmission planning practices meet NERC standards and to provide 

data supporting the Company’s annual compliance filing certifications. SERC conducted 

a NERC Reliability Standards compliance audit of Duke Energy Carolinas in May 2011. 

The scope of this audit included Transmission Planning Standards TPL-002-0.a and TPL003-0a. For both Standards, Duke Energy Carolinas received “No Findings” from the 

audit team. 

Duke Energy Carolinas participates in a number of regional reliability groups to 

coordinate analysis of regional, sub-regional and inter-control area transfer capability and 

interconnection reliability. The reliability groups’ purpose is to: 

• Assess the interconnected system’s capability to handle large firm and non-firm 

transactions for purposes of economic access to resources and system reliability; 

• Ensure that planned future transmission system improvements do not adversely 

affect neighboring systems; and 

• Ensure the interconnected system’s compliance with NERC Reliability Standards. 

Regional reliability groups evaluate transfer capability and compliance with NERC 

Reliability Standards for the upcoming peak season and five- and ten-year periods. The 

groups also perform computer simulation tests for high transfer levels to verify 

satisfactory transfer capability. 

B. Transmission System Emerging Issues 

Looking forward, several items that have the potential to impact the planning of the Duke 

Energy Carolinas Transmission System include: 

• Industry-approved revisions to the NERC Reliability Standards for 

transmission planning standards that are awaiting FERC approval. 

• FERC Order 1000 on Transmission Planning and Cost Allocation by 

Transmission Owning and Operating Public Utilities, issued in July 2011 

under Docket No. RM10-23-000. Compliance filings under FERC Order 

1000 are due on October 11, 2012 and April 11, 2013. 

• Increased interest in the integration of variable renewable resources (e.g., 

wind) into the grid. The NCTPC and the DOE-funded Carolinas Offshore 

Wind Integration Case Study DOE-funded Southeastern Offshore Wind 

Energy Infrastructure Project are performing studies in 2012 to assess the 

transmission impacts of significant off-shore wind development along the 

Southeast coast including North Carolina. 
84

• The Eastern Interconnection Planning Collaborative (EIPC), which is a 

transmission study process that began in late 2009. The EIPC provides: 

1. A mechanism to aggregate existing regional transmission plans in the 

Eastern Interconnection and assess them on an Eastern Interconnection 

wide basis; and 

2. A framework to be able to perform technical analyses to inform state and 

federal government representatives and policy makers on important issues, 

such as future renewable resources and their impact on transmission 

infrastructure. 

As of late July 2012, the EIPC is performing analysis to determine the specific 

transmission infrastructure needed to support three future resource scenarios 

as determined by the Stakeholder Steering Committee in late 2011. This 

analysis and a final report are scheduled to be completed by the end of 2012. 
85 

8. SELECTION AND IMPLEMENTATION OF THE PLAN 

A. Resource Needs Assessment (Future State) 

To meet the future needs of Duke Energy Carolinas’ customers, it is necessary for the 

Company to adequately understand the load and resource balance. For each year of the 

planning horizon, Duke Energy Carolinas develops a load forecast of energy sales and 

peak demand. To determine total resources needed, the Company considers the load 

obligation plus a 15.5% target planning reserve margin (see Reserve Margin discussion 

below). The capability of existing resources, including generating units, energy efficiency 

and demand-side management programs, and purchased power contracts, is measured 

against the total resource need. Any deficit in future years will be met by a mix of 

additional resources that reliably and cost-effectively meet the load obligation. 

Reserve Margin Explanation and Justification 

Background 

As part of the NCUC's approval of the 2010 IRP, Duke Energy Carolinas and Progress 

Energy Carolinas were ordered to perform a quantitative analysis of the utilities’ 

respective reserve margins and to provide the study results in the companies' 2012 IRPs. 

Since the early 2000s, Duke Energy Carolinas’ target reserve margin has been 17% with 

a minimum reserve margin of 15.5%. In place of a quantitative study over the past five 

years, the 17% reserve margin has been justified based on the Company’s review of its 

actual reserves and operating experience. For example twice in the past 5 years, actual 

operating reserves have dropped to approximately 2% during times of peak demand 

supporting the 17% reserve margin. The NCUC approved the 17% planning reserve 

margin as reasonable for planning in each of the Company’s IRPs from 2005 to 2011. 

Duke Energy Carolinas hired Astrape, a consultant that specializes in reserve margin 

analysis, to perform the quantitative analysis. Astrape's analysis was detailed, 

incorporating uncertainty of weather, economic load growth, unit availability, hydro 

availability and transmission availability for emergency tie assistance. 

 Evaluation

Astrape evaluated a range of reserve margins based on a physical reliability metric and on 

an economic metric. A planning year of 2016 was used as the reference year because it 

incorporated the new generation units (Buck & Dan River CC, Cliffside 6) and the 

planned retirements. 
86

The physical reliability metric targets a reserve margin that meets a one day in 10 year 

standard which is interpreted as one firm load shed event every 10 years. This is the most 

common metric used in the utility industry and is commonly referred to as Loss of Load 

Expectation (LOLE). A firm load shed event occurs when load plus operating reserves 

is greater than available capacity and all options including market purchases and demand 

response have been exhausted. This results in unserved energy for a firm customer. 

Based on the results of this analysis, a 14.5% reserve margin meets the one in every 10 

year LOLE metric for Duke Energy Carolinas. 

From an economic perspective, as planning reserve margin increases, the total cost of 

reserves increases while the costs related to reliability events decline. On the other hand, 

as planning reserve margin decreases, the cost of reserves decreases while the costs 

related to reliability events increases, including the costs to customers due to a loss of 

power. Thus, there is an economic optimum point where the cost of additional reserves 

plus the cost of reliability events on customers is minimized. The Astrape study shows 

that the optimal reserve margin that minimizes the cost to customers on a long term basis 

is 14%. 

However, when a range of potential outcomes is examined, the study shows that at a 90% 

confidence interval, an economic benefit would be received by adding efficient natural 

gas combustion turbines up to a reserve margin of 15.5%. In addition, Astrape performed 

analyses using various sensitivities. The results demonstrate that a target reserve margin 

in the 14-16% range performs well in most sensitivity cases. 

Based on the result of the analyses, the Company developed the 2012 IRP assuming a 

minimum planning reserve margin of 14.5% with a target of 15.5%. The 14.5% 

minimum planning reserve margin is 1% lower than the 2011 IRP minimum reserve 

margin of 15.5%, which is equivalent to an approximate 200 MW reduction in generation 

need in the 2016 timeframe. One factor that supports a lower reserve margin is the 

Company’s retirement of the less reliable old fleet CTs and older coal units and 

replacement of such units with the new Buck and Dan River CCs and the new Cliffside 

Unit 6 coal unit. Carrying a lower reserve margin does come with the risk that additional 

purchase will be required from neighboring utilities during periods when there are low 

reserves. Duke Energy Carolinas expects such purchases to be infrequent and lower cost 

to customers than carrying a higher reserve margin. 
87

Load and Resource Balance 

In 2013, the load obligation plus the target planning reserve margin is 20,911 MW. 

Existing resources, consisting of existing generation and purchased power to meet load 

requirements, total 22,331 MW. The difference between available resources and the 

projected load obligation indicates there are sufficient resources to meet Duke Energy 

Carolinas’ 2013 peak system requirements. However, the need for additional capacity 

grows over time due to load growth, unit capacity adjustments, unit retirements, and 

expirations of purchased-power contracts. In fact, the Company’s forecasts predict new 

resource requirements of 2,770 MW by 2022 and 6,360 MW by 2032. The following 

chart shows the existing resources and resource requirements needed to meet the 

Company’s load obligation, plus the 15.5% target planning reserve margin. Assumptions 

made in the development of this chart include: 

1. Cliffside Unit 6 is online in the fall of 2012; included in Resource 

Commitments; 

2. Coal retirements associated with the Cliffside Unit 6 CPCN and Air Permit, 

Buck Units 5&6, and Lee Steam Station are included;

3. Retirement of the old fleet combustion turbines in the fall of 2012 are 

included; 

4. Conservation programs including those associated with the save-a-watt 

program are included; 

5. DSM programs including those associated with the save-a-watt program are 

included; 

6. Buck combined cycle facility was online in the fall of 2011 and Dan River 

combined cycle is online in the fall of 2012; both are included in Resource 

Commitments; 

7. Renewable capacity is built or purchased to meet the NC REPS is included. 

 
88

Chart 8.A 

Load and Resource Balance 

Cumulative Resource Additions to Meet a 15.5% Planning Reserve Margin (MWs) 

 

-

5,000 

10,000 

15,000 

20,000 

25,000 

30,000 

35,000 

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

Resource Requirements

Existing Resources Resource Commitments SAW Conservation Programs

Additional Resources Needed to Meet

Load Plus 15.5% Reserves

Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Resource Need 0 0 280 680 1070 1450 1860 2130 2500 2770

Year 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

Resource Need 3100 3430 3740 4040 4440 4820 5180 5560 5960 6360
89

B. Overall Planning Process Conclusions 

Duke Energy Carolinas’ resource planning process provides a framework for the 

Company to access, analyze and implement a cost-effective approach to reliably meet 

customers’ growing energy needs. In addition to assessing qualitative factors, the 

Company has also conducted a quantitative assessment using simulation models. 

Duke Energy Carolinas tested a variety of sensitivities and scenarios against a base set of 

inputs for various resource mixes, allowing the Company to better understand how 

potentially different future operating environments due to fuel commodity price changes, 

environmental emission mandates, and structural regulatory requirements can affect 

resource choices, and, ultimately, the cost of electricity to customers. (Appendix A 

provides a detailed description and results of the quantitative analyses). 

The results of the Company’s quantitative analyses suggest that a combination of 

additional base load, intermediate and peaking generation, renewable resources, EE, and 

DSM programs is required over the next twenty years to meet customer demand reliably 

and cost-effectively. 

The new pulverized coal unit at Cliffside Steam Station (Unit 6), scheduled to be in 

service in September 2012, is projected to provide 5,700 GWh of base load energy 

annually. The new CC facility at Dan River is also expected to be operational in late 

2012. In addition, Duke Energy Carolinas has included DSM, EE and renewable 

resources consistent with the Company’s energy efficiency plan approved in North and 

South Carolina and to meet the NC REPS. For planning purposes, a renewable energy 

standard similar to NC REPS was assumed for South Carolina beginning in 2016, in 

addition to the energy efficiency programs that will be phased in from 2015 to 2031. 

Nuclear uprates of approximately 100 MW are included in the 2012 IRP. Specific 

projects are being developed to be implemented in the 2013-2015 timeframe. For 

planning purposes, Lee Steam Station will be retired from coal-fired generation in late 

2014 and Unit 3 will be converted to natural gas generation in 2015. 

The Company’s analysis of new nuclear capacity contained in the 2012 IRP focuses on 

the impact of various uncertainties such as load variations, nuclear capital costs, 

greenhouse gas and clean energy legislation, EPA regulations, fuel prices, and the 

availability of financing options such as federal loan guarantees (FLG). 

The IRP analysis included sensitivities on each of the uncertainties described below: 

Load Variations: The base case load forecast incorporates the impact of the current 

recession, projected EE achievements, new wholesale sales opportunities, and the impact 
90

associated with future plug-in hybrid vehicles. The Company also developed high and 

low load forecast sensitivities to reflect a 95% confidence interval. 

Nuclear Capital Costs: The Company varied the nuclear capital cost on the low end to 

reflect the impact of minimal project contingency and low escalation rates and varied on 

the high side to reflect increased labor and material cost. 

Nuclear Financing Options: The nuclear cost in the 2012 IRP includes state 

incentives, local incentives and federal loan guarantees. 

Greenhouse Gas Legislation: The 2012 fundamental CO2 allowance price forecast was 

delayed primarily due to uncertainty of Congress passing carbon legislation. For the 

2012 IRP, the Company evaluated a range of CO2 prices based on various legislative cap 

and trade proposals used in 2009 and 2010 IRPs, in addition to potential Clean Energy 

legislation that does not have a CO2 cap and trade mechanism, but relies upon a federal

RPS. 

Fuel Prices: The base case natural gas and coal price projections were based on Duke 

Energy’s fundamental price forecasts, which are updated annually. The Company also 

evaluated a high cost fuel scenario, which reflects the impact of increased demand on 

natural gas, regulatory challenges to the coal mining industry, and the potential impacts 

of changes to international exports of natural gas and domestic coal. The lower cost fuel 

scenario represents a larger supply of domestic natural gas than currently assumed and a 

lower demand on coal. 

Results 

The results of the Company’s quantitative and qualitative analyses suggest that a 

combination of additional base load, intermediate, and peaking generation, renewable 

resources, and EE and DSM programs are required over the next 20 years. The near-term 

resource needs can be met, in part, with new EE and DSM programs, completing 

construction of the Dan River and Cliffside Projects, pursuing nuclear uprates and 

procuring renewable energy resources, as appropriate. However, additional resources 

will be needed as early as 2016 to meet forecasted system demand and energy 

requirements. As natural gas market price projections have decreased from 2011, 

construction and operation of efficient combined cycle capacity proves to be the most 

economical approach to meeting system needs in the next 5-7 years. However, even with 

a significant price decline in the natural gas market, the Company’s analysis continues to 

affirm the potential benefits of new nuclear capacity in the 2022 timeframe in a carbonconstrained future. 
91

To demonstrate that the Company is planning adequately for customers, the Company 

selected a portfolio incorporating the impact of future carbon legislation for the purposes 

of preparing the Load, Capacity, and Reserve Margin Table (LCR Table). 

This portfolio consisted of 1,800 MW4

 of new natural gas simple cycle capacity, 2,100 

MW of CC capacity, 2,234 MW of new nuclear capacity, 1,207 MW of DSM, 1,320 MW 

of EE, and 758 MW of renewable resources available on-peak. The selected portfolio 

specifically includes the Cliffside Unit 6, Dan River CC, and Lee Unit 3 natural gas 

conversion projects. 

However, the Company will likely face significant challenges relating to its resource 

planning in the future, such as specific challenges in (1) obtaining the necessary 

regulatory approvals to implement future demand-side, EE, and supply-side resources, 

(2) finding sufficient cost-effective, reliable renewable resources to meet the standard, 

particularly the swine and poultry set-asides, (3) effectively integrating renewables into 

the resource mix, particularly with the expected increase in solar QFs, (4) ensuring 

sufficient transmission capability for these resources, and (5) encouraging customers to 

adopt EE and DSM measures at the levels assumed in the resource plan. In light of the 

myriad of qualitative issues facing the Company relating to its fuel diversity, the 

Company’s environmental profile, the stage of technology deployment and regional 

economic development, Duke Energy Carolinas has developed a strategy to ensure that 

the Company can meet customers’ energy needs reliably and economically while 

maintaining flexibility pertaining to long-term resource decisions. 

Challenges and Considerations for New and Existing Nuclear Generation 

In March of 2012, the NRC issued a request for information letter to operating power 

reactor licensees regarding recommendations of the Near-Term Task Force review of 

insights from the Fukushima Dai-ichi accident. In April 2012, the NRC staff 

subsequently requested Duke Energy to update the W.S. Lee III (Lee) plant site-specific 

seismic analysis to incorporate the new Central and Eastern United States (CEUS) 

Seismic Source Characterization model (published as NUREG-2115 in January 2012). 

Work on a new Lee site-specific analysis implementing the new CEUS seismic model is 

underway. However, completion of the new seismic analysis is not expected before 

December 2012. This negatively impacts the schedule for NRC issuance of the Lee 

Combined Operating License (COL). The prior NRC schedule for Lee COL issuance in 

March-April 2013 supported a Commercial Operation Date (COD) of 2021. Completion 

of the new site-specific seismic analysis will delay Lee COL issuance beyond the second 

Quarter 2013, which does not support a 2021 COD. Accordingly, Duke Energy 

4

 The ultimate sizes of any generating unit may change somewhat depending on the vendor selected. 
92

Carolinas has moved the COD for Lee Nuclear Unit 1 to 2022. 

The NRC issued an updated Waste Confidence Rule in 2010 affirming that the agency 

has reasonable assurance utility spent fuel can be safely stored for at least 60 years after a 

power reactor's operating license expires. Waste confidence is central to the agency's 

ability to license new reactors and renew the operating licenses of existing reactors. On 

June 8, 2012, the US Court of Appeals of the District of Columbia Circuit issued a 

decision vacating the updated Waste Confidence Rule and remanding it to the NRC for 

further proceedings. The Court held that the NRC’s analysis was insufficient to support 

its findings that the permanent storage will be available “when necessary,” and that spent 

fuel can safely be stored onsite at nuclear plants for sixty years after the expiration of a 

plant’s license. In response to the remand decision, numerous parties filed a petition 

to suspend final decisions in all pending reactor licensing proceedings pending 

completion of remanded waste confidence proceedings in new nuclear and license 

renewal proceedings pending before the NRC. On August 7, 2012, the NRC issued an 

order on the petition stating that: (1) it is considering all options for resolving the waste 

confidence issues, which could include generic or site specific actions, but has not yet 

determined a course of action. (2) it will not issue licenses dependent on the waste 

confidence rule until the Court’s remand is appropriately addressed, however, this 

determination extends only to final license issuance; and (3) all licensing reviews and 

proceedings should continue to move forward. This is an emerging issue that could 

affect the issuance of the Lee COL. 

The Oconee Nuclear Station’s (Oconee) current operating license expires in 2033, which 

is close to the end of our current IRP planning horizon. At this time, the Company has 

not made a decision concerning a second license extension for this plant. Oconee is a 

significant part of Duke Energy Carolinas’ generation portfolio representing over 2,500 

MW of capacity and annual energy output of approximately 20,000 GWHs. As such, it is 

important to start to examine the impacts of any potential retirement of Oconee to help 

the Company as it considers a second license extension, as well as incorporate these 

impacts into the resource planning process. 

In summary, the Company’s planning process must be dynamic and adaptable to 

changing conditions. This plan is the most appropriate resource plan at this point in time, 

however, good business practice requires Duke Energy Carolinas to continue to study the 

options, and make adjustments as necessary and practical to reflect improved information 

and changing circumstances. Consequently, a good business planning analysis is truly an 

evolving process that can never be considered complete. 

The seasonal projections of load, capacity, and reserves of the selected plan are provided 

in Table 8.A. 
93

Table 8.A

Summer Projections of Load, Capacity, and Reserves

for Duke Energy Carolinas 2012 Annual Plan

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 

Load Forecast

1 Duke System Peak 18,105 18,554 18,975 19,486 19,947 20,386 20,830 21,155 21,552 21,921 22,296 22,673 23,073 23,420 23,859 24,260 24,643 

 Reductions to Load Forecast

2 New EE Programs (62) (117) (181) (247) (317) (384) (451) (517) (585) (652) (720) (785) (854) (921) (988) (1,053) (1,123) 

3 Adjusted Duke System Peak 18,043 18,437 18,795 19,239 19,630 20,002 20,379 20,638 20,967 21,268 21,577 21,888 22,219 22,499 22,871 23,208 23,520 

Cumulative System Capacity

4 Generating Capacity 19,913 21,044 21,109 20,211 20,207 20,207 20,207 20,207 20,207 20,207 20,207 20,207 20,207 20,207 20,207 20,207 20,207 5 Capacity Additions 1,481 66 182 0 0 0 0 0 0 0 0 0 0 0 0 0 0 6 Capacity Derates 0 0 0 (4) 0 0 0 0 0 0 0 0 0 0 0 0 0 7 Capacity Retirements (350) 0 (1,080) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 8 Cumulative Generating Capacity 21,044 21,109 20,211 20,207 20,207 20,207 20,207 20,207 20,207 20,207 20,207 20,207 20,207 20,207 20,207 20,207 20,207 

 Purchase Contracts

9 Cumulative Purchase Contracts 340 340 328 328 328 328 261 258 170 155 155 155 155 155 155 155 141 

 Sales Contracts

10 Catawba Owner Backstand 0 (47) (47) (47) (47) (47) (47) (47) 0 0 0 0 0 0 0 0 0 

11 Firm Sale (150) (150) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 12 Cumulative Future Resource Additions

 Base Load 0 0 0 0 0 0 0 0 0 1,117 1,117 2,234 2,234 2,234 2,234 2,234 2,234 

 Peaking/Intermediate 0 0 0 700 700 1,400 2,200 2,200 2,200 2,200 2,200 2,200 2,200 2,200 2,200 2,900 2,900 

 Renewables 38 103 171 231 256 288 374 395 426 516 536 567 637 661 684 701 715 

13 Cumulative Production Capacity 21,272 21,356 20,664 21,419 21,444 22,177 22,994 23,013 23,003 24,195 24,215 25,363 25,433 25,457 25,480 26,198 26,197 

Reserves w/o Demand-Side Management

14 Generating Reserves 3,229 2,919 1,870 2,180 1,814 2,175 2,616 2,374 2,036 2,927 2,639 3,475 3,214 2,958 2,609 2,990 2,677 

15 % Reserve Margin 17.9% 15.8% 9.9% 11.3% 9.2% 10.9% 12.8% 11.5% 9.7% 13.8% 12.2% 15.9% 14.5% 13.1% 11.4% 12.9% 11.4% 

16 % Capacity Margin 15.2% 13.7% 9.0% 10.2% 8.5% 9.8% 11.4% 10.3% 8.9% 12.1% 10.9% 13.7% 12.6% 11.6% 10.2% 11.4% 10.2% 

Demand-Side Management

17 Cumulative DSM Capacity 872 956 1,043 1,099 1,140 1,153 1,167 1,180 1,194 1,200 1,207 1,207 1,207 1,207 1,207 1,207 1,207 

 IS / SG 95 100 90 86 82 82 82 82 82 82 82 82 82 82 82 82 82 

 Power Share / Power Manager 772 861 953 1,013 1,058 1,071 1,085 1,098 1,112 1,118 1,125 1,125 1,125 1,125 1,125 1,125 1,125 

18 Cumulative Equivalent Capacity 22,144 22,312 21,707 22,518 22,584 23,329 24,161 24,193 24,197 25,395 25,422 26,570 26,640 26,664 26,687 27,405 27,404 

Reserves w/ DSM

19 Generating Reserves 4,101 3,875 2,912 3,279 2,954 3,328 3,783 3,554 3,230 4,127 3,846 4,682 4,421 4,165 3,816 4,197 3,884 

20 % Reserve Margin 22.7% 21.0% 15.5% 17.0% 15.0% 16.6% 18.6% 17.2% 15.4% 19.4% 17.8% 21.4% 19.9% 18.5% 16.7% 18.1% 16.5% 21 % Capacity Margin 18.5% 17.4% 13.4% 14.6% 13.1% 14.3% 15.7% 14.7% 13.3% 16.3% 15.1% 17.6% 16.6% 15.6% 14.3% 15.3% 14.2% 
94

