# The Duke Energy Carolinas Integrated Resource Plan (Annual Report)

September 1, 2012

Public1 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 1 7 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 Initia tives 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 Hist ory 148 APPENDIX E: Proposed Generating Units 15 32

APPENDIX F: Transmission Planned or Under Construc tion 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 Carolin as 2012 IRP 1963



# Integrated Resource Plan – abbreviations

Carbon Dioxide CO 2 Central Electric Power Cooperative, Inc. CEPCI Certificate of Public Convenience and Necessity CPC N 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 NPD ES NC Department of Environment and Natural Resources NCDENR NC Green Power NCGP New Source Performance Standard NSPS Nitrogen Oxide NO x 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 NCEM C North Carolina Municipal Power Agency #1 NCMPA14



# 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 St andard 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 SO 2 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 WCU5

FOREWARD

This Integrated Resource Plan (IRP) is the third bi ennial report filed by Duke Energy Carolinas, LLC (Duke Energy Carolinas or the Compan y) under the revised Commission Rule R8-60. A cross reference identifying the loca tion of each regulatory requirement within this IRP is provided in Appendix L.

Due to the timing of the Duke Energy Corporation an d Progress Energy Corporation merger closing, Duke Energy Carolinas and Progress Energy Carolinas, Inc. (PEC) were not able to coordinate their respective 2012 IRP filings. Inpu t assumptions such as fuel prices, environmental inputs, and generation costs, as well as sensitivities and scenarios were developed independently. Assumptions around key in puts such as Energy Efficiency (EE), Demand Side Management (DSM), renewable resources a nd carbon dioxide (CO 2 ) 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 f or 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 n eeds, and the commitment to meet the North Carolina Renewable Energy and Energy Efficien cy Portfolio Standard (NC REPS) requirements.

The North Carolina Utilities Commission (NCUC) issu ed three orders since the filing of the 2011 Duke Energy Carolinas IRP that require Duke En ergy Carolinas to address certain new requirements in the 2012 IRP. An outline of the th ree orders and specific requirements are shown below.

Pursuant to its October 26, 2011 Order Approving 2010 Biennial Integrated Resource P lans 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 o f such study as part of their 2012 biennial IRPs;

• Each IOU and EMC should investigate the value of ac tivating DSM resources during times of high system load as a means of achieving l ower 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 upda ted DSM/EE market potential studies.

Pursuant to its May 30, 2012 Order Approving 2011 Annual Updates to the 2010 Bie nnial Integrated Resource Plan and 2011 REPS Compliance P lans , the NCUC set forth new requirements listed below.6

• 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 o f 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 N orth Carolina addressing Smart Grid Technology Plans, th e NCUC set forth the requirements listed below.

• Smart Grid Impacts – Each utility shall provide inf ormation regarding the impacts of its smart grid deployment plan on the overall IRP.

• The Smart Grid Technology Plan – By July 1, 2013 an d every two years thereafter, each utility subject to Rule R8-60 shall file with the Commission its smart grid technology plan. Significant amendments or revisio ns to a smart grid technology plan shall be reported to the commission in each ye ar in which the biennial smart grid technology plan is not required to be filed.

Each of these requirements is addressed the Company ’s IRP.7

1. EXECUTIVE SUMMARY

Duke Energy Carolinas, a subsidiary of Duke Energy Corporation, utilizes an integrated resource planning approach to ensure that it can re liably 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 ener gy needs including renewable, nuclear, coal, gas, EE, and DSM 1 resources.

Consistent with its responsibility to meet customer energy needs in a way that is affordable, reliable, and clean, the Company’s resource plannin g approach includes both quantitative analysis and qualitative considerations. Quantitat ive analysis provides insights on future risks and uncertainties associated with fuel prices , load growth rates, capital and operating costs, and other variables. Qualitative perspectiv es, such as the importance of fuel diversity, the Company’s environmental profile, the emergence and development of new technologies, and regional economic development considerations ar e 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 qualitativ e perspectives in conjunction with its quantitative analyses to ensure that Duke Energy Ca rolinas will meet near-term and longterm customer needs, while maintaining the operatio nal flexibility to adjust to evolving economic, environmental, and operating circumstance s 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 I RP are (1) a shift in the Company’s first capacity need from 2015 to 2016 and (2) lower proje cted fundamental natural gas prices throughout the planning horizon.