Winter Projections of Load, Capacity, and Reserves

for Duke Energy Carolinas 2012 Annual Plan

12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29 

Load Forecast

1 Duke System Peak 17,443 17,868 18,295 18,744 19,224 19,672 20,112 20,474 20,764 21,179 21,527 21,880 22,260 22,585 22,958 23,418 23,816 

 Reductions to Load Forecast

2 New EE Programs (60) (109) (164) (219) (303) (369) (435) (489) (567) (633) (699) (763) (814) (879) (963) (1,027) (1,095) 

3 Adjusted Duke System Peak 17,383 17,759 18,130 18,526 18,921 19,303 19,677 19,985 20,197 20,546 20,828 21,117 21,446 21,706 21,994 22,391 22,720 

Cumulative System Capacity

4 Generating Capacity 20,318 21,766 21,801 21,867 20,969 20,965 20,965 20,965 20,965 20,965 20,965 20,965 20,965 20,965 20,965 20,965 20,965 

5 Capacity Additions 2,074 36 66 182 0 0 0 0 0 0 0 0 0 0 0 0 0 6 Capacity Derates 0 0 0 0 (4) 0 0 0 0 0 0 0 0 0 0 0 0 7 Capacity Retirements (626) 0 0 (1,080) 0 0 0 0 0 0 0 0 0 0 0 0 0 8 Cumulative Generating Capacity 21,766 21,801 21,867 20,969 20,965 20,965 20,965 20,965 20,965 20,965 20,965 20,965 20,965 20,965 20,965 20,965 20,965 

 Purchase Contracts

9 Cumulative Purchase Contracts 347 347 335 335 335 335 268 265 170 155 155 155 155 155 155 155 141 

 Sales Contracts

10 Catawba Owner Backstand 0 (47) (47) (47) (47) (47) (47) (47) 0 0 0 0 0 0 0 0 0 11 Firm Sale (25) (25) (25) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 12 Cumulative Future Resource Additions

 Base Load 0 0 0 0 0 0 0 0 0 0 1,117 1,117 2,234 2,234 2,234 2,234 2,234 

 Peaking/Intermediate 0 0 0 0 700 700 1,400 2,200 2,200 2,200 2,200 2,200 2,200 2,200 2,200 2,200 2,900  Renewables 16 38 103 171 231 256 288 374 395 426 516 536 567 637 661 684 701 

13 Cumulative Production Capacity 22,103 22,115 22,233 21,429 22,184 22,209 22,873 23,756 23,729 23,746 24,953 24,973 26,121 26,191 26,215 26,238 26,941 

Reserves w/o Demand-Side Management

14 Generating Reserves 4,720 4,356 4,103 2,903 3,263 2,906 3,197 3,771 3,532 3,200 4,125 3,856 4,675 4,485 4,220 3,847 4,221 15 % Reserve Margin 27.2% 24.5% 22.6% 15.7% 17.2% 15.1% 16.2% 18.9% 17.5% 15.6% 19.8% 18.3% 21.8% 20.7% 19.2% 17.2% 18.6% 16 % Capacity Margin 21.4% 19.7% 18.5% 13.5% 14.7% 13.1% 14.0% 15.9% 14.9% 13.5% 16.5% 15.4% 17.9% 17.1% 16.1% 14.7% 15.7% 

Demand-Side Management

17 Cumulative DSM Capacity 570 595 617 635 653 653 653 653 653 653 653 653 653 653 653 653 653 

 

 IS / SG 95 100 90 86 82 82 82 82 82 82 82 82 82 82 82 82 82 

 

 Power Share / Power Manager 470 500 527 549 571 571 571 571 571 571 571 571 571 571 571 571 571 

 

18 Cumulative Equivalent Capacity 22,673 22,710 22,850 22,063 22,837 22,862 23,526 24,409 24,382 24,399 25,606 25,626 26,774 26,844 26,868 26,891 27,594 

 

Reserves w/ DSM

19 Generating Reserves 4,951 5,290 4,719 3,537 3,916 3,559 3,849 4,424 4,185 3,853 4,777 4,509 5,328 5,138 4,873 4,499 4,874 

 

20 % Reserve Margin 30.4% 27.9% 26.0% 19.1% 20.7% 18.4% 19.6% 22.1% 20.7% 18.8% 22.9% 21.3% 24.8% 23.7% 22.2% 20.1% 21.5% 21 % Capacity Margin 23.3% 21.8% 20.7% 16.0% 17.1% 15.6% 16.4% 18.1% 17.2% 15.8% 18.7% 17.6% 19.9% 19.1% 18.1% 16.7% 17.7% 
95 

 

Assumptions of Load, Capacity, and Reserves Table

The following notes are numbered to match the line numbers on the Summer and Winter Projections of Load,

Capacity, and Reserves tables. All values are MW except where shown as a Percent.

1. Planning is done for the peak demand for the Duke System including Nantahala. Nantahala became a 

 division of Duke Energy Carolinas in 1998.

4. Generating Capacity must be online by June 1 to be included in the available capacity for the summer

 peak of that year. Capacity must be online by Dec 1 to be included in the available capacity for the winter peak

 of that year. Includes 101 MW Nantahala hydro capacity, and total capacity for Catawba Nuclear Station less

 832 MW to account for NCMPA1 firm capacity sale.

5. Capacity Additions include Duke Energy Carolinas projects that have been approved by the NCUC (Cliffside 6,

 Dan River Combined Cycle facility). 

Capacity Additions include the conversion of Lee Steam Station unit 3 from coal to natural gas in 2015 (170 MW).

Capacity Additions include Duke Energy Carolinas hydro units scheduled to be repaired and returned to service. These units are

returned to service in the 2012-2015 timeframe and total 2 MW.

Also included is a 111 MW capacity increase due to nuclear uprates at Catawba, McGuire, and Oconee.

 Timing of these uprates is shown from 2012-2015

6. Capacity Derate of 4 MW associated with Marshall 4 SCR is included in 2016

7. The 350 MW capacity retirement in summer 2013 represents the projected fall 2012 retirement date for the old fleet CT retirements

The 1080 MW capacity retirement in summer 2015 represents the projected retirement date for Lee Steam Station (370 MW),

 Buck Steam Station units 5 and 6 (256 MW) and Riverbend Steam Station units 4-7 (454 MW).

The NRC has issued renewed energy facility operating licenses for all Duke Energy Carolinas' nuclear facilities.

The Hydro facilities for which Duke has submitted an application to FERC for licence renewal are assumed to 

 continue operation through the planning horizon.

All retirement dates are subject to review on an ongoing basis.

9. Cumulative Purchase Contracts have several components:

A. Piedmont Municipal Power Agency took sole responsibility for total load requirements 

 beginning January 1, 2006. This reduces the SEPA allocation from 94 MW to 19 MW in 2006, which is attributed to

 certain wholesale customers who continue to be served by Duke.

B. Purchased capacity from PURPA Qualifying Facilities includes the 88 MW Cherokee County Cogeneration Partners contract

 which began in June 1998 and expires June 2020 and miscellaneous other QF projects totaling 132 MW in 2013.

10-11. A firm wholesale backstand agreement up to 277 MW between Duke Energy Carolinas and PMPA starts on 1/1/2014 and

 continues through the end of 2020. Firm sale of 150 MW summer and 25 MW winter for FERC market power mitigation.

12. Cumulative Future Resource Additions represent a combination of new capacity resources or capability increases

 from the most robust plan.

15. Reserve Margin = (Cumulative Capacity-System Peak Demand)/System Peak Demand

Occurences when Reserve Margin exceeds +/-3% of the 15.5% target planning reserve margin:2013-2014 Reserve Margin 

1) 2013-2014: Due to the addition of Buck and Dan River CC and Cliffside 6 PC units coupled with lower economic load growth.

2) 2019: Due to the addition of 800 MW of CT capacity to meet resource need in 2019, 2020 and 2021.

3) 2022, 2024, and 2025: Due to the addition of 1117 MW nuclear units to meet long-term resource need in 2022 and 2024. 

16. Capacity Margin = (Cumulative Capacity - System Peak Demand)/Cumulative Capacity

17. The Cumulative Demand Side Management capacity includes new Demand Side Management capacity 

 representing placeholders for demand response and energy efficiency programs.
96

The charts in Chart 8.B and 8.C show the changes in Duke Energy Carolinas’ capacity 

mix and energy mix between 2013 and 2032. The relative shares of renewables, energy 

efficiency, and gas all increase, while the relative share of coal decreases. 

Chart 8.B 

 

Coal

35%

CC

6%

CT

12%

Nuclear

27%

Hydro

14%

Purchases

2%

DSM

4%

Renewables

0.2%

2013 Duke Energy Carolinas Capacity

Coal

33%

CC

8.7%

CT

1.0%

Nuclear

51%

Hydro

3.4%

Purchases

2%

Renewables

0.2% DSM/EE

0.5%

2013 Duke Energy Carolinas Energy 

Coal

24%

CC

12%

CT

17%

Nuclear

29%

Hydro

11%

Purchases

0.5%

DSM

4%

Renewables

3%

2032 Duke Energy Carolinas Capacity

Coal

18%

CC

16%

CT

2% Nuclear

50.1%

Hydro

3.3%

Purchases

0.5%

Renewables

3%

DSM/EE

7%

2032 Duke Energy Carolinas Energy 
97 

Chart 8.C 

Annual Capacity Projection 2013 through 2032 

Annual Energy Projection 2013 through 2032 

0

5,000

10,000

15,000

20,000

25,000

30,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 

MW

DEC Capacity

Nuclear New Nuclear Coal Cliffside 6

Gas New CT Buck CC Dan River CC

New CC Hydro Renewables DSM

Purchases DEC Load Obligation

-

20,000 

40,000 

60,000 

80,000 

100,000 

120,000 

140,000 

160,000 

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 

GWh

DEC Energy

Nuclear New Nuclear Coal Cliffside 6

Gas New CT Buck CC Dan River CC

New CC Hydro Renewables DSM/EE

Purchases
98

Table 8.D below represents the annual non-renewable incremental additions reflected in 

the LCR Table of the most robust expansion plan. The plan contains the addition of 

Cliffside Unit 6 in 2012, the unit retirements shown in Table 5.D and the impact of EE 

and DSM programs. 

Table 8.D

 

Year Month Project MW

2012 6 Bridgewater Hydro 8.75

2012 9 Cliffside 6 825

2012 12 Dan River Combined Cycle 620

2013 6 Nuclear Uprates 34

2014 6 Nuclear Uprates 65

2015 6 Nuclear Uprates 12

2016 6 New CC 700

2018 6 New CC 700

2019 6 New CT 800

2022 1 New Nuclear 1117

2023 8 New Nuclear 1117

2028 6 New CC 700

2030 6 New CT 800
99

The details of the forecasted capacity additions, including both nameplate capacity and 

the expected contribution of renewable resources towards Duke Energy Carolinas’ peak 

load needs, are summarized in Table 8.E below. 

Table 8.E Expected Renewable Resource Capacity Additions 

Year Wind Solar Biomass Total Wind Solar Biomass Total

2012 6 8 1 16 40 17 1 58

2013 0 28 10 38 0 56 10 66

2014 15 68 20 103 100 135 20 256

2015 15 127 30 171 100 253 30 383

2016 20 160 51 231 134 320 51 505

2017 20 176 60 256 135 352 60 546

2018 20 199 68 288 135 398 68 602

2019 48 235 90 374 322 471 90 883

2020 48 247 99 395 323 495 99 917

2021 49 269 108 426 324 538 108 970

2022 56 324 135 516 376 649 135 1160

2023 57 346 133 536 378 692 133 1204

2024 57 368 142 567 381 736 142 1258

2025 62 420 154 637 416 840 154 1411

2026 63 443 155 661 419 885 155 1459

2027 63 464 156 684 422 928 156 1507

2028 65 473 163 701 430 946 163 1540

2029 66 483 166 715 439 965 166 1571

2030 67 492 170 729 448 984 170 1602

2031 69 502 173 743 457 1004 173 1633

2032 69 502 173 758 457 1004 173 1665

Renewables

MW Contribution to Summer Peak MW Nameplate
100 

APPENDICES 
101

APPENDIX A: QUANTITATIVE ANALYSIS 

This appendix provides an overview of the Company’s quantitative analysis of resource 

options available to meet customers’ future energy needs. 

Overview of Analytical Process 

The analytical process consists of five steps: 

1. Assess resource needs 

2. Identify resource options and screen for further consideration 

3. Develop theoretical portfolio configurations 

4. Develop final portfolio options 

5. Perform portfolio analysis 

Assess Resource Needs 

Duke Energy Carolinas estimates the required load and generation resource balance 

needed to meet future customer demands by assessing: 

• Customer load forecast peak and energy – identifying future customer aggregate 

demands to identify system peak demands and developing the corresponding energy 

load shape 

• Existing supply-side resources – summarizing each existing generation resource’s 

operating characteristics including unit capability, potential operational constraints, 

and life expectancy 

• Operating parameters – determining operational requirements including target 

planning reserve margins and other regulatory considerations. 

Customer load growth coupled with the expiration of purchased power contracts, lower 

demand response, and renewable compliance assumptions, results in significant resource 

needs to meet energy and peak demands, based on the following assumptions: 

• 1.9% average summer peak system demand growth over the next 20 years without 

impacts of new energy efficiency programs and 1.7% summer peak demand 

growth with energy efficiency impacts 

• Generation retirements of approximately 350 MW of old fleet combustion 

turbines by the end of 2012 

• Generation retirements of approximately 1,040 MW of older coal units associated 

with the addition of Cliffside Unit 6. 
102

• Generation retirements of approximately 630 MW of remaining coal units without 

scrubbers by 2015 

• Approximately 70 MW of net generation reductions as a result of unit derates 

associated with new environmental equipment 

• Continued operational reliability of existing generation portfolio 

• A 15.5% target planning reserve margin for the planning horizon 

Identify and Screen Resource Options for Further Consideration 

The IRP process evaluates EE, DSM and supply-side options to meet customer energy 

and capacity needs. The Company develops DSM/EE options for consideration within 

the IRP based on input from our collaborative partners and cost-effectiveness screening. 

Supply-side options reflect a diverse mix of technologies and fuel sources (gas, coal, 

nuclear and renewable). Supply-side options are initially screened based on the 

following attributes: 

• Technically feasible and commercially available in the marketplace 

• Compliant with all federal and state requirements 

• Long-run reliability 

• Reasonable cost parameters. 

The Company compared capacity options within their respective fuel types and 

operational capabilities, with the most cost-effective options being selected for inclusion 

in the portfolio analysis phase. 

Resource Options 

Supply-Side

Based on the results of the screening analysis, the following technologies were included 

in the quantitative analysis as potential supply-side resource options to meet future 

capacity needs: 

• Base load – 825 MW Supercritical Pulverized Coal with CCS

• Base load – 618 MW IGCC with CCS

• Base load – 2 x 1,117MW Nuclear units (AP1000)

• Base load – 700 MW – 2x2x1 Combined Cycle (inlet chiller and duct fired)

• Peaking/Intermediate – 800 MW (4 x 200 MW) Simple Cycle CT

• Renewable – 150 MW Wind - On-Shore

• Renewable – 5 MW Landfill Gas 

• Renewable – 25 MW Solar PV
103

Although the supply-side screening curves showed that some of these resources would be 

screened out, they were included in the next step of the quantitative analysis for 

completeness. 

Energy Efficiency and Demand-Side Management

EE and DSM programs continue to be an important part of Duke Energy Carolinas’ 

system mix. The Company considered both demand response and conservation programs 

in the analysis. 

The Company modeled the program costs associated with EE and DSM based on a 

combination of both internal company expectations and projections based on information 

from the Company’s 2011 Market Potential Study. These program costs are expected to 

increase throughout the planning horizon as additional EE and DSM measures are 

implemented. 

Develop Theoretical Portfolio Configurations

The Company conducted a screening analysis using a simulation model to identify the 

most attractive capacity options under the expected load profile as well as under a range 

of sensitivities. This analysis began with a set of basic inputs which were varied to test 

the system under different future conditions, such as changes in fuel prices, load levels, 

and construction costs. These analyses yielded many different theoretical configurations 

of resources required to meet an annual 15.5% target planning reserve margin while 

minimizing the long-run revenue requirements to customers, with differing operating 

(production) and capital costs. 

The set of basic inputs included: 

• Fuel costs and availability for coal, gas, and nuclear generation 

• Development, operation, and maintenance costs of both new and existing 

generation 

• Compliance with current and potential environmental regulations; 

• Cost of capital 

• System operational needs for load ramping, spinning reserve (10 to 15-minute 

start-up) 

• The projected load and generation resource need 

• A menu of new supply side and EE/DSM resource options with corresponding 

costs and timing parameters 
104

Duke Energy Carolinas reviewed a number of variations to the theoretical portfolios to 

aid in the development of the portfolio options discussed in the following section.

Develop Final Portfolio Options 

Using the insights gleaned from developing theoretical portfolios, Duke Energy Carolinas 

created a representative range of generation plans reflecting plant designs, lead times and 

environmental emissions limits. Recognizing that different generation plans expose 

customers to different sources and levels of risk, the Company developed a variety of 

portfolios to assess the impact of various risk factors on the costs to serve customers. 

The portfolios analyzed for the development of this IRP were chosen to focus on the 

optimal timing of CT, CC, and nuclear additions in the 2016 – 2032 timeframe. 

The information as shown on the following pages outlines the planning options that the 

Company considered in the portfolio analysis phase. Each portfolio contains demand 

response and conservation identified in the base EE and DSM case and renewable 

portfolio standard requirements modeled after the NC REPS in NC and applied to SC. In 

addition, each portfolio contains the addition of Cliffside Unit 6 in September 2012, Dan 

River CC in December 2012, Lee Unit 3 Gas Conversion in January 2015 and the unit 

retirements shown in Table 5.D. 

The RPS assumptions are based on NC REPS in North Carolina. The assumptions for 

planning purposes are as follows: 

 Overall Requirements/Timing

• 3% of 2011 load by 2012 

• 6% of 2014 load by 2015 

• 10% of 2017 load by 2018 

• 12.5% of 2020 load by 2021 

Additional Requirements

• Up to 25% from EE through 2020 

• Up to 40% from EE starting in 2021 

• Up to 25% of the requirements can be met with out-of-state, unbundled RECs 

• Solar requirement 

o 0.02% by 2010 

o 0.07% by 2012 

o 0.14% by 2015 

o 0.20% by 2018 
105

• Swine waste requirement (NC only – using Duke Energy Carolinas’ share of 

total North Carolina load which is approximately 43%) 

o 0.07% by 2012 

o 0.14% by 2015 

o 0.20% by 2018 

• Poultry waste requirement (NC only - using Duke Energy Carolinas’ share of 

total North Carolina load which is approximately 43%) 

o 72,700 MWh by 2012 

o 292,000 MWh by 2013 

o 384,000 MWh by 2014 

Compliance with these requirements can be met with a combination of EE programs, instate RECs, out-of-state RECs, thermal RECs, and renewable projects that supply energy 

to the resource inventory. The costs associated with each of these resources are included 

in the resource plan, but only those that provide capacity and energy are used in the 

development of the resource plan. 

The overall requirements were applied to all retail load and to wholesale customers who 

have contracted with Duke Energy Carolinas to meet their REPS requirement. The 

requirement that a certain percentage must come from Swine and Poultry waste was not 

applied to the South Carolina portion. 

Conduct Portfolio Analysis 

Duke Energy Carolinas tested the portfolio options under the nominal set of inputs, as 

well as a variety of risk sensitivities and scenarios, in order to understand the strengths 

and weaknesses of various resource configurations and evaluate the long-term costs to 

customers under various potential outcomes. 

For this IRP analysis, the Company selected three main portfolios to illustrate the impacts 

of key risks and decisions. Each portfolio includes renewable resources to meet 

regulatory requirements and the base amount of EE/DSM resources as shown in Table 

4.A. 

The three analyzed portfolios are shown below: 

1. Natural Gas – Combustion turbine/combined cycle portfolio (CT/CC) 

2. Nuclear – Two nuclear unit portfolio with units on-line by the summer peak of 

2022 and 2024 (Nuclear) 

3. Regional Nuclear – Co-ownership of nuclear units in the region. The portfolio 

consists of 215 MW of nuclear by 2018, 730 MW in 2022 and 2024, and 558 

MW in 2028 
106

The sensitivities performed for these scenarios were those representing the highest risks 

going forward. 

The Company evaluated the following sensitivities: 

• Load forecast variations 

- Annual increase relative to base forecast (+7% for peak demand and +6% for 

energy by 2032) 

- Annual decrease relative to base forecast (-7% for peak demand and -8% for 

energy by 2032) 

• Construction cost sensitivity5

- Costs to construct a new nuclear plant (+20/- 10% higher than base case) 

- Costs to construct a new combined cycle plant (+30/- 5% higher than base 

case) 

• Fuel price variability 

- Higher Fuel Prices (coal prices 25% higher, natural gas prices 35% higher) 

- Lower Fuel Prices (coal prices 40% lower, natural gas prices 20% lower) 

• High EE and DSM 

- For EE, this sensitivity assumes full compliance with the Duke EnergyProgress Energy merger settlement agreement with the cumulative EE 

achievements since 2009 counted toward the cumulative settlement 

agreement impacts. The incremental impacts stop in 2031 after reaching 

the full economic potential of 16.5 million MWH. For DSM, an 

additional 100 MW of load curtailment is added by 2017. 

• Carbon Emission Price 

- The reference case is a cap and trade program with CO2 emission prices 

based on the Company’s 2012 fundamental prices. The prices ranged 

from $17/ton starting in 2020 to $44/ton in 2032. The reference CO2 

prices fall at the lower end of the range of prices that were estimated to 

result from federal climate change legislation that was proposed and 

debated in Congress over the past few years. 

- The Company also performed a sensitivity analysis with higher CO2 costs 

ranging from $31/ton in 2020 to $80/ton in 2032. 

• Clean Energy Legislation: Assumptions used in this analysis include: 

- No carbon emission price. 

- 10% of retail sales by 2015 must be clean energy, increasing to 30% by 

2030 

5

 These sensitivities test the risks from increases in construction costs of one type of supply-side resource at 

a time. In reality, cost increases of many construction component inputs such as labor, concrete and steel 

would affect all supply-side resources to varying degrees rather than affecting one technology in isolation. 
107

- Alternative compliance payment of 30$/MWh 

- “Clean Energy” includes renewable resources, EE, nuclear, natural gas 

CC, or alternative compliance payment 

• No Carbon Emission Price 

- Although the Company believes there will be a carbon constrained future 

a sensitivity analysis without a CO2 emission price was provided to show 

the relative impact of carbon on the nuclear and gas portfolios. In addition, 

a sensitivity analysis was also performed with higher fuel prices to reflect 

the impact fuel volatility can have on the portfolios without carbon prices. 