The shift of the Duke Energy Carolinas’ first capac ity need from 2015 to 2016 is primarily due to lower forecasted load projections, an increa se 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. Thes e factors, taken together, result in the Company’s first new resource need of 410 MWs in 201 6. Each of these contributing factors is discussed in greater detail below:

1 Throughout this IRP, the term EE will denote conse rvation programs while the term DSM will denote Dem and Response programs, consistent with the language of N.C. Gen. Stat. 62-133.8 and 133.9.8

• Lower Forecasted Load Projection - Short term lower load growth projections in the residential and commercial sectors and long ter m increases in EE projections are driving the lower forecasted Company load projectio ns.

• Increase in Projected QFs - The increase in projected QF capacity and energy arises from the potential addition of new solar QF facilit ies and due to the renewal of the 88 MW Cherokee Co-Generation QF contract. The Cheroke e contract was due to expire in 2013, but has now been extended through 2020. Th e 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 becau se the final Environmental Protection Agency (EPA) Reciprocating Internal Comb ustion Engine (RICE) rule, which limits hours of non-emergency operation of em ergency generators located at commercial and industrial facilities, was not as st ringent as the original proposed rule from 2011. Also, the projected impacts of Distribu tion Automation, which provides the ability to reduce line voltage during periods o f peak demand, have been incorporated in the DSM program. Distribution Auto mation is a part of the Duke Energy Carolinas Grid Modernization program. The p rojected 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 bi omass 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 proposal s 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 fac ilities have a lower contribution to the Company’s peak than biomass resources, the proj ected increase in volume of solar QFs results in a net increase of renewable re sources 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 m argins 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 20129 IRP. This is a reduction from a 17% target Plannin g Reserve margin used in the 2011 IRP, which resulted in approximately 200 MWs of red uced capacity need in 2015.

The second major change from the 2011 IRP to the 20 12 IRP is that anticipated lower natural gas prices drove the selection of additional combin ed cycle generation rather than additional combustion turbine generation throughout the 20-yea r 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 combusti on turbine resources identified in the
2011 IRP.

Other important factors impacting the 2012 IRP:

As outlined below, a number of additional environme ntal 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 C ompany’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 di scussed in lieu of cap and trade legislation or regulation. A CES would require tha t a certain percentage (e.g. 10% in 2015 escalating up to 30% in 2030) of a utility’s r etail sales be met with combined cycle (CC) natural gas, nuclear, EE, or renewable e nergy. At present, the Company does not anticipate that Congress will consider GHG legislation before the end of 2012. Beyond 2012, the prospects for possible enac tment of any legislation mandating reductions in GHG emissions are highly un certain. Although the Company continues to believe that Congress will eve ntually adopt some form of mandatory GHG emission reduction or Clean Energy le gislation, the timing and form of any such legislation remains highly uncertain.

• EPA GHG Regulation - In the absence of federal GHG or Clean Energy le gislation, the EPA continues to pursue GHG regulations on new and existing units. In 2011, EPA promulgated its Tailoring Rule for existing fos sil-fired generating units which sets the emission thresholds to 75,000 tons/year of CO 2 for determining when a source is potentially subject to Prevention of Sign ificant Deterioration (PSD) permitting for GHGs. Also in 2012, the EPA propose d a rule to establish GHG new source performance standards (NSPS) for new pulveri zed coal and natural gas units. If finalized as proposed, the GHG NSPS would effect ively preclude construction of new pulverized coal units because the standards wer e 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 future10 impacts of these EPA regulations are uncertain at t his time, and there are presently no cost-effective and demonstrated controls for CO 2 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 h as evaluated a range of CO 2 prices, in addition to potential Clean Energy legis lation.