An overview of the specifics of each portfolio is shown in Table A.1 below. 

Table A.1 - Portfolios Evaluated 

Year

CT/CC Nuclear

Regional

Nuclear

2012

2013

2014

2015

2016 CC CC CC

2017 N

2018 CC CC N, CC

2019 CT CT

2020 CT

2021

2022 CC N N

2023

2024 CC N N

2025

2026

2027 CC CC

2028 CT CC N

2029

2030 CT CT

2031 CC

2032 CT CT CT

Total CT 1,930 MW 1,800 MW 1,800 MW

Total CC 4,200 MW 2,100 MW 2,100 MW

Total Nuclear 2,234 MW 2,234 MW

Total Nuclear Uprate 111 MW 111 MW 111 MW

Portfolios
108

Quantitative Analysis Results 

Three potential resource planning strategies were tested under base assumptions and 

variations in CO2 price, fuel costs, load/energy efficiency, and nuclear and combined 

cycle capital costs. These three potential resource planning strategies are: 

• No new nuclear capacity (the CT/CC portfolio) 

• Full ownership of new nuclear capacity (the 2 Nuclear Units portfolio) 

• Regional co-ownership of new nuclear capacity (the Regional Nuclear portfolio) 

For the base case and sensitivities, the Company calculated the PVRR for each portfolio. 

The revenue requirement calculation estimates the costs to customers for the Company to 

recover system production costs and new capital incurred. Duke Energy Carolinas used a 

50-year analysis time frame to fully capture the long-term impact of nuclear generation 

added in the 20 year planning horizon. Table A.2 below represents a comparison of the 

Natural Gas (CT/CC) portfolio with a full ownership nuclear portfolio (1st unit in 2022 & 

2nd unit in 2024) and the regional nuclear portfolio over a range of sensitivities. The 

green block represents the lowest PVRRs between the Natural Gas and the two nuclear 

portfolios. The value contained within the block is the PVRR savings in $billions 

between the cases. 

Table A.2 - Comparison of Nuclear Portfolios to the CT/CC Portfolio ($ Billions) 

6

 The difference between the CT/CC and Nuclear portfolios is less than $10 million. 

Reference Case CO2 Price Clean Energy

Portfolio Base5

High CO2 High Fuel Cost Low Fuel Cost $30 ACP

Nuclear (3.0) (3.1) (2.5)

Regional Nuclear (0.1) (3.1) (3.2) (2.5)

CT/CC 0.01 Nucl 2.1 Nucl / 1.8 Reg

Portfolio High Load Low Load High EE & DSM No Cost No Cost / High Fuel

Nuclear (0.01)

Regional Nuclear (0.07)

CT/CC 0.7 Nucl / 0.6 Reg 0.6 Nucl / 0.4 Reg 3.8 Nucl / 3.5 Reg 0.9 Nucl / 0.6 Reg

Portfolio Nuclear 20% Increase Nuclear 10% Decrease Gas 30% Increase Gas 5% Decrease6

Nuclear (1.2) (0.7)

Regional Nuclear (1.3) (0.8) (0.02)

CT/CC 2.4 Nucl / 2.2 Reg 0.1 Nucl

Load Sensitivity No Carbon Sensitivity

Fuel Sensitivity

Capital Cost Sensitivity
109

Based on the quantitative analysis, the recommended plan includes two new nuclear units 

in the 2020 timeframe. The nuclear portfolios and the natural gas portfolio are essentially 

breakeven in the base portfolios. Even with lower natural gas prices, increased CC 

efficiency, increased energy efficiency and lower projected load for the 2012 IRP, the 

portfolios with nuclear remain competitive with natural gas portfolios. It is the 

Company’s belief that there is more upside risk in fuel cost as reflected in the fuel price 

sensitivities. The high fuel price sensitivity shows that small increases in fuel price 

would impact the cost-effectiveness of the nuclear portfolios. In a Clean Energy 

Standard regulatory construct, the cost benefits of adding additional nuclear are greater 

than in a CO2 Cap and Trade construct. 

The Company’s proposed portfolio including full ownership of two nuclear units in 2022 

and 2024 continues to be cost effective, but the Company recognizes the potential 

benefits to customers of securing new nuclear generation in smaller capacity increments 

through regional nuclear development. Duke Energy Carolinas’ analysis indicates that 

the regional nuclear portfolio is lower cost to customers in the base case and most 

scenarios, but the full nuclear portfolio was chosen for the 2012 IRP preferred plan 

because there are no firm commitments in place at this time for the regional nuclear 

portfolio. Several advantages to a regional nuclear approach are: 

• Load Growth: Smaller blocks of base load generation brought on-line over a 

period of years would more closely match projected load growth. 

• Financial: The substantial capital cost would be phased in over a longer period of 

time and would spread the risk if there were cost increases. 

• Regulatory Uncertainty: The optimal amount and timing of additional nuclear 

generation will depend on the outcome of final GHG legislation. Using a regional 

approach would allow utilities to better optimize their portfolios as legislation or 

regulation change over time. 

Duke Energy Carolinas continues to support regional nuclear opportunities and is 

actively pursuing this concept. The Company will continue to assess opportunities to 

benefit from economies of scale and risk reduction by considering the prospects for joint 

ownership for new nuclear generation resources including potentially with Progress 

Energy Carolinas. As the Company announced in 2011 Duke Energy Carolinas has 

agreements with JEA, located in Jacksonville, Florida, and with the Public Service 

Authority of South Carolina (Santee Cooper). Duke Energy Carolinas has an agreement 

with Santee Cooper to perform due diligence to potentially acquire an option for a 

minority interest (5 to 10% of the capacity of the two units) in Santee Cooper’s 45% 

ownership of the planned new nuclear reactors at V.C. Summer Nuclear Generating 

 

7

 The CT/CC portfolio is more cost effective than the Nuclear portfolio by approximately $120 million. 
110

Station in South Carolina. The new Summer units are scheduled to be online in 2017 and 

2018. JEA has signed an option agreement to potentially purchase up to 20% of Lee 

Nuclear Station. 

Although the Company believes it needs to plan for a carbon constrained future, a 

sensitivity analysis without a CO2 emission price has been incorporated to show the 

relative impact of carbon on the nuclear and gas portfolios. In addition, a sensitivity 

analysis was also performed with higher fuel prices to reflect the impact fuel volatility 

can have on the portfolios without carbon prices. The lack of CO2 prices significantly 

advantages the natural gas portfolio. However, as shown in Table A.2, the sensitivity 

analysis indicates that the addition of higher fuel prices to the no-carbon sensitivity 

reduces the value of the natural gas portfolio by approximately $3 billion PVRR. 

The high nuclear capital cost sensitivity analysis reflects the importance of minimizing 

cost increases on the new nuclear generation. However, there is the risk that natural gas 

generation cost could also increase with the significant amount of natural gas generation 

that will be added over the planning horizon. 

Quantitative Analysis Summary 

One of the major benefits of having additional nuclear generation is the lower system 

CO2 footprint and the associated economic benefit. The projected CO2 emissions under 

the CT/CC, Nuclear, and Regional Nuclear scenarios are shown in Chart A.3 below. A 

review of these projections illustrates that for the Company to achieve material system 

reductions in CO2 emissions, it must add new nuclear generation to the future resource 

portfolio. In the absence of a CO2 policy, the CO2 emissions in each portfolio would be 

at least two million tons higher by 2032. 
111

Chart A.3 - CO2 Emissions 

The biggest risks to the proposed nuclear portfolios are the time required to license and 

construct a nuclear unit, uncertainty regarding GHG regulation/legislation, potential for 

lower demand than currently estimated, capital cost to build, and the ability to secure 

favorable financing. However, in a carbon constrained future, new nuclear generation 

must be in the generation mix to reduce the Company’s carbon footprint. This is 

especially true as Oconee Nuclear Station nears the end of its licensed life in the 2030 

timeframe. 

In summary, the results of the quantitative analyses indicate that it is prudent for Duke 

Energy Carolinas to continue to preserve the option to build new nuclear capacity in the 

2020 timeframe. The Company’s analysis re-affirms the advantages of favorable 

financing and co-ownership in future nuclear generation. Duke Energy Carolinas is 

pursuing favorable financing options and continues to seek potential regional generation 

partners. 

The overall conclusions of the quantitative analysis are that significant additions of base 

load, intermediate, peaking, EE, DSM, and renewable resources to the Duke Energy 

Carolinas portfolio are required over the planning horizon. Conclusions based on these 

analyses are: 

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032

Thousands of Tons/Year

CO2 Emission Projections

CT/CC Nuclear Regional Nuclear
112

• The new levels of EE and DSM are cost-effective for customers. 

- The screening analysis shows that portfolios with the new EE and DSM 

were lower cost than those without and EE and DSM. 

- The high EE sensitivity assumes 100% participation of cost effective EE 

programs identified in the 2011 Market Potential study. The high EE 

sensitivity is cost effective if there is an equal participation between 

residential and non-residential customers. If a significant number of nonresidential customers opt out, then the high EE case may no longer be 

cost effective. 

• Significant renewable resources will be needed to meet the new NC REPS and a 

potential federal standard. 

• There is a capacity need in the 2016 to 2020 timeframe to maintain the target 

15.5% reserve margin. 

• The analysis demonstrates that the nuclear option is an attractive option for the 

Company’s customers. 

- Continuing to preserve the option to secure new nuclear generation is 

prudent under the circumstances. 

- Favorable financing is very important to the project cost when compared 

to other generation options. 

- Co-ownership is beneficial from a generation and risk perspective.

For the purpose of demonstrating that there will be sufficient resources to meet 

customers’ needs, Duke Energy Carolinas has selected a balanced portfolio which, over 

the 20-year planning horizon includes: 

• 1,071 MW equivalent of incremental DSM capacity 

• 135 MW of capacity from grid modernization impacts 

• 1,320 MW of new EE (reduction to system peak load) 

• 2,234 MW of new nuclear capacity 

• 2,100 MW of new CC capacity 

• 1,800 MW of new CT capacity 

• 111 MW of nuclear uprates 

• 758 MW of renewables (1,665 MWs nameplate) 

Significant challenges remain with respect to the Company’s portfolio, such as obtaining 

the necessary regulatory approvals to implement the EE and DSM programs and supply 

side resources, finding sufficient cost-effective, reliable renewable resources to meet the 

NC REPS standard, effectively integrating renewables into the resource mix, and 

ensuring sufficient transmission capability for these resources. 
113 

APPENDIX B 

Duke Energy Carolinas

Spring 2012 Forecast

Sales

Rates Billed

Peaks

2012-2027
114 

 Page

I. EXECUTIVE SUMMARY 1

II. FORECAST METHODOLOGY 3

III. BILLED SALES AND OTHER ENERGY REQUIREMENTS

A. System Billed Sales 7

B. Residential Billed Sales 8

C. Commercial Billed Sales 9

D. Total Industrial Billed Sales 10

E. Textile Billed Sales 11

F. Other Industrial Billed Sales 12

G. Other Retail Billed Sales 13

H. Retail Billed Sales 14

I. Full / Partial Requirements Wholesale Sales 15

IV. NUMBER OF RATES BILLED

A. Total Rates Billed 17

B. Residential Rates Billed 18

C. Commercial Rates Billed 19

D. Total Industrial Rates Billed 20

E. Textile Rates Billed 21

F. Other Industrial Rates Billed 22

V. SYSTEM PEAKS

A. Summer Peak 24

B. Winter Peak 26

C. Load Factor 28

V. LOAD DEFINITIONS 29

Table of Contents
115 

 (Load Forecast Pg 1) 

Item %

System Sales 80,129 GWH 81,506 GWH 1,376 GWH 1.7%

System Summer Peak 17,716 MW 18,043 MW 327 MW 1.8%

Note: After Duke Energy Carolinas sponsored energy efficiency (EE) programs have been subtracted.

Growth Statistics from 2012 to 2013

Forecasted 2012 Growth

Amount

Forecasted 2013

Amount Amount

System Sales & System Peak Summer (2012 Spring Forecast vs. 2011 Spring Forecast)

System Sales is the sum of Retail and Wholesale. Retail Sales include Residential, 

Commercial, Industrial and Other Retail (Public Street Lighting & Traffic Signals). 

Wholesale Sales include contracts with municipals in Duke's service area as well as 

contracts with Piedmont, Blue Ridge , Rutherford, Haywood, NCEMC Retained, 

NCEMC Load Shape and New Horizon. The summer peak demand includes all loads 

that Duke Carolinas has a contractual obligation to serve, and thus includes System Sales 

plus Line losses and Company Use, and is after DSM has been subtraacted.

All sales & peaks given in this book are after the impacts of Duke Energy Carolinas 

sponsored energy efficiency (EE) programs have been subtracted.

System Sales Outlook for the Forecast Horizon (2011 – 2027)

System Sales for the Spring 2012 Forecast are projected to grow at an average annual rate of 1.5% 

from 2011 through 2027, which is less than the 1.7% in the Spring 2011 Forecast. The Spring 2012 

Forecast for Residential, Commercial and Industrial is lower term than the Spring 2011 Forecast due to 

slower projected economic growth and the fact that actual sales in the latter part of 2011 were weaker 

than expected . 

Adjustments were made to the Spring 2012 Forecasts and the Spring 2011 Forecasts to account for 

Duke Energy Carolinas Sponsored Energy Efficiency programs and the expected ban of incandescent 

lighting mandated by the Energy Independence and Security Act of 2007, as well as for the expected 

growth Plug-in Electric Vehicles. Additional adjustments to the Spring 2012 Forecast include sales 

reductions due to projected growth in Solar Energy. 

Growth in the Wholesale is extremely strong from 2013-2019 due to the stair-step pattern of the 

contract with New Horizon beginning in 2013. By 2020 Duke Carolinas will supply 100% of their load. Executive Summary
116

 

 (Load Forecast Pg 2)

Item Amount % Amount %

System Sales:

Residential 308 GWH 1.0% 419 GWH 1.3% -111 GWH

Commercial 558 GWH 1.8% 641 GWH 2.0% -84 GWH

Industrial (total) 141 GWH 0.6% 159 GWH 0.7% -18 GWH

Textile -44 GWH -1.2% -36 GWH -1.0% -8 GWH

Other Industrial 184 GWH 1.0% 195 GWH 1.1% -11 GWH

Other 5 GWH 1.5% 5 GWH 1.6% 0 GWH

Wholesale 369 GWH 5.1% 407 GWH 5.5% -38 GWH

Total System 1,380 GWH 1.5% 1,632 GWH 1.7% -252 GWH

Item % %

System Peaks

Summer 338 MW 1.7% 353 MW 1.8% -14 MW

Winter 326 MW 1.7% 336 MW 1.8% -10 MW

Note: After Duke Energy Carolinas sponsored energy efficiency (EE) programs have been subtracted. 

Amount Amount

Spring 2012 Forecast

Annual Growth

(2011-2027)

Spring 2011 Forecast

Annual Growth

(2011-2027)

Comparison of System Sales Growth Statistics

Spring 2012 Forecast vs. Spring 2011 Forecast

Comparison of System Peak Demand Growth Statistics

Spring 2012 Forecast vs. Spring 2011 Forecast

Spring 2012 Forecast

Annual Growth

(2011-2027)

Spring 2011 Forecast

Annual Growth

(2011-2027)

Annual

Difference 1

Average 

Annual

Difference 

Average 

Note: After Duke Energy Carolinas sponsored energy efficiency (EE) programs have been 

subtracted.

System Peak Outlook for the Forecast Horizon (2011 – 2027)

System peak hour demands are forecasted on a summer and winter basis. The peak forecast

information below represents the amount of load that Duke Energy Carolinas is contractually 

obligated to serve and is used as the basis for Duke's Integrated Resource Plan. 

The forecasts include an adjustment for proposed utility sponsored energy efficiency 

programs as well as adjustments for the expected growth in Plug-in Hybrid Electric Vehicles 

(PHEV) and the proposed ban on incandescent lighting. The Spring 2012 Forecast also 

reflects the impacts of expected growth in solar energy. 

The system summer peak demand on the Duke Energy Carolinas is expected to grow at an 

average annual rate of 1.7% from 2011 through 2027. The system peak winter demand is also 

expected to grow at an average annual rate of 1.7% from 2011 through 2027. 
117

(Load Forecast Pg 3) 

General forecasting methodology for Duke Energy Carolinas energy and demand 

forecasts for Spring 2012

Duke Energy Carolinas’ Spring 2012 forecasts represent projections of the energy 

and peak demand needs for its service area, which is located within the states of North 

and South Carolina, including the major urban areas of Charlotte, Greensboro and 

Winston-Salem in North Carolina and Spartanburg and Greenville in South Carolina. 

The forecasts cover the time period of 2012 – 2027 and represent the energy and peak 

demand needs for the Duke Energy Carolinas system comprised of the following 

customer classes and other utility/wholesale entities:

• Residential

• Commercial

• Textiles

• Other Industrial

• Other Retail

• Duke Energy Carolinas full/partial requirements wholesale

Energy use is dependent upon key economic factors such as income, energy prices 

and employment along with weather. The general framework of the Company’s 

forecast methodology begins with forecasts of regional economic activity, 

demographic trends and expected long-term weather. The economic forecasts used in 

the Spring 2012 forecasts are obtained from Moody’s Analytics, a nationally 

recognized economic forecasting firm, and include economic forecasts for the Duke 

Carolinas service area region. These economic forecasts represent long-term 

projections of numerous economic concepts including the following:

• Total real gross regional product (GRP)

• Non-manufacturing real GRP

• Non-manufacturing employment 

• Manufacturing real GRP industry group, e.g., textiles

• Manufacturing Employment industry group

• Total real personal income

Total population forecasts are obtained from the two states’ demographic offices for 

each county in each state which are then used to derive the total population forecast 

for the 51 counties that the Company serves in the Carolinas.

Forecast Methodology
118

(Load Forecast Pg 4) 

General forecasting methodology (continued)

A projection of weather variables, cooling degree days (CDD) and heating degree days 

(HDD), is made for the forecast period by examining long-term historical weather. For the 

Spring 2012 forecasts, a 10 year simple average of CDD and HDD were used. 

Other factors influencing the forecasts are identified and quantified such as changes in 

wholesale power contracts, historical billing days and other demographic trends including 

housing square footage, etc. 

Energy forecasts for all of the Company’s retail customers are developed at a customer class 

level, i.e., residential, commercial, textile, other industrial and street lighting along with 

forecasts for its wholesale customers. Econometric models incorporating the use of industrystandard linear regression techniques were developed utilizing a number of key drivers of 

energy usage as outlined above. The following provides information about the models.

Residential Class:

The Company’s residential class sales forecast is comprised of two separate and independent 

forecasts. The first is the number of residential rates billed which is driven by population 

projections of the counties in which the Company provides electric service. The second 

forecast is energy usage per rate billed which is driven primarily by weather, regional 

economic and demographic trends, electric price and appliance efficiencies. The total 

residential sales forecast is derived by multiplying the two forecasts together.

Commercial Class:

Commercial electricity usage changes with the level of regional economic activity, such as 

personal income or commercial employment, and the impact of weather.

Textile Class: 

The level of electricity consumption by Duke Energy Carolinas’ textile group is impacted by 

the level of textile manufacturing output, exchange rates, electric prices and weather.

Other Industrial Class:

Electricity usage for Duke’s other industrial customers was forecasted by 5 groups according 

to the 3 digit NAICS classification and then aggregated to provide the overall other industrial 

sales forecast. Usage is driven primarily by regional manufacturing output at a 3 digit NAICS 

level, industrial production indices, electric prices and weather.

Other Retail Class: 

This class in comprised of public street lighting and traffic signals within the Company’s 

service area. The level of electricity usage is impacted not only by economic growth but also 

by advances in lighting efficiencies.

Full / Partial Requirements Wholesale:

Duke Energy Carolinas provides electricity on a contract basis to numerous wholesale 

customers. The larger wholesale entities are forecasted by using an econometric model with 

aggregate economic drivers such as regional GDP or income. The very small entities are 

forecasted by assuming they grow at the same rate as Duke's retail sector. The Wholesale 

category is also affected by the terms of the contracted sales agreements and any changes 

therein. 
119 

(Load Forecast Pg 5) Billed Sales and Other Energy Requirements
120 

(Load Forecast Pg 6) 

System Sales, which includes billed sales to Retail and Wholesale, are expected to 

grow at 1380 GWH per year or 1.5% over the forecast horizon. Retail sales 

include GWH sales billed to the Residential, Commercial, Industrial, Street and 

Public Lighting, and Traffic Signal Service classes. Full/Partial Requirements 

Wholesale sales include GWH sales billed to municipalities and public utility 

companies that purchase their full power requirements from the Company, plus in 

the forecast period, supplemental sales to specified EMCs in North Carolina and 

sales to the city of Greenwood, SC and sales to the Central Electric Power 

Cooperative, (New Horizon Contract).

Adjustments were made to the energy and peak projections for the Spring 2012 

Forecast to reflect the effects of utility sponsored energy efficiency programs, and 

additions from the expected growth in Plug-in Hybrid Electric Vehicles (PHEV) in 

the forecast. The expected ban on incandescent lighting mandated by the Energy 

Independence and Security Act of 2007 is reflected in the residential sales model 

by adjusting the appliance efficiency variable. Also, the expected reduction due to 

solar energy was included.

Points of Interest

• The Residential class continues to show positive growth, driven by steady gains 

in population within the Duke Energy Carolinas service area. The resulting annual 

growth in Residential billed sales is expected to average 1.0% over the forecast 

horizon.

• The Commercial class is projected to be the fastest growing retail class, with 

billed sales growing at 1.8% per year over the next fifteen years. The three largest 

sectors in the Commercial Class are Offices, which includes banking, Retail and 

Education. 

• The Industrial The long term structural decline that has occurred in the Textile 

industry is expected to moderate in the forecast horizon, with an overall projected 

decline of 1.2%, compared to an average decline of 6.9% from 1996-2011. In the 

Other Industrial sector, several industries such as Autos, Rubber & Plastics and 

Primary Metals, are projected to show strong growth. Overall, Other Industrial 

sales are expected to grow 1.0% over the forecast horizon.