• 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 generat ion, CO 2 emissions for the natural gas portfolio are projected to continue to rise thr oughout the planning period. In addition, the Company’s fundamental natural gas pri ces were developed assuming continued operation of the nation’s existing nuclea r fleet. The operating licenses of many of the country’s existing nuclear units have a lready 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 natura l gas and new nuclear generation. As discussed above, although GHG legislation is not believed to be imminent, the EPA continues to pursue CO 2 regulations on existing and new generation units, w hich will also impact the future cost for any CO 2 -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 in crease 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 Statio n Unit 3 to natural gas fuel, along with the energy and capacity savings achievements of the Com pany’s EE and DSM programs, will fulfill these needs through 2015. Beginning in 201 6, 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 Com pany’s options and plans for meeting its projected long-term needs. The general factors that influence the Company’s future resource needs are:11

• 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 Du ke Energy Carolinas has a reliable, diverse, environmentally sound, and reasonably pric ed portfolio of resources over time.

Both DSM and EE programs play important roles in th e Company’s development of a balanced, cost-effective and environmentally respon sible resource portfolio. Renewable generation options are also necessary to meet the N C REPS enacted in 2007. These resources will be incorporated more broadly into th e Company’s resource portfolio to the extent they become more cost-effective in compariso n with traditional supply-side resources and with consideration of other qualitative issues such as their intermittency and relative contribution to meeting peak capacity needs. Energ y savings resulting from EE programs may also be used to meet, in part, the Company’s RE PS obligations. The Company’s REPS Compliance Plan is being filed concurrently with th e 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 201 8 and at various points throughout the study period in addition to significant EE, DSM, an d 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 Co mpany’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 o r more partners plan collaboratively to stage multiple nuclear stations over a period of ye ars 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 gene ration plan. Duke Energy Carolinas continues to strongly support regional nuclear oppo rtunities and is actively pursuing this12

concept. As the Company announced in 2011, Duke En ergy 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 op tion for a minority interest (5 to 10% of the capacity of the two units) in Santee Cooper’s 4 5% 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 Stati on.

The Company’s analysis indicates that the regional nuclear portfolio is lower cost to customers in the base case and in most scenarios. H owever, the full nuclear portfolio was chosen for the 2012 IRP preferred plan because ther e are no firm commitments in place at this time for the regional nuclear portfolio. Alth ough 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, includin g the results of the due diligence related to Summer, the capacity need at the time of the dec ision, and the financial implications of the purchase on the Company. Duke Energy Carolinas wil l 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 agre ements for new nuclear generation

resources.

The 2012 IRP also includes the Company’s plan for m eeting the requirements set forth in the Cliffside Unit 6 NCDAQ Air Permit (Cliffside Air Pe rmit). 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’ respec tive 2011 IRPs, the NCUC approved the Company’s proposed carbon neutrality plan as requir ed 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 a ctivities. With the incorporation of these updates, the Company’s proposed plan remains robust by projecting to eliminate approximately 9.2M tons of CO 2 , where the emission reduction requirement is appro ximately 5.3M tons to render Cliffside Unit 6 as carbon neut ral by 2018.

Duke Energy Carolinas has developed a sustainable s trategy to ensure that the Company can meet customers’ energy needs reliably and economica lly over the near and long term. The strategic action plan for long-term resources maint ains prudent flexibility in the face of uncertain and constantly evolving circumstances.13

Short Term Action Plan

The Company’s Short Term Action Plan, which identif ies accomplishments in the past year and actions to be taken over the next five years, i s 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 cap acity may include purchased power or generating capacity or Company-owned gener ation.

• Continue to evaluate and plan for the retirement of older coal generation. Buck Steam Station Units 3 and 4 were retired in May 201 1. 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 Ru le. Duke Energy Carolinas is also planning to retire all of its older CTs in Oct ober 2012.