• The Full/Partial Requirements Wholesale class is expected to grow at 5.1% 

annually over the forecast horizon, primarily due to the forecasted supplemental 

sales to specified EMCs in North Carolina and sales to New Horizons in South 

Carolina.
121

(Load Forecast Pg 7) 

System Billed Sales (After EE Subtracted) (Sum of Retail and Full/Partial Wholesale classes)

 

 

Year Actual Growth GWH %

GWH GWH % Per Year Per Year

2002 76,769 1,164 1.5

2003 74,784 -1,984 -2.6

2004 77,374 2,590 3.5

2005 79,130 1,756 2.3

2006 78,347 -784 -1.0

2007 81,572 3,225 4.1 History (2006 to 2011) 701 0.9

2008 81,066 -505 -0.6 History (1996 to 2011) 613 0.8

2009 77,528 -3,539 -4.4 

2010 84,088 6,561 8.5 Spring 2012 Forecast (2011 to 2027) 1380 1.5

2011 81,851 -2,237 -2.7 Spring 2011 Forecast (2011 to 2027) 1632 1.7

 

 Growth

Year GWH GWH % GWH GWH % GWH %

2012 80,129 -1,722 -2.1 82,273 422 1.0 -2,144 -2.6%

2013 81,506 1,376 1.7 84,039 1,766 2.1 -2,534 -3.0%

2014 83,223 1,717 2.1 85,930 1,891 2.2 -2,708 -3.2%

2015 85,072 1,850 2.2 87,752 1,821 2.1 -2,679 -3.1%

2016 86,939 1,867 2.2 89,570 1,819 2.1 -2,631 -2.9%

2017 88,779 1,840 2.1 91,427 1,857 2.1 -2,648 -2.9%

2018 90,654 1,875 2.1 93,364 1,937 2.1 -2,710 -2.9%

2019 92,359 1,705 1.9 95,146 1,782 1.9 -2,787 -2.9%

2020 93,720 1,361 1.5 96,546 1,399 1.5 -2,826 -2.9%

2021 95,098 1,378 1.5 97,950 1,405 1.5 -2,852 -2.9%

2022 96,498 1,399 1.5 99,479 1,529 1.6 -2,981 -3.0%

2023 97,903 1,405 1.5 101,104 1,625 1.6 -3,202 -3.2%

2024 99,323 1,420 1.5 102,775 1,670 1.7 -3,452 -3.4%

2025 100,810 1,487 1.5 104,454 1,679 1.6 -3,644 -3.5%

2026 102,327 1,517 1.5 106,189 1,734 1.7 -3,862 -3.6%

2027 103,930 1,604 1.6 107,960 1,771 1.7 -4,029 -3.7%

SPRING 2012 FORECAST SPRING 2012 vs SPRING 2011

 HISTORY AVERAGE ANNUAL GROWTH

Growth

SPRING 2011 FORECAST

55,000

65,000

75,000

85,000

95,000

105,000

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

GWH

Year

History Spring 2011 Forecast Spring 2012 Forecast
122 

(Load Forecast Pg 8) 

Residential Billed Sales (After EE Subtracted)

 

Year Actual Growth GWH %

GWH GWH % Per Year Per Year

2002 24,466 1,194 5.1

2003 23,947 -519 -2.1

2004 25,150 1,203 5.0

2005 26,108 958 3.8

2006 25,816 -292 -1.1

2007 27,459 1,643 6.4 History (2006 to 2011) 501 1.9

2008 27,335 -124 -0.5 History (1996 to 2011) 456 1.9

2009 27,273 -62 -0.2 

2010 30,049 2,777 10.2 Spring 2012 Forecast (2011 to 2027) 308 1.0

2011 28,323 -1,726 -5.7 Spring 2011 Forecast (2011 to 2027) 419 1.3

SPRING 2012 vs SPRING 2011

 

 

Year GWH GWH % GWH GWH % GWH %

2012 27,118 -1,205 -4.3 27,749 -574 1.0 -631 -2.3%

2013 27,252 134 0.5 27,914 165 0.6 -662 -2.4%

2014 27,584 332 1.2 28,350 436 1.6 -766 -2.7%

2015 27,974 390 1.4 28,760 410 1.4 -786 -2.7%

2016 28,391 417 1.5 29,154 394 1.4 -763 -2.6%

2017 28,796 405 1.4 29,554 400 1.4 -758 -2.6%

2018 29,209 414 1.4 29,995 441 1.5 -786 -2.6%

2019 29,623 413 1.4 30,454 459 1.5 -831 -2.7%

2020 30,056 433 1.5 30,926 472 1.5 -870 -2.8%

2021 30,490 434 1.4 31,387 461 1.5 -896 -2.9%

2022 30,930 439 1.4 31,946 559 1.8 -1,017 -3.2%

2023 31,369 440 1.4 32,535 589 1.8 -1,166 -3.6%

2024 31,826 456 1.5 33,154 619 1.9 -1,329 -4.0%

2025 32,296 470 1.5 33,774 620 1.9 -1,478 -4.4%

2026 32,758 462 1.4 34,408 634 1.9 -1,650 -4.8%

2027 33,243 485 1.5 35,021 614 1.8 -1,778 -5.1%

SPRING 2012 FORECAST

 HISTORY AVERAGE ANNUAL GROWTH

Growth

SPRING 2011 FORECAST

Growth

16,000

20,000

24,000

28,000

32,000

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

GWH

Year

History Spring 2011 Forecast Spring 2012 Forecast
123 

(Load Forecast Pg 9) 

Commercial Billed Sales (After EE Subtracted)

 

Year Actual Growth GWH %

GWH GWH % Per Year Per Year

2002 24,242 576 2.4

2003 24,355 113 0.5

2004 25,204 849 3.5

2005 25,679 475 1.9

2006 26,030 352 1.4

2007 27,433 1,402 5.4 History (2006 to 2011) 312 1.2

2008 27,288 -145 -0.5 History (1996 to 2011) 533 2.3

2009 26,977 -311 -1.1 

2010 27,968 991 3.7 Spring 2012 Forecast (2011 to 2027) 558 1.8

2011 27,593 -375 -1.3 Spring 2011 Forecast (2011 to 2027) 641 2.0

SPRING 2012 vs SPRING 2011

 

 

Year GWH GWH % GWH GWH % GWH %

2012 27,196 -397 -1.44 27,759 167 1.0 -564 -2.0%

2013 27,626 430 1.6 28,399 640 2.3 -773 -2.7%

2014 28,234 608 2.2 29,031 631 2.2 -796 -2.7%

2015 28,871 637 2.3 29,658 627 2.2 -787 -2.7%

2016 29,502 631 2.2 30,281 623 2.1 -779 -2.6%

2017 30,098 596 2.0 30,907 626 2.1 -809 -2.6%

2018 30,694 596 2.0 31,537 630 2.0 -843 -2.7%

2019 31,286 593 1.9 32,173 636 2.0 -886 -2.8%

2020 31,886 600 1.9 32,815 642 2.0 -928 -2.8%

2021 32,507 621 1.9 33,468 653 2.0 -960 -2.9%

2022 33,138 631 1.9 34,129 662 2.0 -991 -2.9%

2023 33,768 630 1.9 34,847 718 2.1 -1,079 -3.1%

2024 34,390 622 1.8 35,577 729 2.1 -1,187 -3.3%

2025 35,066 676 2.0 36,319 742 2.1 -1,252 -3.4%

2026 35,787 721 2.1 37,074 756 2.1 -1,287 -3.5%

2027 36,514 727 2.0 37,851 777 2.1 -1,337 -3.5%

 HISTORY AVERAGE ANNUAL GROWTH

SPRING 2012 FORECAST SPRING 2011 FORECAST

Growth Growth

12,000

16,000

20,000

24,000

28,000

32,000

36,000

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

GWH

Year

History Spring 2011 Forecast Spring 2012 Forecast
124 

(Load Forecast Pg 10) 

Total Industrial Billed Sales (After EE Subtracted)

 

 

Year Actual Growth GWH %

GWH GWH % Per Year Per Year

2002 26,259 -643 -2.4

2003 24,764 -1,496 -5.7

2004 25,209 445 1.8

2005 25,495 286 1.1

2006 24,535 -960 -3.8

2007 23,948 -587 -2.4 History (2006 to 2011) -750 -3.3

2008 22,634 -1,314 -5.5 History (1996 to 2011) -597 -2.4

2009 19,204 -3,430 -15.2 

2010 20,618 1,414 7.4 Spring 2012 Forecast (2011 to 2027) 141 0.6

2011 20,783 164 0.8 Spring 2011 Forecast (2011 to 2027) 159 0.7

SPRING 2012 vs SPRING 2011

 

 

Year GWH GWH % GWH GWH % GWH %

2012 20,765 -17 -0.1 21,374 592 1.0 -609 -2.9%

2013 20,864 98 0.5 21,600 225 1.1 -736 -3.4%

2014 21,016 152 0.7 21,770 171 0.8 -755 -3.5%

2015 21,169 153 0.7 21,871 100 0.5 -702 -3.2%

2016 21,316 148 0.7 21,963 93 0.4 -647 -2.9%

2017 21,458 142 0.7 22,059 96 0.4 -601 -2.7%

2018 21,605 146 0.7 22,159 100 0.5 -555 -2.5%

2019 21,755 150 0.7 22,263 104 0.5 -508 -2.3%

2020 21,911 156 0.7 22,375 112 0.5 -464 -2.1%

2021 22,064 153 0.7 22,493 119 0.5 -429 -1.9%

2022 22,217 153 0.7 22,618 125 0.6 -402 -1.8%

2023 22,376 159 0.7 22,748 130 0.6 -373 -1.6%

2024 22,536 160 0.7 22,876 128 0.6 -340 -1.5%

2025 22,694 157 0.7 23,001 125 0.5 -308 -1.3%

2026 22,838 145 0.6 23,147 146 0.6 -309 -1.3%

2027 23,037 198 0.9 23,333 185 0.8 -296 -1.3%

 HISTORY AVERAGE ANNUAL GROWTH

SPRING 2012 FORECAST SPRING 2011 FORECAST

Growth Growth

16,000

20,000

24,000

28,000

32,000

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

GWH

Year

History Spring 2011 Forecast Spring 2012 Forecast
125 

(Load Forecast Pg 11) 

Textile Billed Sales (After EE Subtracted)

 

Year Actual Growth GWH %

GWH GWH % Per Year Per Year

2002 8,443 -382 -4.3

2003 7,562 -881 -10.4

2004 7,147 -415 -5.5

2005 6,561 -586 -8.2

2006 5,791 -770 -11.7

2007 5,224 -567 -9.8 History (2006 to 2011) -362 -7.2

2008 4,524 -700 -13.4 History (1996 to 2011) -508 -6.9

2009 3,616 -908 -20.1 

2010 4,003 387 10.7 Spring 2012 Forecast (2011 to 2027) -44 -1.2

2011 3,983 -20 -0.5 Spring 2011 Forecast (2011 to 2027) -36 -1.0

SPRING 2012 vs SPRING 2011

 

 

Year GWH GWH % GWH GWH % GWH %

2012 3,871 -112 -2.8 4,159 176 1.0 -288 -6.9%

2013 3,809 -61 -1.6 4,125 -33 -0.8 -316 -7.7%

2014 3,750 -60 -1.6 4,068 -57 -1.4 -318 -7.8%

2015 3,694 -55 -1.5 4,011 -57 -1.4 -316 -7.9%

2016 3,647 -47 -1.3 3,953 -57 -1.4 -306 -7.7%

2017 3,601 -46 -1.3 3,900 -54 -1.4 -298 -7.7%

2018 3,560 -42 -1.2 3,845 -54 -1.4 -286 -7.4%

2019 3,519 -41 -1.1 3,790 -55 -1.4 -271 -7.2%

2020 3,484 -35 -1.0 3,739 -51 -1.3 -255 -6.8%

2021 3,447 -38 -1.1 3,689 -51 -1.4 -242 -6.6%

2022 3,410 -37 -1.1 3,638 -51 -1.4 -228 -6.3%

2023 3,378 -32 -0.9 3,588 -50 -1.4 -210 -5.9%

2024 3,348 -30 -0.9 3,539 -49 -1.4 -191 -5.4%

2025 3,319 -29 -0.9 3,491 -48 -1.4 -171 -4.9%

2026 3,282 -37 -1.1 3,445 -45 -1.3 -164 -4.7%

2027 3,286 4 0.1 3,407 -39 -1.1 -121 -3.6%

 HISTORY AVERAGE ANNUAL GROWTH

SPRING 2012 FORECAST SPRING 2011 FORECAST

Growth Growth

1,000

5,000

9,000

13,000

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

GWH

Year

History Spring 2011 Forecast Spring 2012 Forecast
126 

(Load Forecast Pg 12) 

Other Industrial Billed Sales (Aftr EE Subtracted)

 

 

Year Actual Growth GWH %

GWH GWH % Per Year Per Year

2002 17,816 -261 -1.4

2003 17,202 -614 -3.4

2004 18,063 861 5.0

2005 18,934 872 4.8

2006 18,744 -191 -1.0

2007 18,724 -20 -0.1 History (2006 to 2011) -389 -2.2

2008 18,110 -614 -3.3 History (1996 to 2011) -89 -0.5

2009 15,588 -2,522 -13.9 

2010 16,616 1,028 6.6 Spring 2012 Forecast (2011 to 2027) 184 1.0

2011 16,800 184 1.1 Spring 2011 Forecast (2011 to 2027) 195 1.1

SPRING 2012 vs SPRING 2011

 

 

Year GWH GWH % GWH GWH % GWH %

2012 16,894 94 0.6 17,216 416 1.0 -321 -1.9%

2013 17,054 160 0.9 17,474 259 1.5 -420 -2.4%

2014 17,266 212 1.2 17,702 228 1.3 -436 -2.5%

2015 17,474 208 1.2 17,860 158 0.9 -385 -2.2%

2016 17,669 195 1.1 18,010 150 0.8 -341 -1.9%

2017 17,857 188 1.1 18,159 150 0.8 -302 -1.7%

2018 18,045 188 1.1 18,314 154 0.8 -269 -1.5%

2019 18,236 191 1.1 18,473 159 0.9 -237 -1.3%

2020 18,427 191 1.0 18,635 162 0.9 -209 -1.1%

2021 18,617 191 1.0 18,805 169 0.9 -187 -1.0%

2022 18,807 190 1.0 18,981 176 0.9 -173 -0.9%

2023 18,998 191 1.0 19,160 180 0.9 -163 -0.8%

2024 19,188 190 1.0 19,337 177 0.9 -149 -0.8%

2025 19,374 186 1.0 19,510 173 0.9 -136 -0.7%

2026 19,556 182 0.9 19,702 192 1.0 -146 -0.7%

2027 19,751 194 1.0 19,926 224 1.1 -175 -0.9%

 HISTORY AVERAGE ANNUAL GROWTH

SPRING 2012 FORECAST SPRING 2011 FORECAST

Growth Growth

12,000

16,000

20,000

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

GWH

Year

History Spring 2011 Forecast Spring 2012 Forecast
127 

(Load Forecast Pg 13) 

Other Retail Billed Sales (Sum of PL, TS and Interdeptmental)

 

 

Year Actual Growth GWH %

GWH GWH % Per Year Per Year

2007 278 6 2.4 History (2006 to 2011) 3 1.1

2008 284 6 2.2 History (1996 to 2011) 2 0.8

2009 287 3 0.9 

2010 287 1 0.2 Spring 2012 Forecast (2011 to 2027) 5 1.5

2011 287 0 -0.1 Spring 2011 Forecast (2011 to 2027) 5 1.6

SPRING 2012 vs SPRING 2011

 

 

Year GWH GWH % GWH GWH % GWH %

2012 288 1 0.5 293 6 1.0 -4 -1.5%

2013 292 3 1.2 297 5 1.6 -6 -1.9%

2014 296 5 1.6 302 5 1.6 -6 -1.9%

2015 301 5 1.6 306 4 1.4 -5 -1.7%

2016 305 4 1.4 310 4 1.4 -5 -1.7%

2017 309 4 1.4 315 4 1.4 -5 -1.7%

2018 314 4 1.4 319 4 1.4 -5 -1.7%

2019 318 4 1.4 324 5 1.5 -6 -1.8%

2020 323 5 1.5 329 5 1.5 -6 -1.8%

2021 328 5 1.5 334 5 1.5 -6 -1.8%

2022 333 5 1.6 340 5 1.6 -6 -1.9%

2023 339 5 1.6 346 6 1.7 -7 -2.0%

2024 345 6 1.7 352 6 1.8 -7 -2.0%

2025 351 6 1.8 358 6 1.8 -7 -2.0%

2026 357 6 1.8 364 6 1.8 -7 -2.0%

2027 363 6 1.8 371 7 1.8 -8 -2.0%

SPRING 2012 FORECAST

 HISTORY AVERAGE ANNUAL GROWTH

Growth

SPRING 2011 FORECAST

Growth

190

210

230

250

270

290

310

330

350

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

GWH

Year

History Spring 2011 Forecast Spring 2012 Forecast
128 

(Load Forecast Pg 14) 

Retail Billed Sales (After EE Subtracted)

 

Year Actual Growth GWH %

GWH GWH % Per Year Per Year

2007 79,118 2,466 3.2 History (2006 to 2011) 67 0.1

2008 77,541 -1,577 -2.0 History (1996 to 2011) 395 0.5

2009 73,740 -3,801 -4.9 

2010 78,922 5,182 7.0 Spring 2012 Forecast (2011 to 2027) 1011 1.2

2011 76,985 -1,937 -2.5 Spring 2011 Forecast (2011 to 2027) 1224 1.4

SPRING 2012 vs SPRING 2011

 

 

Year GWH GWH % GWH GWH % GWH %

2012 75,367 -1,618 -2.1 77,175 190 1.0 -1,809 -2.3%

2013 76,033 666 0.9 78,210 1,035 1.3 -2,178 -2.8%

2014 77,130 1,098 1.4 79,453 1,242 1.6 -2,322 -2.9%

2015 78,315 1,185 1.5 80,595 1,142 1.4 -2,279 -2.8%

2016 79,514 1,199 1.5 81,709 1,114 1.4 -2,194 -2.7%

2017 80,662 1,147 1.4 82,835 1,126 1.4 -2,173 -2.6%

2018 81,822 1,160 1.4 84,011 1,176 1.4 -2,189 -2.6%

2019 82,983 1,161 1.4 85,214 1,204 1.4 -2,232 -2.6%

2020 84,176 1,194 1.4 86,445 1,230 1.4 -2,268 -2.6%

2021 85,390 1,213 1.4 87,682 1,237 1.4 -2,292 -2.6%

2022 86,618 1,228 1.4 89,033 1,352 1.5 -2,416 -2.7%

2023 87,852 1,234 1.4 90,477 1,443 1.6 -2,625 -2.9%

2024 89,096 1,244 1.4 91,959 1,482 1.6 -2,862 -3.1%

2025 90,406 1,310 1.5 93,452 1,493 1.6 -3,046 -3.3%

2026 91,740 1,334 1.5 94,994 1,542 1.7 -3,253 -3.4%

2027 93,158 1,417 1.5 96,576 1,582 1.7 -3,418 -3.5%

SPRING 2012 FORECAST

 HISTORY AVERAGE ANNUAL GROWTH

Growth

SPRING 2011 FORECAST

Growth

60,000

70,000

80,000

90,000

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

GWH

Year

History Spring 2011 Forecast Spring 2012 Forecast
129 

(Load Forecast Pg 15) 

Full / Partial Requirements Wholesale Billed Sales 1

 

 

Year Actual Growth GWH %

GWH GWH % Per Year Per Year

2002 1,530 47 3.1

2003 1,448 -82 -5.4

2004 1,542 93 6.4

2005 1,580 38 2.5

2006 1,694 114 7.2

2007 2,454 760 44.8 History (2006 to 2011) 634 23.5

2008 3,525 1,072 43.7 History (1996 to 2011) 219 7.8

2009 3,788 262 7.4 

2010 5,166 1,379 36.4 Spring 2012 Forecast (2011 to 2027) 369 5.1

2011 4,866 -300 -5.8 Spring 2011 Forecast (2011 to 2027) 407 5.5

SPRING 2012 vs SPRING 2011

 

 

Year GWH GWH % GWH GWH % GWH %

2012 4,763 -103 -2.1 5,098 232 1.0 -335 -6.6%

2013 5,473 710 14.9 5,829 731 14.3 -356 -6.1%

2014 6,092 619 11.3 6,478 648 11.1 -385 -5.9%

2015 6,757 665 10.9 7,157 679 10.5 -400 -5.6%

2016 7,425 668 9.9 7,862 705 9.8 -437 -5.6%

2017 8,117 692 9.3 8,592 730 9.3 -475 -5.5%

2018 8,833 716 8.8 9,353 761 8.9 -521 -5.6%

2019 9,377 544 6.2 9,932 579 6.2 -555 -5.6%

2020 9,543 167 1.8 10,101 169 1.7 -557 -5.5%

2021 9,709 165 1.7 10,268 168 1.7 -560 -5.5%

2022 9,880 171 1.8 10,446 177 1.7 -566 -5.4%

2023 10,051 171 1.7 10,628 182 1.7 -577 -5.4%

2024 10,226 176 1.7 10,816 188 1.8 -590 -5.5%

2025 10,404 177 1.7 11,002 186 1.7 -599 -5.4%

2026 10,586 183 1.8 11,195 192 1.7 -608 -5.4%

2027 10,773 186 1.8 11,384 189 1.7 -611 -5.4%

1 Does not include SEPA allocation. 

 HISTORY AVERAGE ANNUAL GROWTH

SPRING 2012 FORECAST SPRING 2011 FORECAST

Growth Growth

1,000

5,000

9,000

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

GWH

Year

History Spring 2011 Forecast Spring 2012 Forecast
130 

(Load Forecast Pg 16) Number of Rates Billed
131 

(Load Forecast Pg 17) 

Total Rates Billed

(Sum of Major Retail Classes: Residential, Commercial and Industrial)

 

 

Year Actual Growth Rates Billed %

Rates Billed Rates Billed % Per Year Per Year

2002 2,148,117 30,685 1.4

2003 2,186,825 38,708 1.8

2004 2,221,590 34,766 1.6

2005 2,261,639 40,049 1.8

2006 2,304,050 42,411 1.9

2007 2,354,078 50,028 2.2 History (2006 to 2011) 24,064 1.0

2008 2,393,426 39,348 1.7 History (1996 to 2011) 37,416 1.8

2009 2,399,359 5,933 0.2 

2010 2,413,085 13,727 0.6 Spring 2012 Forecast (2011 to 2027) 31,347 1.2

2011 2,424,368 11,283 0.5 Spring 2011 Forecast (2011 to 2027) -151,523 -100.0

SPRING 2012 vs SPRING 2011

 

 Growth

Year Rates Billed Rates Billed % Rates Billed Rates Billed % Rates Billed %

2012 2,438,779 14,411 0.6 2,461,853 37,485 1.0 -23,074 -0.9%

2013 2,461,153 22,374 0.9 2,500,751 38,899 1.6 -39,599 -1.6%

2014 2,490,608 29,455 1.2 2,539,624 38,872 1.6 -49,016 -1.9%

2015 2,525,184 34,576 1.4 2,577,453 37,829 1.5 -52,269 -2.0%

2016 2,559,552 34,369 1.4 2,614,490 37,037 1.4 -54,937 -2.1%

2017 2,593,628 34,076 1.3 2,651,397 36,907 1.4 -57,769 -2.2%

2018 2,627,486 33,858 1.3 2,688,220 36,823 1.4 -60,734 -2.3%

2019 2,660,526 33,040 1.3 2,724,824 36,604 1.4 -64,298 -2.4%

2020 2,693,885 33,359 1.3 2,761,410 36,586 1.3 -67,525 -2.4%

2021 2,727,342 33,457 1.2 2,798,003 36,593 1.3 -70,661 -2.5%

2022 2,760,168 32,825 1.2 2,834,602 36,599 1.3 -74,434 -2.6%

2023 2,792,602 32,434 1.2 2,871,206 36,604 1.3 -78,604 -2.7%

2024 2,825,550 32,948 1.2 2,907,812 36,606 1.3 -82,262 -2.8%

2025 2,858,888 33,338 1.2 2,944,418 36,606 1.3 -85,530 -2.9%

2026 2,892,410 33,522 1.2 2,980,922 36,504 1.2 -88,512 -3.0%

2027 2,925,912 33,503 1.2

SPRING 2012 FORECAST

 HISTORY AVERAGE ANNUAL GROWTH

SPRING 2011 FORECAST

Growth

1,500,000

1,700,000

1,900,000

2,100,000

2,300,000

2,500,000

2,700,000

2,900,000

3,100,000

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

Rates Billed

Year

History Spring 2011 Forecast Spring 2012 Forecast
132 

(Load Forecast Pg 18) 

Residential Rates Billed 

 

 

Year Actual Growth Rates Billed %

Rates Billed Rates Billed % Per Year Per Year

2002 1,839,689 25,822 1.4

2003 1,872,484 32,795 1.8

2004 1,901,335 28,851 1.5

2005 1,935,320 33,985 1.8

2006 1,971,673 36,353 1.9

2007 2,016,104 44,431 2.3 History (2006 to 2011) 21,901 1.1

2008 2,052,252 36,149 1.8 History (1996 to 2011) 32,184 1.8

2009 2,059,394 7,142 0.3 

2010 2,071,877 12,484 0.6 Spring 2012 Forecast (2011 to 2027) 26,168 1.2

2011 2,081,179 9,302 0.4 Spring 2011 Forecast (2011 to 2027) 31,234 1.4

SPRING 2012 vs SPRING 2011

 

 Growth

Year Rates Billed Rates Billed % Rates Billed Rates Billed % Rates Billed %

2012 2,091,635 10,456 0.5 2,111,339 30,161 1.0 -19,705 -0.9%

2013 2,108,208 16,573 0.8 2,144,532 33,193 1.6 -36,324 -1.7%

2014 2,131,555 23,347 1.1 2,177,288 32,756 1.5 -45,733 -2.1%

2015 2,160,074 28,519 1.3 2,209,204 31,915 1.5 -49,129 -2.2%

2016 2,188,612 28,537 1.3 2,240,467 31,263 1.4 -51,855 -2.3%

2017 2,217,078 28,466 1.3 2,271,658 31,192 1.4 -54,581 -2.4%

2018 2,245,525 28,447 1.3 2,302,781 31,122 1.4 -57,256 -2.5%

2019 2,273,922 28,398 1.3 2,333,700 30,919 1.3 -59,777 -2.6%

2020 2,302,301 28,378 1.2 2,364,617 30,918 1.3 -62,316 -2.6%

2021 2,330,644 28,343 1.2 2,395,539 30,922 1.3 -64,895 -2.7%

2022 2,358,961 28,317 1.2 2,426,465 30,925 1.3 -67,503 -2.8%

2023 2,387,255 28,294 1.2 2,457,395 30,931 1.3 -70,140 -2.9%

2024 2,415,522 28,267 1.2 2,488,332 30,937 1.3 -72,810 -2.9%

2025 2,443,766 28,243 1.2 2,519,270 30,939 1.2 -75,505 -3.0%

2026 2,471,824 28,059 1.1 2,550,110 30,840 1.2 -78,286 -3.1%

2027 2,499,864 28,040 1.1

SPRING 2012 FORECAST

 HISTORY AVERAGE ANNUAL GROWTH

SPRING 2011 FORECAST

Growth

1,300,000

1,500,000

1,700,000

1,900,000

2,100,000

2,300,000

2,500,000

2,700,000

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

Rates Billed

Year

History Spring 2011 Forecast Spring 2012 Forecast
133 

(Load Forecast Pg 19) 

Commercial Rates Billed 

 

 

Year Actual Growth Rates Billed %

Rates Billed Rates Billed % Per Year Per Year

2002 300,440 5,140 1.7

2003 306,540 6,101 2.0

2004 312,665 6,125 2.0

2005 318,827 6,162 2.0

2006 324,977 6,150 1.9

2007 330,666 5,689 1.8 History (2006 to 2011) 2,224 0.7

2008 333,873 3,208 1.0 History (1996 to 2011) 5,337 1.8

2009 332,593 -1,280 -0.4 

2010 333,960 1,367 0.4 Spring 2012 Forecast (2011 to 2027) 5,197 1.4

2011 336,099 2,139 0.6 Spring 2011 Forecast (2011 to 2027) 5,844 1.5

SPRING 2012 vs SPRING 2011

 

 Growth

Year Rates Billed Rates Billed % Rates Billed Rates Billed % Rates Billed %

2011 340,127 4,028 1.2 343,384 7,285 1.0 -3,257 -0.9%

2013 345,925 5,798 1.7 349,077 5,693 1.7 -3,152 -0.9%

2014 352,020 6,095 1.8 355,189 6,112 1.8 -3,170 -0.9%

2015 358,086 6,066 1.7 361,123 5,934 1.7 -3,038 -0.8%

2016 363,933 5,847 1.6 366,919 5,795 1.6 -2,986 -0.8%

2017 369,567 5,634 1.5 372,660 5,741 1.6 -3,093 -0.8%

2018 374,999 5,433 1.5 378,382 5,722 1.5 -3,383 -0.9%

2019 379,662 4,663 1.2 384,087 5,705 1.5 -4,425 -1.2%

2020 384,665 5,003 1.3 389,777 5,690 1.5 -5,111 -1.3%

2021 389,801 5,135 1.3 395,466 5,690 1.5 -5,666 -1.4%

2022 394,329 4,528 1.2 401,157 5,690 1.4 -6,828 -1.7%

2023 398,492 4,163 1.1 406,848 5,691 1.4 -8,356 -2.1%

2024 403,203 4,711 1.2 412,539 5,692 1.4 -9,336 -2.3%

2025 408,322 5,118 1.3 418,232 5,693 1.4 -9,911 -2.4%

2026 413,784 5,463 1.3 423,917 5,685 1.4 -10,133 -2.4%

2027 419,247 5,463 1.3

 HISTORY AVERAGE ANNUAL GROWTH

SPRING 2012 FORECAST SPRING 2011 FORECAST

Growth

220,000

270,000

320,000

370,000

420,000

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

Rates Billed

Year

History Fall 2011 Spring 2012
134 

(Load Forecast Pg 20) 

Total Industrial Rates Billed (Includes Textile and Other Industrial)

 

 

Year Actual Growth Rates Billed %

Rates Billed Rates Billed % Per Year Per Year

2002 7,989 -276 -3.3

2003 7,801 -188 -2.3

2004 7,591 -210 -2.7

2005 7,492 -99 -1.3

2006 7,401 -91 -1.2

2007 7,309 -92 -1.2 History (2006 to 2011) -62 -0.9

2008 7,301 -8 -0.1 History (1996 to 2011) -105 -1.3

2009 7,372 71 1.0 

2010 7,248 -124 -1.7 Spring 2012 Forecast (2011 to 2027) -18 -0.3

2011 7,090 -158 -2.2 Spring 2011 Forecast (2011 to 2027) -443 -100.0

SPRING 2012 vs SPRING 2011

 

 Growth

Year Rates Billed Rates Billed % Rates Billed Rates Billed % Rates Billed %

2012 7,017 -73 -1.0 7,130 39 1.0 -112 -1.6%

2013 7,020 3 0.0 7,143 13 0.2 -123 -1.7%

2014 7,033 13 0.2 7,146 3 0.0 -114 -1.6%

2015 7,024 -9 -0.1 7,126 -20 -0.3 -102 -1.4%

2016 7,008 -16 -0.2 7,104 -22 -0.3 -97 -1.4%

2017 6,984 -24 -0.3 7,079 -26 -0.4 -95 -1.3%

2018 6,962 -22 -0.3 7,057 -21 -0.3 -95 -1.3%

2019 6,942 -21 -0.3 7,037 -20 -0.3 -96 -1.4%

2020 6,919 -23 -0.3 7,016 -21 -0.3 -97 -1.4%

2021 6,897 -21 -0.3 6,997 -19 -0.3 -100 -1.4%

2022 6,878 -20 -0.3 6,981 -17 -0.2 -103 -1.5%

2023 6,855 -23 -0.3 6,963 -18 -0.3 -108 -1.6%

2024 6,825 -30 -0.4 6,941 -22 -0.3 -116 -1.7%

2025 6,801 -24 -0.4 6,915 -26 -0.4 -114 -1.7%

2026 6,801 0 0.0 6,894 -22 -0.3 -93 -1.3%

2027 6,801 0 0.0

SPRING 2012 FORECAST

 HISTORY AVERAGE ANNUAL GROWTH

SPRING 2011 FORECAST

Growth

6,200

6,600

7,000

7,400

7,800

8,200

8,600

9,000

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

Rates Billed

Year

History Spring 2011 Forecast Spring 2012 Forecast
135 

(Load Forecast Pg 21) 

Textile Rates Billed 

 

 

Year Actual Growth Rates Billed %

Rates Billed Rates Billed % Per Year Per Year

2002 949 -103 -9.8

2003 914 -35 -3.6

2004 857 -57 -6.2

2005 802 -56 -6.5

2006 757 -45 -5.6

2007 728 -29 -3.8 History (2006 to 2011) -37 -5.5

2008 675 -53 -7.3 History (1996 to 2011) -52 -5.6

2009 649 -26 -3.9 

2010 622 -27 -4.2 Spring 2012 Forecast (2011 to 2027) -4 -0.7

2011 572 -50 -8.1 Spring 2011 Forecast (2011 to 2027) 0 0.0

SPRING 2012 vs SPRING 2011

 

 Growth

Year Rates Billed Rates Billed % Rates Billed Rates Billed % Rates Billed %

2011 543 -29 -5.0 621 49 1.1 -78 -12.5%

2013 535 -8 -1.5 618 -2 -0.4 -83 -13.5%

2014 529 -6 -1.1 616 -2 -0.4 -87 -14.1%

2015 524 -5 -0.9 613 -3 -0.5 -89 -14.5%

2016 518 -6 -1.2 609 -4 -0.6 -91 -14.9%

2017 514 -4 -0.7 606 -3 -0.6 -91 -15.1%

2018 511 -4 -0.8 602 -3 -0.6 -92 -15.2%

2019 508 -2 -0.5 599 -4 -0.6 -91 -15.1%

2020 508 0 -0.1 595 -3 -0.6 -87 -14.7%

2021 507 -1 -0.2 592 -3 -0.6 -85 -14.4%

2022 506 -1 -0.1 588 -4 -0.6 -82 -14.0%

2023 507 0 0.1 585 -4 -0.7 -78 -13.3%

2024 505 -2 -0.3 581 -4 -0.7 -76 -13.0%

2025 504 -1 -0.2 576 -5 -0.8 -72 -12.5%

2026 506 1 0.3 573 -3 -0.6 -67 -11.7%

2027 507 1 0.3

 HISTORY AVERAGE ANNUAL GROWTH

SPRING 2012 FORECAST SPRING 2011 FORECAST

Growth

300

500

700

900

1,100

1,300

1,500

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

Rates Billed

Year

History Fall 2010 Forecast Spring 2011 Forecast
136 

(Load Forecast Pg 22) 

Other Industrial Rates Billed 

 

 

Year Actual Growth Rates Billed %

Rates Billed Rates Billed % Per Year Per Year

2002 7,040 -173 -2.4

2003 6,887 -153 -2.2

2004 6,733 -154 -2.2

2005 6,690 -43 -0.6

2006 6,644 -47 -0.7

2007 6,581 -63 -0.9 History (2006 to 2011) -25 -0.4

2008 6,626 45 0.7 History (1996 to 2011) -53 -0.8

2009 6,723 97 1.5 

2010 6,626 -97 -1.4 Spring 2012 Forecast (2011 to 2027) -14 -0.2

2011 6,518 -108 -1.6 Spring 2011 Forecast (2011 to 2027) -13 -0.2

SPRING 2012 vs SPRING 2011

 

 Growth

Year Rates Billed Rates Billed % Rates Billed Rates Billed % Rates Billed %

2012 6,474 -44 -0.7 6,509 -9 1.0 -34 -0.5%

2013 6,485 10 0.2 6,524 15 0.2 -39 -0.6%

2014 6,503 19 0.3 6,530 6 0.1 -27 -0.4%

2015 6,499 -4 -0.1 6,513 -17 -0.3 -14 -0.2%

2016 6,490 -10 -0.1 6,495 -18 -0.3 -6 -0.1%

2017 6,470 -20 -0.3 6,473 -22 -0.3 -3 -0.1%

2018 6,452 -18 -0.3 6,455 -18 -0.3 -3 -0.1%

2019 6,433 -18 -0.3 6,438 -17 -0.3 -5 -0.1%

2020 6,411 -23 -0.4 6,420 -18 -0.3 -10 -0.2%

2021 6,391 -20 -0.3 6,405 -15 -0.2 -15 -0.2%

2022 6,371 -19 -0.3 6,392 -13 -0.2 -21 -0.3%

2023 6,348 -23 -0.4 6,378 -14 -0.2 -30 -0.5%

2024 6,320 -28 -0.4 6,360 -18 -0.3 -40 -0.6%

2025 6,297 -23 -0.4 6,339 -21 -0.3 -42 -0.7%

2026 6,295 -1 0.0 6,321 -18 -0.3 -26 -0.4%

2027 6,294 -1 0.0 6,303 -9 -0.1 -18

SPRING 2012 FORECAST

 HISTORY AVERAGE ANNUAL GROWTH

SPRING 2011 FORECAST

Growth

6,000

6,200

6,400

6,600

6,800

7,000

7,200

7,400

7,600

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023

Rates Billed

Year

History Spring 2011 Forecast Spring 2012 Forecast
137 

(Load Forecast Pg 23) System Peaks
138 

(Load Forecast Pg 24) 

The Summer peak forecast represents the maximum demand during the summer season 

Summer Peak

on the Duke Energy Carolinas system. The Summer Peak Forecast includes all load 

that Duke Energy Carolinas is contractually obligated to serve and is used in the 

Integrated Resource Plan. It includes all Retail classes, Wholesale, Company Use and 

is at generation. 

The forecast reflects Duke Energy Carolinas energy efficiency programs as well as 

adjustments for the expected growth in Plug-in Hybrid Electric Vehicles (PHEV) and 

the proposed ban on incandescent lighting. The Spring 2012 Forecast also reflects the 

impacts of expected growth in solar energy. 

Thus, the Summer Peak forecast shown is after all adjustments.

Growth Forecasts

The new forecast projects an incremental growth of 338 MW or 1.7% per year for 

2011-2027. The previous forecast growth was 353 MW or 1.8% per year for 2011-

2027.
139 

(Load Forecast Pg 25) 

Native Load Summer MW (After EE Subtracted)

 

 WEATHER NORMAL

 

Year MW % Actual

MW MW % Per Year Per Year MW

2005 17,497 16,399 

2006 17,439 -58 -0.3 18,255 

2007 17,698 259 1.5 History (2006 to 2011) 4 0.0 17,474 

2008 17,670 -28 -0.2 History (1996 to 2011) 120 0.7 18,292 

2009 17,100 -570 -3.2 17,760 

2010 17,088 -12 -0.1 Spring 2012 Forecast (2011 to 2027) 338 1.7 17,358 

2011 17,457 369 2.2 Spring 2011 Forecast (2011 to 2027) 353 1.8 17,772 

SPRING 2012 vs SPRING 2011

 

 

Year MW MW % MW MW % MW %

2012 17,716 259 1.5 17,812 355 1.0 -96 -0.5%

2013 18,043 327 1.8 18,245 433 2.4 -202 -1.1%

2014 18,437 393 2.2 18,680 435 2.4 -243 -1.3%

2015 18,795 358 1.9 19,032 352 1.9 -237 -1.2%

2016 19,239 444 2.4 19,476 444 2.3 -237 -1.2%

2017 19,630 391 2.0 19,877 401 2.1 -247 -1.2%

2018 20,002 372 1.9 20,265 388 2.0 -263 -1.3%

2019 20,379 377 1.9 20,644 379 1.9 -265 -1.3%

2020 20,638 259 1.3 20,901 257 1.2 -263 -1.3%

2021 20,967 328 1.6 21,214 313 1.5 -247 -1.2%

2022 21,268 301 1.4 21,530 316 1.5 -262 -1.2%

2023 21,577 309 1.5 21,836 306 1.4 -259 -1.2%

2024 21,888 311 1.4 22,135 299 1.4 -247 -1.1%

2025 22,219 331 1.5 22,465 330 1.5 -245 -1.1%

2026 22,499 279 1.3 22,733 268 1.2 -234 -1.0%

2027 22,871 372 1.7 23,099 366 1.6 -228 -1.0%

SPRING 2012 FORECAST

 HISTORY AVERAGE ANNUAL GROWTH

Growth

SPRING 2011 FORECAST

Growth

Growth

13,000

15,000

17,000

19,000

21,000

23,000

1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025

MW

Year

WN History Spring 2011 Forecast Spring 2012 Forecast Actual History
140 

(Load Forecast Pg 26) 

The Winter peak forecast represents the maximum demand during the winter 

Winter Peak

season on the Duke Energy Carolinas' system. The Winter Peak Forecast includes

all load that Duke Energy Carolinas is contractually obligated to serve and is used in 

the Integrated Resource Plan. It includes all Retail classes, Wholesale, Company 

Use and is at generation.

The forecast reflects Duke Energy Carolinas sponsored energy efficiency 

programs as well as adjustments for the expected growth in Plug-in Hybrid Electric 

Vehicles (PHEV) and the proposed ban on incandescent lighting. The Spring 2012 

Forecast also reflects the impacts of expected growth in solar energy.

Thus, the Winter Peak forecast shown is after all adjustments.

Growth Forecasts

The new Forecast projects an incremental growth of 326 MW or 1.7% per year from 

2011-2027. The previous forecast growth was 336 MW or 1.8% per year from 

2011-2027. 
141 

(Load Forecast Pg 27) 

System Winter MW (After EE Subtracted)

 

 WEATHER NORMAL

 

Year MW %

MW MW % Per Year Per Year

2002 14,565 -506 -3.4

2003 14,626 61 0.4

2004 14,770 144 1.0

2005 15,568 798 5.4

2006 15,193 -375 -2.4

2007 15,936 742 4.9 History (2006 to 2011) 316 2.0

2008 16,065 130 0.8 History (2000 to 2011) 199 1.3

2009 16,723 657 4.1 

2010 16,893 170 1.0 Spring 2012 Forecast (2011 to 2027) 326 1.7

2011 16,774 -119 -0.7 Spring 2011 Forecast (2011 to 2027) 336 1.8

SPRING 2012 vs SPRING 2011

 

 

Year MW MW % MW MW % MW %

2012 17,069 295 1.8 17,348 574 1.0 -279 -1.6%

2013 17,383 314 1.8 17,695 347 2.0 -311 -1.8%

2014 17,759 375 2.2 18,044 350 2.0 -286 -1.6%

2015 18,130 372 2.1 18,388 343 1.9 -257 -1.4%

2016 18,526 395 2.2 18,790 402 2.2 -264 -1.4%

2017 18,921 395 2.1 19,201 411 2.2 -280 -1.5%

2018 19,303 382 2.0 19,608 407 2.1 -305 -1.6%

2019 19,677 374 1.9 19,985 377 1.9 -309 -1.5%

2020 19,985 309 1.6 20,279 294 1.5 -294 -1.4%

2021 20,197 211 1.1 20,476 197 1.0 -279 -1.4%

2022 20,546 349 1.7 20,831 355 1.7 -285 -1.4%

2023 20,828 282 1.4 21,101 271 1.3 -273 -1.3%

2024 21,117 289 1.4 21,386 284 1.3 -268 -1.3%

2025 21,446 328 1.6 21,679 293 1.4 -233 -1.1%

2026 21,706 260 1.2 21,920 241 1.1 -214 -1.0%

2027 21,994 289 1.3 22,148 228 1.0 -153 -0.7%

Growth

SPRING 2012 FORECAST

 HISTORY AVERAGE ANNUAL GROWTH

SPRING 2011 FORECAST

Growth

Growth

12,000

14,000

16,000

18,000

20,000

22,000

24,000

2000 2003 2006 2009 2012 2015 2018 2021 2024 2027

MW

Year

TC History Spring 2011 Forecast Spring 2012 Forecast
142 

(Load Forecast Pg 28) 

Summer Load Factor (After EE Subtracted)

SPRING 2012 SPRING 2011

Year Load Factor Load Factor

2012 58.3 59.4 

2013 58.0 59.1 

2014 57.9 59.0 

2015 58.0 59.1 

2016 57.8 58.9 

2017 57.8 58.8 

2018 57.9 58.9 

2019 57.8 58.8 

2020 57.9 59.0 

2021 57.8 58.9 

2022 57.7 58.9 

2023 57.7 59.0 

2024 57.7 59.1 

2025 57.6 59.1 

2026 57.7 59.4 

2027 57.6 59.3 

The Load factor below is based on the IRP load. The system load factor represents the 

relationship between annual energy and the maximum demand for the Duke Energy Carolinas' 

system. It is measured at generation level and is reflects sales and peaks after all EE, EV and 

PV programs have been subtracted..

Load Factor

56.5 

57.0 

57.5 

58.0 

58.5 

59.0 

59.5 

60.0 

SPRING 2012 SPRING 2011
143 

Load Definitions The following table shows differences in the load forecasts that are utilized for various Company and regulatory documents, reports, 

LOAD TYPES/

LOAD COMPONENTS

BALANCING 

AUTHORITY IRP RPO FERC FORM1 SERC

LOAD 

FORECAST 

BOOK

REGULAR 

BILLED 

SALES 

RETAIL X X X X X X X 

S10A - CONCORD X X X X X X X 

S10A - DALLAS X X X X X X X 

S10A - KINGS MOUNTAIN X X X X X X X 

S10A - FOREST CITY X X X X X X X 

S10A - DUE WEST X X X X X X X 

S10A - PROSPERITY X X X X X X X 

S10A - LOCKHART X X X X X X X 

WESTERN CAROLINA UNIVERSTIY X X X X X X X 

HIGHLAND X X X X X X X 

GREENWOOD X X X X X X 

SENECA X 

SCEG X 

PIEDMONT EMC X X X X

BLUE RIDGE EMC X X X X

RUTHERFORD EMC X X X X

HAYWOOD EMC X X X X

NCEMC TOTAL X X NCMPA TOTAL X X 

PMPA TOTAL X X 

SALUDA RIVER TOTAL X 

NCEMC OWNERSHIP OF CATAWBA 

NET OF PBRH CATAWBA

(630-98-3) X X

NCEMC FIXED LOAD SHAPE X X X

NEW HORIZON STEP-UP CONTRACT X (Start in 2013) X (Start in 2013) X (Start in 2013) X (Start in 2013) X (Start in 2013) X (Start in 2013

LINE LOSSES X X X X X X 

UNBILLED X X X X X X 

COMPANY USE X X X X X X 

Notes:1. Changes from 2011 definition 1) NCEMC's ownership reduced from 682 to 630 because they are moving 52 MWs of their entitlement to PJM (

 2) Remove 432 NCMPA entitlement, backstand agreement ends Dec 31, 2011

2. Greenwood became part of Duke's native load for IRP and RPO beginning Jan 1st 2010. 3. Seneca was added to Balancing Authority load on July 14 2010 @ HE 1000. 4. The loss multiplier to convert meter load to generation is 1.03092783505155 5. New Horizon co-ops include Little River EC, Blue Ridge EC, Broad River EC, York EC and Laurens EC.This table serves a reference for developing forecast for various load definitions. Because historical load for definitions are derived from the balancing autority load, please refers to the Load Calculation page for the eq

come up with historical load actuals. 

6. Balancing Authority load is an all-in load, meaning it includes loads from loads supplied by sources other generation (SEPA and BTM). The engineering definition of BA load is: Sum of Duke's Generation + Load FlowFlowing Out
144 

APPENDIX C: SUPPLY-SIDE SCREENING 

The following sets of estimated Levelized Busbar Cost8

 charts provide an economic 

comparison of the technologies in their respective categories. Despite the usefulness of 

levelized busbar cost comparisons, comparisons involving some renewable resources, 

particularly wind and solar resources, can be somewhat misleading because these 

resources do not contribute their full installed capacity at the time of the system peak9. 

Since busbar charts attempt to levelize and compare costs on an installed kW basis, wind 

and solar resources appear to be more economical than they would be if the comparison 

was performed on a peak kW basis. The Renewables Busbar Chart shows a single point 

for each type of resource at the particular capacity factor specified. 

Base load

The following technologies are found on the base load technologies screening chart: 

1) 2 x 1,117 MW Nuclear 

2) 825 MW Supercritical Coal with Carbon Capture and Sequestration at 60% 

3) 618 MW IGCC with Carbon Capture and Sequestration at 55% 

4) 700 MW – 2x2x1 Combined Cycle (Inlet Chiller and Duct Fired) 

8

 While these estimated levelized busbar costs provide a reasonable basis for initial screening of 

technologies, simple busbar cost information has limitations. In isolation, busbar cost information has 

limited applicability in decision-making because it is highly dependent on the circumstances being 

considered. A complete analysis of feasible technologies must include consideration of the 

interdependence of the technologies within the context of Duke Energy Carolinas’ existing generation 

portfolio. 

9

 For purposes of this IRP, wind resources are assumed to contribute 15% of installed capacity at the time 

of peak and solar resources are assumed to contribute 40% of installed capacity at the time of peak. 
145

With lower gas prices combined with larger capacities and increased high efficiency, 

combined cycle is the lowest cost base load technology. However, if these curves 

incorporated the impacts of CO2 escalating at a rate higher than inflation after 2032, as 

anticipated, the nuclear and CC costs are competitive at 90% capacity factor and above. 

It is important to note that the capital and operating costs for carbon capture technology 

are still the subjects of ongoing industry studies and research, along with the feasibility 

and costs of geological sequestration of CO2 once it is captured. The sequestration 

geology is not favorable in the Carolinas. 

Intermediate and Peaking

The following technologies are found on the peak/intermediate technologies screening 

chart: 

1) 800 MW Simple-Cycle 4-7FA CTs 

2) 627 MW Simple- Cycle 8-7EA CTs 

0

500

1000

1500

2000

2500

0% 20% 40% 60% 80% 100%

PVRR $/kw-yr

Capacity Factor

Baseload Technologies Screening 2012-2032

618 MW w/ CCS 800#/nMWHR IGCC 

Combined Cycle 7FA - 2x2x1 Inlet Chiller + Duct Fired 

2 x 1117 MW Nuclear (AP1000) 

825 MW w/CCS 1000#/nMWHR SCPC 

C 

O 

N 

F 

I 

D 

E 

N 

T 

I 

A 

L 
146

The peak and intermediate screening curves include two options for simple cycle CTs 

with the 7FA unit making up the lower envelope of the curves. Historically, CTs are 

limited to peaking generation due to permit restrictions. CCs were shown as a base load 

technology, however with higher gas prices or not including the impacts of CO2, CC 

becomes an intermediate technology. 

Renewables

The following technologies are found on the renewable technologies screening chart: 

1) 150 MW Wind 

2) 25 MW Solar Photovoltaic 

3) 5 MW Landfill Gas 

0

100

200

300

400

500

600

0% 20% 40% 60% 80% 100%

PVRR $/kw-yr

Capacity Factor

Peak / Intermediate Technologies Screening 2012-2032

Simple Cycle (4 CTs) 7FA Simple Cycle (8 CTs) 7EAs 

C 

O 

N 

F 

I 

D 

E 

N 

T 

I 

A 

L 
147

One must remember that busbar chart comparisons involving some renewable resources, 

particularly wind and solar resources can be somewhat misleading because these 

resources do not contribute their installed capacity at the time of the system peak10. Since 

busbar charts attempt to levelize and compare costs on an installed kW basis, wind and 

solar resources appear to be more economic than they would be if the comparison was 

performed on a peak kW basis. In addition, the cost of solar does not incorporate the 

impact of federal and state investment tax credits or the impacts of solar technology cost 

decreasing over time, as was used in the IRP. 

Since these renewable technologies either have no CO2 emissions or are deemed to be 

carbon neutral, the cost of CO2 emissions does not impact their operating cost. Landfill 

gas appears to be the least-cost renewable alternative through its entire capacity factor 

range with Solar Photovoltaic as the most expensive resource within the renewable 

category. 

 

10 For purposes of this IRP, wind resources are assumed to contribute 15% of installed capacity at the time 

of peak and solar resources are assumed to contribute 40% of installed capacity at the time of peak. 

0

50

100

150

200

250

300

350

400

450

500

0% 20% 40% 60% 80% 100%

PVRR $/kw-yr

Capacity Factor

Renewable Technologies Screening 2012-2032

Wind Solar Photovoltaic Landfill Gas

C 

O 

N 

F 

I 

D 

E 

N 

T 

I 

A 

L 
148 

APPENDIX D: DEMAND SIDE MANAGEMENT ACTIVATION HISTORY 

Time 

Frame Program Times Activated 

Reduction 

Expected 

Reduction 

Achieved 

Activation 

Date 

07/11-05/12 Air Conditioners Economic Event 115 MW 101 MW 07/11/2011 

 Economic Event 123 MW 102 MW 07/13/2011 

 Economic Event 120 MW 108 MW 07/20/2011 

 Economic Event 127 MW 115 MW 07/21/2011 

 Economic Event 120 MW 110 MW 07/29/2011 

 Economic Event 119 MW 115 MW 08/02/2011 

 Test Emergency Event 180 MW 183 MW 08/25/2011 

Standby Generator1 Emergency Event 48 MW 45 MW 07/12/2011 

Interruptible Service Emergency Event 128 MW 133 MW 07/12/2011 

Communication Test N/A N/A 05/08/2012 

PowerShare® Generator1 Emergency Event 13 MW 13 MW 07/12/2011 

PowerShare® Mandatory Emergency Event 337 MW 339 MW 07/12/2011 

PowerShare® Voluntary Economic Event N/A 2 MW 07/20/2011 

Economic Event N/A 2 MW 07/21/2011 

Economic Event N/A 4 MW 07/22/2011 

 Economic Event N/A 2 MW 08/03/2011 

09/10-06/11 Air Conditioners Economic Event 113 MW 101 MW 06/21/2011 

Standby Generator Emergency Event 48 MW 55 MW** 06/01/2011 

Interruptible Service Emergency Event 148 MW 156 MW** 06/01/2011 

Communication Test N/A N/A 05/12/2011 

PowerShare® Generator Emergency Event 13 MW 17 MW** 06/01/2011 

PowerShare® Mandatory Emergency Event 335 MW 334 MW** 06/01/2011 

PowerShare® Voluntary Economic Event N/A 14 MW 12/15/2010 

Economic Event N/A 2 MW** 06/01/2011 

Economic Event N/A 16 MW 06/02/2011 

PowerShare® CallOption Economic Event 0.2 MW 0.2 MW 12/14/2010 

Economic Event 0.2 MW 0.2 MW 12/15/2010 

Economic Event 0.2 MW 0.2 MW 01/13/2011 
149 

Time 

Frame Program Times Activated 

Reduction 

Expected 

Reduction 

Achieved 

Activation 

Date 

9/09 – 

9/10* 

Air Conditioners Economic Event 46 MW 50 MW 6/14/2010 

Economic Event 50 MW 45 MW 6/15/2010 

Economic Event 103 MW 102 MW 6/23/2010 

 Economic Event 90 MW 81 MW 07/07/2010 

 Economic Event 90 MW 87 MW 07/08/2010 

 Economic Event 99 MW 103 MW 07/22/2010 

 Economic Event 114 MW 114 MW 07/23/2010 

 Economic Event 107 MW 107 MW 08/05/2010 

Standby Generators Monthly Test 

Interruptible Service Communication Test N/A N/A 6/8/2010 

PowerShare® Voluntary Economic Event N/A 13 MW 6/15/2010 

Economic Event N/A 17 MW 6/23/2010 

 Economic Event N/A 9 MW 7/7/2010 

 Economic Event N/A 7 MW 7/8/2010 

 Economic Event N/A 7 MW 7/23/2010 

 Economic Event N/A 28 MW 7/29/2010 

 Economic Event N/A 5 MW 8/4/2010 

 Economic Event N/A 7 MW 8/5/2010 

PowerShare®CallOption Economic Event 0.2 MW 0.2 MW 07/07/2010 

 Economic Event 0.2 MW 0.2 MW 07/08/2010 

 Economic Event 0.2 MW 0.2 MW 08/05/2010 

9/08 -9/09 Air Conditioners Cycling Event 30 MW 8/10/2009 

 SOC Full Shed Test N/A N/A 8/11/2009 

 

Water Heaters 

Standby Generators 

Interruptible Service Communication Test N/A N/A 5/6/2009 

9/07 – 9/08 Air Conditioners 

Water Heaters 

Standby Generators 

Interruptible Service Communication Test N/A N/A 5/6/2008 

8/06 – 8/07 Air Conditioners Cycling Test N/A N/A 8/30/2007 

 Load Test (PLC only) N/A N/A 8/7/2007 

 Load Test 120 MW 88 MW 8/2/2007 

 Water Heaters Cycling Test N/A N/A 8/30/2007 

 Load Test (PLC only) N/A N/A 8/7/2007 

 Load Test 2 MW Included in Air 

Conditioners. 

8/2/2007 

 Standby Generators Capacity Need 82 MW 88 MW 8/10/2007 

 Capacity Need 82 MW 90 MW 8/9/2007 

 Capacity Need 82 MW 79 MW 8/8/2007 

 Capacity Need 82 MW 85 MW 8/1/2006 

 Monthly Test 
150

Time 

Frame Program Times Activated 

Reduction 

Expected 

Reduction 

Achieved 

Activation 

Date 

8/06 – 8/07 Interruptible Service Capacity Need 306 MW 301 MW 8/10/2007 

cont. Capacity Need 306 MW 323 MW 8/9/2007 

 Capacity Need 341 MW 391 MW 8/1/2006 

 Communication Test N/A N/A 4/24/2007 

8/05 – 7/06 Air Conditioners Load Test 110 MW 107 MW 6/21/2006 

 Cycling Test N/A N/A 9/21/2005 

 Cycling Test N/A N/A 9/20/2005 

 Water Heaters Load Test 2 MW Included in Air 

Conditioners. 

6/21/2006 

 Cycling Test N/A N/A 9/21/2005 

 Cycling Test N/A N/A 9/20/2005 

 Standby Generators Monthly Test 

 Interruptible Service Communication Test N/A N/A 4/25/2006 

8/04 – 7/05 Air Conditioners Load Test 140 MW 148 MW 7/21/2005 

 Cycling Test N/A N/A 8/19/2004 

 Cycling Test N/A N/A 8/18/2004 

 Water Heaters Load Test 2 MW Included in Air 

Conditioners. 

7/21/2005 

 Cycling Test N/A N/A 8/19/2004 

 Cycling Test N/A N/A 8/18/2004 

 Standby Generators Monthly Test 

8/03 – 7/04 Air Conditioners Load Test 110 MW 170 MW 7/14/2004 

 Cycling Test N/A N/A 8/20/2003 

 Water Heaters Cycling Test N/A N/A 8/20/2003 

 Standby Generators Monthly Test 

 Interruptible Service Communication Test N/A N/A 4/28/2004 

8/02 – 7/03 Air Conditioners Load Test 120 MW 195 MW 7/16/2003 

 Cycling Test N/A N/A 6/18/2003 

 Cycling Test N/A N/A 9/18/2002 

 Load Test 82 MW 122 MW 8/21/2002 

 Water Heaters Load Test 5 MW Included in Air 

Conditioners. 

7/16/2003 

 Cycling Test N/A N/A 6/18/2003 

 Cycling Test N/A N/A 9/18/2002 

 Load Test 6 MW Included in Air 

Conditioners. 

8/21/2002 

 Standby Generators Monthly Test 

 Interruptible Service Communication Test N/A N/A 5/7/2003 

 Communication Test N/A N/A 11/19/2002 
151 

Time 

Frame Program Times Activated 

Reduction 

Expected 

Reduction 

Achieved 

Activation 

Date 

8/01 – 7/02 Air Conditioners Cycling Test N/A N/A 7/17/2002 

 Cycling Test N/A N/A 6/19/2002 

 Cycling Test N/A N/A 8/31/2001 

 Load Test 150 MW 151 MW 8/17/2001 

 Water Heaters Cycling Test N/A N/A 7/17/2002 

 Cycling Test N/A N/A 6/19/2002 

 Cycling Test N/A N/A 8/31/2001 

 Load Test 6 MW Included in Air 

Conditioners. 

8/17/2001 

 Standby Generators Capacity Need 80 MW 20 MW 

Estimation due 

to 

communication 

problems. 

6/13/2002 

 Interruptible Service Capacity Need 403 MW 370 MW 6/13/2002 

 Communication Test N/A N/A 4/17/2002 

8/00 – 7/01 Air Conditioners Communication Test N/A N/A 9/14/2000 

 Water Heaters Communication Test N/A N/A 9/14/2000 

 Standby Generators Capacity Need 70 MW 70 MW 8/7/2000 

 Interruptible Service Communication Test N/A N/A 5/8/2001 

7/99 – 8/00 Air Conditioners Load Test 170-200 MW 175-200 MW 6/15/2000 

 Water Heaters Load Test 6 MW Included in Air 

Conditioners. 

6/15/2000 

 Standby Generators Capacity Need 70 MW 70 MW 7/2/2000 

 Monthly Test 

 Interruptible Service Communication Test N/A N/A 5/17/2000 

 Communication Test N/A N/A 10/20/1999 

9/98 – 7/99 Standby Generators Monthly Test 

 Interruptible Service Communication Test N/A N/A 5/11/1999 

 Communication Test N/A N/A 10/27/1998 

9/97 – 9/98 Air Conditioners Load Test 180 MW 170 MW 8/18/1998 

 Water Heaters Load Test 7 MW 7 MW 8/18/1998 

 Communication Test N/A N/A 5/29/1998 

 Standby Generators Capacity Need 68 MW 58 MW 8/31/1998 

 Capacity Need 68 MW 58 MW 6/12/1998 

 Monthly Test 

 Interruptible Service Capacity Need 570 MW 500 MW 8/31/1998 

 Communication Test N/A N/A 5/29/1998 
152 

Time 

Frame Program Times Activated 

Reduction 

Expected 

Reduction 

Achieved 

Activation 

Date 

9/96 – 9/97 Air Conditioners Communication Test N/A N/A 6/17/1997 

 Standby Generators Capacity Need 62 MW 50 MW 7/28/1997 

 Capacity Need 62 MW 50 MW 7/15/1997 

 Capacity Need 62 MW 50 MW 7/14/1997 

 Capacity Need 62 MW 50 MW 12/20/1996 

 Monthly Test 

 Interruptible Service Capacity Need 650 MW 550 MW 7/28/1997 

 Communication Tests N/A N/A 6/17/1997 

 Communication Tests N/A N/A 10/16/1996 

* Starting in 2010, a new category of event called an Economic Event has been added to the table. 

**Corrected numbers from previous table filed. 

1PowerShare® Generator and Standby Generator have monthly test event activations. 
153 

APPENDIX E: PROPOSED GENERATING UNITS AT LOCATIONS NOT 

KNOWN 

A list of proposed generating units at locations not known with capacity, plant type, and 

date of operation included to the extent known: 

Line 12 of the LCR Table for Duke Energy Carolinas identifies cumulative future 

resource additions needed to meet customer load reliably. Resource additions may be a 

combination of short/long-term capacity purchases from the wholesale market, capacity 

purchase options, and building or contracting of new generation

 
154

APPENDIX F: TRANSMISSION LINES AND OTHER ASSOCIATED

FACILITIES PLANNED OR UNDER CONSTRUCTION 

NCUC Rule R8-62(p) requires the following information: 

1. For existing lines, the information required on FERC Form 1, pages 422, 423, 424 and 

425: (Please see Appendix J for Duke Energy Carolinas’ current FERC Form 1 pages 

422, 423, 422.1, 423.1, 422.2, 423.2, 423.3, 424, 425, and 450.1.) 

2. For lines under construction: 

Transmission lines and facilities currently planned or under construction are listed below: 

 

• Caesar 230 kV line reconductoring project - The project is needed to 

accommodate a transmission service request to transfer power into Progress 

Energy Carolinas West area. The project consists of reconductoring a 22 mile 

line of existing 954 ACSR conductor with 1158 ACSS conductor. The line runs 

between Duke’s Pisgah Tie and Shiloh Switching Station. The planned in-service 

date for this project is June 2013. 

• Antioch Tie 500/230 kV transformer upgrade project- This project is one of the 

FERC approved merger mitigation transmission projects. This project will 

replace two existing transformers, with a total capacity of 1500 MVA, with two 

new transformers with a total capacity of 3000 MVA. The estimated completion 

date for this project is June 2015. 

3. For all other proposed lines, as the information becomes available: 

There are no proposed lines at this time. Information will be added as it becomes 

available. 

 
155
156
157
158

 
159
160
161
162
163
164
165
166 

GENERATION AND ASSOCIATED TRANSMISSION FACILITIES SUBJECT 

TO CONSTRUCTION DELAYS 

A list of any generation and associated transmission facilities under construction which 

have delays of over six months in the previously reported in-service dates and the major 

causes of such delays. Upon request from the NCUC Staff, the reporting utility shall 

supply a statement of the economic impact of such delays: 

There are no delays over six months in the stated in-service dates. 

2012 FERC Form 715 

The 2012 FERC Form 715 filed March 2012, is confidential and filed under seal. 
167 

APPENDIX G: OTHER INFORMATION (ECONOMIC DEVELOPMENT) 

Customers Served Under Economic Development: 

In the NCUC Order issued in Docket No. E-100, Sub 97, dated November 15, 2002, the 

NCUC ordered North Carolina utilities to review the combined effects of existing 

economic development rates within the approved IRP process and file the results in its 

short-term action plan. The incremental load (demand) for which customers are 

receiving credits under economic development rates and/or self-generation deferral rates 

(Rider EC), as well as economic redevelopment rates (Rider ER) as of June 2012 is: 

Rider EC: 

89 MW for North Carolina 

9 MW for South Carolina 

Rider ER: 

3 MW for North Carolina 

1 MW for South Carolina 

 
168

APPENDIX H: NON-UTILITY GENERATION/CUSTOMER-OWNED 

GENERATION/STAND-BY GENERATION: 

In the NCUC’s Order Revising Integrated Resource Planning Rules in Docket No. E-100, 

Sub 111, dated July 11, 2007, the NCUC required North Carolina utilities to provide a 

separate list of all non-utility electric generating facilities in the North Carolina portion of 

their control areas, including customer-owned and standby generating facilities, to the 

extent possible. Duke Energy Carolinas’ response to that Order was based on the best 

available information, and the Company has not attempted to independently validate it. In 

addition, some of that information duplicates data that Duke Energy Carolinas supplies 

elsewhere in this IRP. 

The Company has continued to add small non-utility electric generation since the 2010 

IRP. An updated listing is included below. The tables in this Appendix represent those 

non-utility generation and stand-by generation contracts that were signed as of August 1, 

2012. It is prudent to note that additional contracts are in various phases of signing and 

negotiation, and these tables frequently change. Tables 5.E and 5.F in Chapter 5 also 

represent a high-level snapshot of some of the wholesale non-utility generation contracts 

signed as of August 1, 2012. 

The Company also includes a full list in its annual status report filed in Docket No. E100, Sub 41B. 

 
169 

PURPA Qualifying Facilities 

Supplier City Nameplate 

KW Primary Fuel Type

Part of Total 

Supply 

Resources 1

203 Neotrantor LLC Hendersonville 9 Photovoltaic Yes

Active Concepts - LLC Lincolnton 75 Photovoltaic Yes

Advantage Investment Group, LLC Gastonia 640 Hydroelectric Yes

AKS Realty & Development (Solar Tech South) Chapel Hill 3 Photovoltaic Yes

Alamance Hydro, LLC Glen Raven 240 Hydroelectric Yes

Amelia M. Collins Chapel Hill 4 Photovoltaic Yes

Andrews Truss, Inc. Andrews 10 Photovoltaic Yes

Anna L. Reilly Winston-Salem 4 Photovoltaic Yes

Arnold M. Schechter Chapel Hill 10 Photovoltaic Yes

Arrowood Construction Franklin 4 Wind Yes

Barbara Ann Evans Caroleen 324 Hydroelectric Yes

Barry L Bingham Lawndale 10 Photovoltaic Yes

Barry R. Wharton Bryson City 3 Photovoltaic Yes

Benjamin R. Eustice Conover 4 Photovoltaic Yes

Berjouhi Keshguerian High Point 4 Photovoltaic Yes

Gail S. Schneitler Pilot Mountain 10 Photovoltaic Yes

Biomerieux, Inc. Durham 124 Photovoltaic Yes

Black Hawk, Inc. Hendersonville 9 Photovoltaic Yes

Boyd Leon Hyder Hendersonville 10 Photovoltaic Yes

Brien R. Deuterman Greensboro 4 Photovoltaic Yes

Bryan C. Turner Durham 7 Photovoltaic Yes

Burlington Hydro LLC Burlington 150 Hydroelectric Yes

Byron Matthews Chapel Hill 3 Photovoltaic Yes

Catawba County - Blackburn Landfill Newton 4,000 Landfill Gas Yes

Catherine C. Hooks Troutman 3 Photovoltaic Yes

Chad D Davis Burlington 3 Photovoltaic Yes

Chapel Hill Tire Company Carrboro 16 Photovoltaic Yes

Charles Brandon Mitchell Durham 4.16 Photovoltaic Yes

Christopher D. Hardin Huntersville 6 Photovoltaic Yes

Cisco Systems Inc. Triangle Park 100 Photovoltaic Yes

City of Charlotte Charlotte 250 Photovoltaic Yes

Cliffside Mills, LLC Cliffside 1,600 Photovoltaic Yes

Commonwealth Brands Inc. Reidsville 169 Photovoltaic Yes

Concepts By Gary, LLC Advance 10 Photovoltaic Yes

Concord Energy LLC Concord 11500 Landfill Gas Yes

CPIM, LLC Carrboro 9.9 Photovoltaic Yes

Daniel E. Suman Chapel Hill 4 Photovoltaic Yes

David Birkhead Hillsborough 2 Photovoltaic Yes

David E. Guinnup Durham 4 Photovoltaic Yes

David E. Shi Brevard 3 Photovoltaic Yes

David H. Newman Greensboro 6 Photovoltaic Yes

David Boyer Sandy Ridge 4 Photovoltaic Yes

David M. Thomas Lenoir 6 Photovoltaic Yes

David A. Ringenburg Chapel Hill 8 Photovoltaic Yes

David W. Walters Sylva 5 Photovoltaic Yes

David Wiener DBA JZ Solar Electric Chapel Hill 3 Photovoltaic Yes

Davidson Gas Producers, LLC-Landfill Gas Lexington 1600 Landfill Gas Yes

DDM Mortgage Corporation Browns Summit 72 Photovoltaic Yes

Decision Support Management LLC Matthews 30 Photovoltaic Yes

Dee Industries, Inc. China Grove 4 Photovoltaic Yes

PURPA QUALIFYING FACILITIES (Selling electricity to Duke Energy Carolinas)
170 

PURPA Qualifying Facilities cont. 

Supplier City Nameplate 

KW Primary Fuel Type

Part of Total 

Supply 

Resources 1

Delta Products Corporation RTP 30 Photovoltaic Yes

Diann M. Barbacci Kernersville 2 Photovoltaic Yes

Dirk J. Spruyt Chapel Hill 4 Photovoltaic Yes

Dixon Dairy Road Kings Mountain 4,000 Photovoltaic Yes

Don A Bicknell Charlotte 4 Photovoltaic Yes

Douglas Albright Thompson Burlington 3 Photovoltaic Yes

Dr. James David Branch Winston-Salem 11 Photovoltaic Yes

Ecologic-Studio, LLC Chapel Hill 4 Photovoltaic Yes

Edward W. Witkin Chapel Hill 6 Photovoltaic Yes

Elaine K. Scott Charlotte 3 Photovoltaic Yes

Elizabeth D Burns Charlotte 4 Photovoltaic Yes

Elizabeth D. Hilborn Chapel Hill 3 Photovoltaic Yes

Elizabeth J Mutran Durham 4 Photovoltaic Yes

Elsewhere Living Museum Greensboro 4.8 Photovoltaic Yes

Eric L. Gaylord Matthews 4 Photovoltaic Yes

Erik Kimelman Greensboro 5 Photovoltaic Yes

Erik P. Raudsep Durham 4 Photovoltaic Yes

Everett Williams Robbinsville 5 Micro-hydro Yes

FLS Owner II, LLC- McDowell Senior Center-Solar Marion 4 Photovoltaic Yes

Fogleman Construction, Inc. Graham 3 Photovoltaic Yes

Foothills Wineworx Inc. Morganton 24 Photovoltaic Yes

Frances L. Thompson Hickory 5 Photovoltaic Yes

Friendship Trays, Inc. Charlotte 8 Photovoltaic Yes

Gail D. Schmidt Tryon 3 Photovoltaic Yes

Gail Severs Schneitler Pilot Mountain 10 Photovoltaic Yes

Gas Recovery Systems, LLC Concord 5,000 Landfill Gas Yes

Gaston County Dallas 4,800 Landfill Gas Yes

Geoffrey E. Gledhill Cedar Grove 6 Photovoltaic Yes

George F. Fralick Edneyville 3 Photovoltaic Yes

Gerald W. Meisner & Harol M. Hoffman Greensboro 4 Photovoltaic Yes

Gerry Priebe Bryson City 7 Photovoltaic Yes

Greensboro Plumbing Supply Greensboro 50 Photovoltaic Yes

Gwenyth T. Reid Hillsborough 4 Photovoltaic Yes

H. Malcolm Hardy Chapel Hill 3 Photovoltaic Yes

Haneline Power, LLC Millersville 365 Hydroelectric Yes

Hardins Resources Company Hardens 820 Hydroelectric Yes

Haw River Hydro Company Saxapahaw 1,500 Hydroelectric Yes

Hayden-Harman Foundation Burlington 2 Photovoltaic Yes

Hendrik J. Roddenburg Chapel Hill 3 Photovoltaic Yes

Holzworth Holdings, Inc. Durham 3 Photovoltaic Yes

Innovative Solar Solutions Charlotte 4 Photovoltaic Yes

Irvine River Company Eden 500 Hydroelectric Yes

J Chester Grey Vale 10 Photovoltaic Yes

Jafasa Farms - Residence Horseshoe 6 Photovoltaic Yes

Jafasa Farms - Greenhouse Horseshoe 6 Photovoltaic Yes

James B. Sherman Chapel Hill 5 Photovoltaic Yes

James E. Jackson Mount Airy 12.26 Photovoltaic Yes

James Edward Rowell Jr. Charlotte 4 Photovoltaic Yes

James J. Boyle Durham 4 Photovoltaic Yes

James Lee Johnson Matthews 2 Photovoltaic Yes
171 

PURPA Qualifying Facilities cont. 

Supplier City Nameplate 

KW Primary Fuel Type

Part of Total 

Supply 

Resources 1

James Richard Trevathan Highlands 3 Photovoltaic Yes

JDC Manufacturing, LLC Reidsville 90 Photovoltaic Yes

Jeffery L. Pardue Wilkesboro 4 Photovoltaic Yes

Jerome Levit Graham 2 Photovoltaic Yes

Jim and Linda Alexander Chapel Hill 4 Photovoltaic Yes

Joel L. Hager Salisbury 4 Photovoltaic Yes

John B. Robbins Concord 10 Photovoltaic Yes

John D. Whitler Randleman 4 Photovoltaic Yes

John H. DiLiberti Hillsborough 10 Photovoltaic Yes

John J. Hammiller Jonesville 4 Photovoltaic Yes

Juba Aluminum Products Company, Inc. Concord 9 Photovoltaic Yes

Katharine L. Popejoy Charlotte 5 Photovoltaic Yes

Keith Adam Smith Nebo 2 Photovoltaic Yes

Kenneth A. Bollen Chapel Hill 2 Photovoltaic Yes

Kevin Newell Mooresville 4 Photovoltaic Yes

KMBA, LLC Charlotte 9 Photovoltaic Yes

Laura J. Ballance Durham 7 Photovoltaic Yes

Lawrence Electric, Inc. Salisbury 2 Photovoltaic Yes

Lawrence Lee Adrian Durham 4 Photovoltaic Yes

Leon's Beauty School, Inc. Greensboro 35 Photovoltaic Yes

Lynwood Solar I, LLC Kings Mountain 135 Photovoltaic Yes

Marilyn M. Norfolk Chapel Hill 5 Photovoltaic Yes

Mark A. Powers Chapel Hill 2 Photovoltaic Yes

Mark S. Trustin Attorney At Law Durham 3 Photovoltaic Yes

Markus Andres Chapel Hill 4 Photovoltaic Yes

Martin Joseph Lashua Huntersville 4 Photovoltaic Yes

Martin Truex Jr. LLC Mooresville 60 Photovoltaic Yes

Mary Karen Nicholson Mebane 2 Photovoltaic Yes

Matthew T. Ewers Charlotte 3 Photovoltaic Yes

Mayberry Solar LLC Mount Airy 1,000 Photovoltaic Yes

Mayo Hydropower, LLC Mayodan 951 Hydroelectric Yes

Mayo Hydropower, LLC Mayodan 1,275 Hydroelectric Yes

Megawatt Solar, Inc. Hillsborough 5 Photovoltaic Yes

Mehul Shah Huntersville 4 Photovoltaic Yes

Michael G. Hitchcock Yadkinville 8 Photovoltaic Yes

Michael J. Peterson Charlotte 1.89 Photovoltaic Yes

Mill Shoals Hydro Company, Inc. High Shoals 1,800 Hydroelectric Yes

Molly S. Payne Pinnacle 4 Photovoltaic Yes

MP Durham, LLC Durham 3,180 Landfill Gas Yes

Namron, Inc. Charlotte 4 Photovoltaic Yes

Nathaniel J. Poovey Newton 5 Photovoltaic Yes

National Renewable Energy Corporation Gastonia 635 Photovoltaic Yes

Newton-Conover City Schools Conover 135 Photovoltaic Yes

Norris Job Galyan Concord 4 Photovoltaic Yes

Northbrook Carolina Hydro, L.L.C. - Turner Shoals Mill Spring 5,500 Hydroelectric Yes

Nypro INC dba Nypro Carolinas Mebane 222 Photovoltaic Yes

Oakdale Holding, LLC Hillsborough 18 Photovoltaic Yes

Oenophilia Hillsborough 18 Photovoltaic Yes

Old Dominion Freight Line Inc Thomasville 1,500 Yes

Optima Engineering Charlotte 8 Photovoltaic Yes
172 

PURPA Qualifying Facilities cont. 

Supplier City Nameplate 

KW Primary Fuel Type

Part of Total 

Supply 

Resources 1

Pacifica Master Homeowners' Association Carrboro 5 Photovoltaic Yes

Paul C. Kuo Chapel Hill 3 Photovoltaic Yes

Paul G. Keller DBA Futility Chapel Hill 4 Photovoltaic Yes

Paul M. Neubauer Graham 2 Photovoltaic Yes

Philip E. Miner Ellenboro 5 Photovoltaic Yes

Phillip B. Caldwell Brevard 3 Photovoltaic Yes

Pierre Burke Sylva 9 Photovoltaic Yes

Pickens Mill Hydro, LLC Charlotte 600 Hydroelectric Yes

Pippin Home Designs Sherrils Ford 4 Photovoltaic Yes

Public Library of Charlotte & Meck. County Charlotte 33 Photovoltaic Yes

R. Lawrence Ashe, Jr. Glenville 4 Photovoltaic Yes

Rainer Dammers Chapel Hill 4 Photovoltaic Yes

Rajah Y. Chacko Charlotte 3 Photovoltaic Yes

Rajendra Morey Durham 7 Photovoltaic Yes

Ramona L. Sherwood Charlotte 4 Photovoltaic Yes

RayLen Vineyards, Inc. Mocksville 10 Photovoltaic Yes

Rebecca A. Durante Charlotte 2 Photovoltaic Yes

Rebecca G. Laskody Chapel Hill 3 Photovoltaic Yes

Rebecca T. Cobey Chapel Hill 2 Photovoltaic Yes

Richard J. Harkrader Durham 4 Photovoltaic Yes

Richard Sweeney Belmont 4 Photovoltaic Yes

Robert Carton Glenville 9.9 Photovoltaic Yes

Robert E Adams Hendersonville 4 Photovoltaic Yes

Robert Skirboll Greensboro 4 Photovoltaic Yes

Robert W. Stone Charlotte 5 Photovoltaic Yes

Ron B. Rozzelle Graham 6 Photovoltaic Yes

Ron O. Bryant Norwood 5.16 Photovoltaic Yes

Ronald Lippard Randleman 4 Photovoltaic Yes

Ronald R. Butters Durham 5 Photovoltaic Yes

Ronnie B Power (Sharpe-Falls) Warrensville 200 Hydroelectric Yes

Runaway Properties, LLC Hendersonville 9 Photovoltaic Yes

Russell Von Stein Brevard 3 Photovoltaic Yes

Salem Energy Systems, L.L.C. Winston-Salem 4,750 Landfill Gas Yes

Samuel C. Bingham Rutherfordton 4 Photovoltaic Yes

J. Chester Grey Vale 10 Photovoltaic Yes

SanDan Farm McLeansville 24 Photovoltaic Yes

Scot Friedman Greensboro 5 Photovoltaic Yes

Shawn L. Slome Chapel Hill 2 Photovoltaic Yes

Sheldon R. Pinnell Durham Photovoltaic Yes

Shoe Show, Inc. Concord 4500 Photovoltaic Yes

South Yadkin Power, Inc. Greensboro 1,500 Hydroelectric Yes

SouthData, Inc. Mount Airy 9.87 Photovoltaic Yes

Spencer Yost Pfafftown 4 Photovoltaic Yes

Stanley D. Chamberlain Chapel Hill 9 Photovoltaic Yes

Stewart Bible Durham 2 Photovoltaic Yes

Stephen C. Graf Cedar Grove 5 Photovoltaic Yes

Steven D. Holdaway Chapel Hill 5.17 Photovoltaic Yes

Steve Mason Enterprises Inc Gastonia 750 Hydroelectric Yes

Stoneville Solar, LLC Stoneville 9 Photovoltaic Yes

Strates Inc. DBA Westtown Eatery & Express Winston-Salem 6 Photovoltaic Yes
173 

PURPA Qualifying Facilities cont. 

Supplier City Nameplate 

KW Primary Fuel Type

Part of Total 

Supply 

Resources 1

Lamar Bailes Walhalla 5 Photovoltaic Yes

Lawrence B. Miller Anderson 3 Photovoltaic Yes

Lockhart Power Company Wellford 1,600 Landfill Gas Yes

Northbrook Carolina Hydro, L.L.C. - Boyd's Mill Ware Shoals 1,500 Hydroelectric Yes

Northbrook Carolina Hydro, L.L.C. - Hollidays 

Bridge Belton 3,500 Hydroelectric Yes

Northbrook Carolina Hydro, L.L.C. - Saluda Greenville 2,400 Hydroelectric Yes

Pelzer Hydro Company, Inc. Pelzer 2,020 Hydroelectric Yes

Pelzer Hydro Company, Inc. Pelzer 3,300 Hydroelectric Yes

Thomas W. Bates Simpsonville 5 Photovoltaic Yes
174 

Stand-by Generator Customers 

County State Nameplate kW

Alamance NC 875

Alamance NC 550

Alamance NC 600

Alamance NC 200

Alamance NC 800

Alamance NC 1150

Burke NC 200

Burke NC 600

Cabarrus NC 2950

Cabarrus NC 680

Catawba NC 1500

Catawba NC 1750

Catawba NC 1040

Catawba NC 500

Catawba NC 500

Cleveland NC 4480

Davidson NC 300

Davidson NC 750

Davidson NC 2950

Durham NC 1600

Durham NC 1300

Durham NC 3000

Durham NC 2250

Durham NC 1000

Durham NC 350

Durham NC 1825

Elkin NC 400

Forsyth NC 800

Forsyth NC 1800

Forsyth NC 400

Forsyth NC 750

Forsyth NC 1050

Forsyth NC 3000

Forsyth NC 500

Forsyth NC 2000

Forsyth NC 3750

Forsyth NC 3000
175 

Stand-by Generator Customers cont. 

County State Nameplate kW

Gaston NC 265

Gaston NC 350

Gaston NC 500

Gaston NC 350

Gaston NC 440

Gaston NC 1590

Gaston NC 210

Granville NC 1250

Granville NC 750

Guilford NC 1350

Guilford NC 125

Guilford NC 700

Guilford NC 2500

Guilford NC 1280

Guilford NC 750

Guilford NC 250

Henderson NC 1000

Henderson NC 500

Henderson NC 1000

Iredell NC 750

McDowell NC 650

Mecklenburg NC 1750

Mecklenburg NC 1250

Mecklenburg NC 200

Mecklenburg NC 2250

Mecklenburg NC 1200

Mecklenburg NC 420

Mecklenburg NC 400

Mecklenburg NC 2200

Mecklenburg NC 1450

Mecklenburg NC 1450

Mecklenburg NC 3200

Mecklenburg NC 10000

Orange NC 500

Orange NC 1135

Orange NC 500

Orange NC 2000
176 

Stand-by Generator Customers cont. 

County State Nameplate kW

Rockingham NC 1700

Rockingham NC 750

Rowan NC 1500

Surry NC 600

Surry NC 750

Surry NC 500

Union NC 400

Wilkes NC 600

Wilkes NC 750

Wilkes NC 750

Wilkes NC 155

Yadkin NC 1200

Yadkin NC 500
177 

PowerShare® Generator Customers 

County State Nameplate kW

Greenwood SC 1500

Laurens SC 447

Lancaster SC 1875

Spartanburg SC 500

Spartanburg SC 2900

Durham NC 13400

Durham NC 10900

Jackson NC 12500

Guilford NC 2000
178 

APPENDIX I: WHOLESALE PROJECTIONS FROM EXISTING AND 

POTENTIAL CUSTOMERS 

Table I.1 below provides the historical and projected growth in peak loads for the 

Company’s wholesale customers. The wholesale customer growth rates vary. With 

respect to wholesale sales contracts, the Company has developed econometric forecasting 

models for the larger wholesale customer in a process similar to that used for retail to 

produce MWH sales forecasts. For smaller wholesale customers, however, their 

forecasted growth is assumed to be the same as Duke Energy Carolinas’ retail growth. 

It is important to note that the growth rates for Central and NCEMC Supplemental 

Requirements) are primarily driven by terms of the contract. The Central Sale provides 

for a seven year “step-in” to Central’s full load requirement such that the Company will 

provide 15% of Central’s total member cooperative load in Duke’s Balancing Authority 

Area requirement in 2013. This initial load requirement will be followed by subsequent 

15% annual increases in load over the following six years up to a total of 100% of 

Central’s load requirements. The NCEMC Fixed Load Shape is essentially a fixed 

quantity of capacity and energy specified by the contract 

The wholesale sales contracts, shown in Table 3.D, are gross loads and are not reduced 

by the resources that some wholesale entities operate. 
179

TABLE I.1 (CONFIDENTIAL) 

There are no undesignated wholesale contracts identified in the 2012 Duke Energy Carolinas 

IRP. 

 

Duke Energy Carolinas Historical and Projected Load

Municipal Other 

Customers 1Piedmont EMC

Blue Ridge EMC & 

(New River) Rutherford EMC

NCEMC Fixed 

Load Shape Haywood EMC

City of 

Greenwood Central

History

2000 265 69 155 206 NA NA 62 638

2001 265 76 169 227 NA 15 65 651

2002 287 78 200 239 NA 18 68 719

2003 249 76 189 230 NA 16 66 691

2004 239 80 189 238 NA 18 65 693

2005 278 92 206 251 NA 23 71 815

2006 304 87 216 256 NA 20 67 729

2007 309 97 226 271 NA 24 73 878

2008 289 84 216 268 NA 25 73 818

2009 275 87 203 255 72 20 66 816

2010 349 87 223 268 72 25 68 836

2011 327 85 217 258 72 20 67 818

Forecast

2012 315 90 224 273 72 20 66 - 

2013 317 91 227 276 72 20 66 123 

2014 322 92 230 281 72 20 67 250 

2015 327 94 234 285 72 20 68 383 

2016 332 95 238 290 72 21 69 521 

2017 337 97 242 294 72 21 70 664 

2018 342 98 246 299 72 21 71 812 

2019 347 100 250 304 72 22 72 919 

2020 352 101 254 308 72 22 74 937 

2021 357 103 258 313 72 22 75 955 

2022 362 105 263 318 72 23 76 973 

2023 367 106 267 323 72 23 77 992 

2024 372 108 272 328 72 23 78 1,011 

2025 378 110 276 333 72 23 79 1,031 

2026 383 112 281 338 72 24 80 1,050 

2027 389 114 286 343 72 24 81 1,070 

2028 396 116 290 348 72 25 83 1,090 

2029 402 118 295 353 72 25 84 1,110 

2030 408 120 300 359 72 25 85 1,132 

2031 414 122 306 364 72 26 87 1,153 

2032 421 124 311 370 72 26 88 1,175 

2001-2011 2001-2011 2001-2011 2001-2011 2001-2011 2001-2011 2001-2011 2001-2011

Growth Rate 2.1% 1.1% 2.5% 1.3% 0.0% 3.1% 0.3% 2.3%

2012-2032 2012-2032 2012-2032 2012-2032 2012-2032 2012-2032 2012-2032 2012-2032

Growth Rate 1.5% 1.6% 1.7% 1.5% 0.0% 1.4% 1.5% 1.7%

1

 Duke resale Forecast includes the cities of Concord, Kings Mountain, Forest City,Due West, Prosperity, Dallas, and the electric 

 company Lockhart and Western Carolina, University and the city of Highlands.

The contract lengths vary from city to city.

The historical data and forecast no longer includes Clemson starting in 2009. Clemson went from wholesale to Retail in early 2009.
180 

APPENDIX J: CARBON NEUTRALITY PLAN 

Greenhouse Gas Reduction Compliance Plan – Cliffside Unit 6 

On January 29, 2008, the NCDAQ issued the Air Quality Permit to Duke Energy 

Carolinas for the Cliffside Unit 6. The Permit specifically requires that Duke Energy 

Carolinas implement a Greenhouse Gas Reduction Plan (Greenhouse Plan), and 

specifically obligates Duke Energy Carolinas to take the following actions in recognition 

of NCDAQ’s issuance of the Permit for Cliffside Unit 6: (1) retire 800 MWs of coal 

capacity in North Carolina in accordance with the schedule set forth in Table J.1, which 

is in addition to the retirement of Cliffside Units 1 – 4; (2) accommodate, to the extent 

practicable, the installation and operations of future carbon control technology; and (3) 

take additional actions to make Cliffside Unit 6 carbon neutral by 2018. 

 

With regard to obligation (1) identified above, as shown in Table J.1 below, Duke Energy 

Carolinas proposes to retire up to 1299 MW at the following generating units to satisfy 

the required retirement schedule set forth in the Greenhouse Plan. 

Table J.1 - Cumulative Coal Plant Retirements

1 In the 2012 IRP, this data appears in Table 5.D, page 55. Plant retirements that were applicable to the first 

obligation were put in this table. References have been updated to match the 2012 IRP. 

2

 The IRP Retirement Schedule indicates that the retirements would exceed the Greenhouse Plan by close 

to 50%. 

With respect to obligation (2) listed above, the requirement to build Cliffside Unit 6 to 

accommodate future carbon technologies has been met by allocating space at the 1100 

acre site for this equipment and incorporating practical energy efficiency designs into the 

plant. 

With respect to obligation (3) to render Cliffside Unit 6 carbon neutral by 2018, the 

Greenhouse Plan 

Retirement 

Schedule 

Capacity in MW 

IRP 

Retirement 

Schedule 

Capacity in 

MW (per 

Table 5.D)1

Description for IRP 

Retirement Schedule 

by end of 2011 113 Buck 3 & 4 

by end of 2012 389 Dan River 1-3 

by end of 2015 350 1299

Riverbend 4 - 7, Buck 5 

& 6, Lee 1&2 

by end of 2016 550 1299 Note 2

by end of 2018 800 1299 
181

proposed plan to achieve this requirement is set forth below. The Greenhouse Gas 

Reduction Plan states that the plan for carbon neutrality: 

may include energy efficiency, carbon free tariffs, purchase of credits, domestic and 

international offsets, additional retirements or reduction in fossil fuel usage as carbon 

free generation becomes available, and carbon reduction through the development of 

smart grid, plug in hybrid electric vehicles or other carbon mitigation projects. Such 

actions will be included in plans to be filed with the NCUC and will be subject to NCUC 

approval, including appropriate cost recovery of such actions. In addition, the plans 

shall be submitted to the Division of Air Quality, which will evaluate the effect of the 

plans on carbon, and provide its conclusions to the NCUC. 

Duke Energy Carolinas included the plan for carbon neutrality in the 2011 IRP in order to 

satisfy the requirement to file and seek approval of the plan from the NCUC as required 

by the NCDAQ Air Permit. The NCUC’s Order Approving 2011 Annual Updates to 

2010 Biennial Resource Plans and 2011 REPS Compliance Plans issued on May 30, 

2012, states that “the Commission is approving the Plan itself as a reasonable path for 

Duke’s compliance with the carbon emission reduction standards of the air quality permit 

and is not approving any individual specific activities nor expenditures for any activities 

shown in the Plan.” 

The estimated emissions reductions required to render Cliffside Unit 6 carbon neutral in 

2018 are approximately 5.3 million tons of carbon dioxide (the Emission Reduction 

Requirement). The Company calculated the estimated emission reductions by estimating 

the actual tons of carbon dioxide emissions that will be released per year from Cliffside 

Unit 6 less 681,954 tons of carbon dioxide emissions that was historically generated from 

Cliffside Units 1 – 4 and will be eliminated by the retirement of these units. (See Table 

J.2 below.) 

Table J.2 - Emission Reduction Requirement 

Actions Tons of CO2 

Equivalent 

Emissions

Notes 

Cliffside Unit 6 6,000,000 Expected Annual Emissions (based on an 

approximate 90% capacity factor) 

Less Cliffside 

Units 1 – 4

(681,954) Average of emissions in 2007 & 20081

 Total Increase 5,318,046 Emissions Reduction Requirement 

1

The emissions attributable to coal plant retirements are identified as the highest two year average CO2 

emissions for the five years prior to the operations of Unit 6 in 2012, consistent with the methodology for 

calculating emissions for major modification under the Clean Air Act Prevention of Significant 

Deterioration regulations. 
182

The Company’s plan for meeting the Emissions Reductions Requirements includes 

actions from multiple categories and associated methodologies for determining the offset 

value known as “Qualifying Actions” (defined below and as further indicated in Table 

J.3). 

For 2018, the Company has identified approximately 9.2 million annual tons of carbon 

dioxide emissions reductions and a life-time credit of 600,000 tons of carbon dioxide biosequestration as eligible Qualifying Actions. (See Table J.3) The Qualifying Actions 

include the avoidance of carbon dioxide emission releases from coal plant retirements, 

addition of renewable resources, implementation of energy efficiency measures, nuclear 

and hydropower capacity upgrades. This also includes the expected retirement of coalfired operations at Lee Units 1, 2 and 3 in South Carolina in 2015. In addition, carbon 

dioxide bio-sequestration offsets from the Greentrees program, which sequesters carbon 

as trees grow, is identified as a Qualifying Action. 

While the reductions associated with retirements for each of the coal plants shall be the 

same each year, the reductions for the remaining Qualifying Actions will vary based on 

actual results for each of the categories and the then current system carbon intensity 

factor. The system carbon intensity factor shall be equal to the actual carbon dioxide 

emissions of all Company-owned generation dedicated for Duke Energy Carolina 

customers divided by the megawatt hours generated by those same resources (the 

“Conversion Factor”). 

 
183

Table J.3 - Qualifying Actions for carbon dioxide emission reductions 

Categories Tons of CO2

Equivalent 

Emissions

Methodology Description 

Buck 3 216,202 Average of emissions in 2007 & 20081

Buck 4 139,429 Average of emissions in 2007 & 20081

Buck 5 606,837 Average of emissions in 2007 & 20081

Buck 6 653,860 Average of emissions in 2007 & 20081

Riverbend 4 462,314 Average of emissions in 2007 & 20081

Riverbend 5 435,895 Average of emissions in 2007 & 20081

Riverbend 6 684,010 Average of emissions in 2007 & 20081

Riverbend 7 710,023 Average of emissions in 2007 & 20081

Dan River 1 249,900 Average of emissions in 2007 & 20081

Dan River 2 282,944 Average of emissions in 2007 & 20081

Dan River 3 677,334 Average of emissions in 2007 & 20081

Lee 1 5 335,583 Average of emissions in 2007 & 20081

Lee 2 5 390,965 Average of emissions in 2007 & 20081

Lee 3 5 783,658 Average of emissions in 2007 & 20081

Conservation 1,585,494 In 2018, 3,963,735 MWH “Conservation and 

Demand Side Management Programs”2

 is 

multiplied by a Conversion Factor of 0.40. 

Renewable Energy 623,362 In 2018, 602 MW per the Table 8.E “MW 

Nameplate Capacity”.3 Is multiplied by an 

assumed 30% (wind), 20% (solar), and 85% 

(biomass) capacity factor and a Conversion 

Factor of 0.40. 

Bridgewater Hydro 7,997 Indicates 8.75 MW increase in capacity. This 

is multiplied by a 26% capacity factor and a 

Conversion Factor of 0.40. 

Nuclear Uprates 357,829 Assumed 111 MW of nuclear uprates by June 

of 2018.4 Assumed a 92% capacity factor and 

a Conversion Factor of 0.40. 

 Total Annual 9,203,636

1 The emissions attributable to coal plant retirements are identified as the highest two year average CO2

emissions for the five years prior to the operations of Unit 6 in 2012, consistent with the methodology for 

calculating emissions for major modifications under the Clean Air Act Prevention of Significant 

Deterioration regulations. Company reserves the right to use any credits for reduction of nitrogen oxide, 

sulfur dioxide and carbon dioxide emissions generated by retirement of units retired under the plan 

consistent with provisions of State and federal law. 

2

 Data is from Table 4.A, page 39 of the 2012 IRP. 

3 Data is from the Table 8.E on page 99 of the 2012 IRP. Actual nameplate capacity is 602 MW. The 

contribution to peak is 288 MW. 

4

 Data is a portion of the total capacity addition on page 93 of 2012 IRP prior to June 2018. 

5 Lee Units 1, 2 and 3 are planned for retirement by April 15, 2015. Alternatively, Duke Energy is 

considering converting one or more of these units to natural gas to allow continued operation for peak

generation demand only (at a low annual capacity factor). Any CO2 from operating with natural gas would 

be subtracted from the reductions shown in the table. 
184

As the proposed Plan methodology has been approved, Duke Energy Carolinas shall 

provide a compliance report in the 2019 IRP filing indicating what Qualifying Actions 

were used to meet the Emission Reduction Requirement in 2018. The expected 

Qualifying Actions total 9.2 million tons of emission reductions by 2018. The Company’s 

proposed Qualifying Actions clearly demonstrate that identified reductions can more than 

exceed the Required Emissions Reduction estimate of 5.3 million tons. 
185 

APPENDIX K: NCUC ORDERS 

The NCUC issued three orders since the filing of the 2011 Duke Energy Carolinas IRP 

that require Duke Energy Carolinas to specifically address new requirements in the 2012 

IRP. An outline of the three orders and specific requirements are shown below. 
186 

1. Pursuant to its October 26, 2011 Order Approving 2010 Biennial Integrated 

Resource Plans and 2010 REPS Compliance Plans, the NCUC set forth new 

requirements listed below: 

a) Duke Energy Carolinas and PEC should each prepare a comprehensive 

reserve margin requirements study and include the results of such study as part 

of their 2012 biennial IRPs. 

A discussion of the comprehensive reserve margin study that Duke Energy Carolinas 

performed is found in Chapter 8 on page 85. 
187 

b) Each IOU and EMC should investigate the value of activating DSM 

resources during times of high system load as a means of achieving lower fuel 

costs by not having to dispatch peaking units with their associated higher fuel 

costs if it is less expensive to activate DSM resources. 

A detailed discussion of this order is discussed below: 

Dispatching DSM Resources for Fuel Savings

In Docket No. E-100, Sub 128, issued October 26, 2011, the NCUC order addressed the 

topic of dispatching DSM resources to capture fuel savings, stating, “each IOU and EMC 

should investigate the value of activating DSM resources during times of high system 

load as a means of achieving lower fuel costs by not having to dispatch peaking units 

with their associated higher fuel costs if it is less expensive to activate DSM resources. 

This issue should be addressed as a specific item in their 2012 biennial IRP reports.” 

Duke Energy Carolinas will address the Commission’s requirement in 4 categories as 

listed below. 

A. Duke Energy Carolinas Current DSM Programs Available to Capture Fuel 

Savings

Duke Energy Carolinas administers and implements a portfolio of DSM resources. 

Several of these DSM resources are specifically designed for use only during system 

emergency conditions, while others may be used as an economic resource. Resources 

utilized during system emergency conditions, programs such as Interruptible Service (IS), 

and PowerShare® Mandatory programs are dispatched by the Duke Energy Carolinas 

System Operations Center with an emphasis on system reliability. When implemented, 

these programs may capture fuel savings during these emergency implementations but 

cannot be dispatched in the absence of emergency conditions (i.e. economically) unless 

changes are made to the programs. 

In contrast, Duke Energy Carolinas primarily implements the Power Manager®

 DSM 

resource for economic use and captures fuel savings when the power supply from 

generation options results in a relatively high marginal price. Utilizing DSM resources 

economically only on high marginal cost days maintains the number of activations at a 

reasonable level, and thus retains customer participation in these programs. 

This discussion will concentrate on the Power Manager

® program since it is the program 

with the most potential for capturing fuel savings at this time. There was no participation 

in PowerShare® CallOption in 2011 and the participation in the PowerShare® Voluntary 

program produced relatively small load reduction amounts (i.e., average load reduction 
188

during 2011 event hours of 4.4 MW). Therefore, the evaluation focused on the Power 

Manager® program. 

B. Discussion of Capacity and Energy Value from DSM Resources

DSM resources can provide both avoided capacity cost benefits and avoided energy cost 

benefits. The capability to use Power Manager® for economic implementation was 

provided in Duke Energy Carolinas’ filings in Docket No. E-7, Sub 831. The NCUC 

approved Power Manager® in its Order in the docket dated February 26, 2009. 

With the utilization of actual load information from the summer of 2011, Duke Energy 

Carolinas explores the value of using the Power Manager

®

 program to capture fuel 

savings. As exhibited on Graph K-1, slightly more avoided energy cost could be 

captured by having events either 1 hour later in the day and/or by extending the events for 

an additional hour. Assuming Duke Energy Carolinas would know which days were the 

highest price days to implement economic events throughout the summer, Scenario 4 

shows that economic cycling of customers across 35 days for 100 hours produces greater 

avoided energy costs. 

Graph K.1: 2011 Avoided Energy Cost Scenarios 

Assuming these fuel saving were achieved over a 15 year period, the NPV of potential 

fuel savings are shown in Table K-1 below. The NPVs incorporates the rebound impacts 

of AC units using more energy after event hours than they would have used during the 

same hours had the event not occurred. The value captures price differentials between 

on-peak hours and off-peak hours. The energy values and corresponding fuel savings 

are very small when compared to the NPV of Avoided Capacity Costs equal to 

$29,952 $41,655 $48,019 

$196,501 

$-

$50,000 

$100,000 

$150,000 

$200,000 

$250,000 

Estimated Fuel Dollars Saved

2011 Events vs. Later vs. Longer vs. 100 Hours

2011 Events 1 Hour Later 1 Hour Longer 100 Hours
189

approximately $337 Million over a 15 year period for the Power Manager® program.

Table K.1 

Avoided Energy Cost 

Scenario 

2011 Scenario Avoided 

Energy Cost Results 

15-year NPV Scenario 

Avoided Energy Cost 

2011 Events $29,952 $284,820 

1 Hour Later $41,655 $396,107 

1 Hour Longer $48,019 $456,621 

100 Hours $196,501 $1,868,575 

C. Customer Perceptions and Behaviors Regarding DSM Resources

To address DSM resource implementation from the participant’s perspective, Duke 

Energy Carolinas has gathered data from three sources to investigate customer reaction to 

increased program implementation, including a measure of their behavioral response (i.e., 

their decision to continue or terminate their participation in the DSM program). 

1. Secondary Research Through E-Source: E-Source, an energy industry consulting 

firm, concluded that there is no universal limit to how frequently DR programs 

can be activated before participants become dissatisfied. The primary message 

Duke Energy Carolinas takes from the E-Source response is that participants 

should be engaged and “trained” on how the program works and the expectations 

of program implementation. This will allow customers to make an informed 

decision about participating in demand response programs. Duke Energy 

Carolinas will also carefully manage the cost of additional communications and 

customer training to avoid expenses beyond the savings provided by economic 

event implementation. 

2. Primary Research Study with Power Manager® Participants and Nonparticipants: 532 Power Manager®

 Participants and 700 Power Manager® nonparticipants responded to a survey. The primary objective of this study was to 

investigate how customers would respond if program implementation increased 

up to approximately 100 hours each summer. This study found that increasing the 

length of a DSM event caused participation to drop significantly more than 

increasing the number of DSM events over a shorter period of time. In addition, 

among existing participants, the study also found that participating customers are 

very concerned with the end time of an event. Therefore, using the DSM program 

to achieve more fuel savings may result in unwanted attrition unless carefully 

managed. 
190

3. Perceptions of Customer Experience and Other Program Comments from Duke 

Energy Carolinas DSM Program Managers

a. PowerShare® Voluntary – Experience shows that event participation is 

low unless participant perception is that the system is stressed and an 

emergency could be pending. It is assumed that the large commercial and 

industrial customer participants are cognizant of the differential costs of 

curtailment versus the commitment to produce or serve their customers. 

Those costs or profits, are likely greater than the incentives possible 

through DSM avoided energy incentives. Most load reduction from this 

program is captured during emergency and close-to-emergency events. 

b. PowerShare® CallOption – For the summer of 2011, there were no 

participants in any of the program options offered as the program currently 

suffers from a relatively poor position in the Duke Energy Carolinas 

portfolio of DSM programs. 

c. Power Manager®® – As noted above, Duke Energy Carolinas converted 

the program from an emergency-only program to the Power Manager® 

program that allows for both economic and emergency implementation. 

This allows the capture of some of the additional benefit of avoided 

energy costs and provides increased operational flexibility. Prior to the 

summer of 2012, it was uncertain if a transition from an economic cycling 

event to an emergency full-shed event would function properly. During 

that time, on days when emergency events were considered possible, a 

Power Manager® economic cycling event was not implemented. The 

System Operations Center no longer requires that economic 

implementation be withheld now that upgraded systems will reliably 

transition from an economic event to an emergency event, if needed. 

D. Duke Energy Carolinas’ Current and Recommended DSM Implementation 

Process

Duke Energy Carolinas has established a portfolio of DSM programs to allow customers 

to select their level of involvement with demand response programs. Duke Energy 

Carolinas frequently communicates with customers about their program choices. 

Customers also benefit from savings through economic implementation of the programs. 

In addition, several programs are under consideration to provide customers more options 

and more active involvement with economic implementation of DSM resources in the 

future. Some of these are: 

- Considering new programs such as energy management programs, electric vehicle 

demand response, demand response ready appliances, and a high involvement PS 

CallOption offering. 
191

- Aligning of PowerShare® program incentives with the level of involvement 

selected by the customer 

- Continuing efforts to replace Power Manager® devices with new functioning 

devices 

Conclusion: Based on the research analyzed for the Power Manager®

 program, an 

increased number of short duration events ending early in the evening (i.e. 5 or 6 pm) 

can be tolerated by customers with little impact on customer satisfaction and program 

defection. However, given the large disparity between avoided capacity cost benefits 

and avoided energy cost benefits, the increased implementation strategy must be 

implemented slowly in order to monitor customer perception and closely track program 

enrollment levels. This new bias towards implementation can start as early as the 

summer of 2013. Therefore, Duke Energy Carolinas plans to continue its current 

economic event implementation process with a slightly increased bias toward 

implementation. 
192 

c) Each electric utility should use appropriately updated DSM/EE market 

potential studies. 

A discussion of use of the Company’s 2011 DSM/EE Market Potential study is found in 

Appendix A on page 103. 
193 

2) Pursuant to its May 30, 2012 Order Approving 2011 Annual Updates to the 

2010 Biennial Integrated Resource Plan and 2011 REPS Compliance Plans, the 

NCUC set forth new requirements listed below: 

 

a. Each IOU shall include a discussion of variance of 10% or more in projected 

Energy Efficiency savings from one IRP report to the next. 

The projected total annual MWh load reductions associated with EE programs 

included in the base case for this 2012 IRP are more than 10% higher than those 

included in the 2011 IRP base case, primarily due to updated expectations of the 

performance of the EE programs beyond the initial 5 year planning period. The 

projected base case for this 2012 IRP reaches approximately the same total 

cumulative achievements, including actual achievements since 2009, by 2023 that 

were projected to be achieved by 2031 in the 2011 IRP. 
194 

b. Each IOU shall include a discussion of the status of market potential studies 

or updates in their 2012 and future IRPs. 

In 2011, Duke Energy commissioned an independent Market Potential Study for both the 

North Carolina and South Carolina service territories. This study was prepared by 

Forefront Economics Inc. and was completed in December of 2011. The results of this 

Market Potential Study were incorporated into the Energy Efficiency forecasts included 

in this IRP. 
195 

3) Pursuant to its April 11, 2012 Order Amending Commission Rule R8-60 and 

Adopting Commission Rule R8-60.1 in the Matter of Integrated Resource Planning in 

North Carolina addressing Smart Grid Technology Plans, the NCUC set forth the 

requirements listed below. 

a. Smart Grid Impacts – Each utility shall provide information regarding the impacts 

of its smart grid deployment plan on the overall IRP. 

b. The Smart Grid Technology Plan – By July 1, 2013 and every two years 

thereafter, each utility subject to Rule R8-60 shall file with the Commission its smart 

grid technology plan. Significant amendments or revisions to a smart grid technology 

plan shall be reported to the commission in each year in which the biennial smart grid 

technology plan is not required to be filed. 

A discussion of the Smart Grid Impacts and the Smart Grid Technology Plan is discussed 

on page 41 in Chapter 5. 
196 

APPENDIX L: CROSS-REFERENCE OF IRP REQUIREMENTS 

The following table cross-references IRP regulatory requirements for North Carolina and 

South Carolina, and identifies where those requirements are discussed in the IRP. 

Requirement Location Reference Updated

15-year Forecast of Load, Capacity and Reserves Ch 8, Table 8.A NC R8-60 (c) 1 Yes

Comprehensive analysis of all resource options Ch 4, 5 & 8, App A NC R8-60 (c) 2 Yes

Assessment of Purchased Power Ch 5, Sec D NC R8-60 (d) Yes

Assessment of Alternative Supply-Side Energy Resources Ch 5, Sec B NC R8-60 (e) Yes

Assessment of Demand-Side Management Ch 4, App D NC R8-60 (f) Yes

Evaluation of Resource Options Ch 8, App A & C NC R8-60 (g) Yes

Short-Term Action Plan Executive Summary NC R8-60 (h) 3 Yes

REPS Compliance Plan Filed Concurrently NC R8-60 (h) 4 Yes

Forecasts of Load, Supply-Side Resources, and Demand-Side

Resources

 * 10-year History of Customers and Energy Sales Ch 3 & App B NC R8-60 (i) 1(i) Yes

 * 15-year Forecast w & w/o Energy Efficiency Ch 3 & App B NC R8-60 (i) 1(ii) Yes

 * Description of Supply-Side Resources Ch 5 & App C NC R8-60 (i) 1(iii) Yes

Generating Facilities

 * Existing Generation Ch 5, Sec A NC R8-60 (i) 2(i) Yes

 * Planned Generation Ch 8 & App A NC R8-60 (i) 2(ii) Yes

 * Non Utility Generation Ch 5, Sec D NC R8-60 (i) 2(iii) Yes

Reserve Margins Ch 8, LCR Notes NC R8-60 (i) 3 Yes

Wholesale Contracts for the Purchase and Sale of Power

 * Wholesale Purchased Power Contracts Ch 5, Sec D NC R8-60 (i) 4(i) Yes

 * Request for Proposal Ch 5, Sec D NC R8-60 (i) 4(ii) Yes

 * Wholesale Power Sales Contracts Ch 3 & App I NC R8-60 (i) 4(iii) Yes

Transmission Facilities Ch 7 & App F NC R8-60 (i) 5 Yes

Energy Efficiency and Demand-Side Management

 * Existing Programs Ch 4 & App D NC R8-60 (i) 6(i) Yes

 * Future Programs Ch 4 NC R8-60 (i) 6(ii) Yes

 * Rejected Programs Ch 4 NC R8-60 (i) 4(iii) Yes

 * Consumer Education Programs Ch 4 NC R8-60 (i) 4(iv) Yes

Assessment of Alternative Supply-Side Energy Resources

 * Current and Future Alternative Supply-Side Resources Ch 5, Sec C & App C NC R8-60 (i) 7(i) Yes

 * Rejected Alternative Supply-Side Resources Ch 5, Sec C & App C NC R8-60 (i) 7(ii) Yes

Evaluation of Resource Options (Quantitative Analysis) App A NC R8-60 (i) 8 Yes

Levelized Bus-bar Costs App C NC R8-60 (i) 9 Yes

Smart Grid Impacts Foreward & Ch 4 NC R8-60 (i) 10 Yes

Legislative and Regulatory Issues Ch 6 Yes

Greenhouse Gas Reduction Compliance Plan App J Yes

Other Information (Economic Development) App G Yes