• Continue to execute the Company’s EE and DSM plan, which includes a diverse portfolio of EE and DSM programs, and continue on-g oing 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 achi evements 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 Cyc le (CC) unit. The unit was operational November 2011. The 620 MW natural gas- fired CC generating station achieves high operational flexibility and high ther mal efficiency while utilizing stateof-the-art environmental control technology to mini mize 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 Steam14 Station. As of August 2012, the project was over 90 % complete.

• Continue to assess the conversion of Lee Steam Stat ion 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 ongo ing.

• Continue to pursue the option for new nuclear gener ating 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 Impac t Statement for the William States Lee III Nuclear plant in December 20 11, 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 reasonab le basis for planning.

 The Company plans to continue to support the NRC ev aluation of the COL. In March of 2012, the NRC issued a request for informa tion letter to operating power reactor licensees regarding recommendations o f the Near-Term Task Force review of insights from the Fukushima Dai-ich i accident. In April 2012, the NRC staff subsequently requested that Duke Ener gy update the W.S. Lee III (Lee) plant site-specific seismic analysis. This r equest impacted the schedule for NRC issuance of the Lee Combined Operating License, moving the projected Commercial Operation Date (COD) beyond the summer p eak 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 re gulatory approvals.

 The Company will continue to pursue available feder al, state and local tax incentives and favorable financing options at the f ederal and state level.

 The Company will continue to assess opportunities t o 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 g eneration and procure capacity, as appropriate. PPAs have been signed with develop ers of solar photovoltaic (PV), landfill gas, wind, and thermal resources. Addition ally, renewable energy certificate (REC) purchase agreements have been executed for pu rchases of unbundled RECs from wind, solar PV, solar thermal and hydroelectri c facilities.

• Continue to investigate the future environmental co ntrol requirements and resulting operational impacts associated with the Mercury MAC T rule, the CCR rule, the CSAPR rule and the new Ozone NAAQS and SO 2
.

• Continue to pursue existing and potential opportuni ties for wholesale power sales agreements within the Duke Energy Balancing Authori ty Area.

• Continue to monitor energy-related statutory and re gulatory activities.

A summarization of the capacity resource changes fo r 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.16



### 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 pl anning purposes, wind presents a 15% contribution t o 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 custo mers, Duke Energy Carolinas also sells wholesale electricity to incorporated municipalitie s 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 contrac ts and from the following electric generation assets:

• Three nuclear generating stations with a combined n et 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-sto rage facilities) with a combined capacity of 3,229 MW; and

• Nine combustion turbine stations (including one Com bined Cycle Station) with a combined capacity of 3,740 MW.

Duke Energy Carolinas’ power delivery system consis ts 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 uti lities: Progress Energy Carolinas, American Electric Power, Tennessee Valley Authority, Souther n Company, Yadkin, Southeastern Power Administration (SEPA), South Carolina Electri c and Gas, and Santee Cooper. These interconnections allow utilities to work together t o provide an additional level of reliability. The strength of the system is also reinforced throu gh coordination with other electric service providers in the Virginia-Carolinas (VACAR) sub-reg ion, 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.1819 B. Objectives

Duke Energy Carolinas has an obligation to provide reliable and economic electric service to its customers in North Carolina and Sout h Carolina. To meet this obligation, the Company conducted an integrated resource planni ng process that serves as the basis for its 2012 IRP.

The purpose of this IRP is to outline a robust stra tegy 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 con stantly adaptable to changing conditions. The IRP presented herein represents th e most robust and cost effective outcome based upon the Company’s analyses under var ious 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 ma ke 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 conside rs the costs and benefits to all stakeholders (customers, shareholders, employees, s uppliers, 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 p lan 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 p ortfolio.

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 function s:

• Developing planning objectives and assumptions.20 • Considering the impacts of anticipated or pending r egulations or events on existing resources (environmental, renewables, etc. ).

• Developing a regulatory construct to assess the imp act of potential CO 2 or Energy Policy legislation. More details of this ste p 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 concer ning 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 s upply-side options with the existing system and electric load forecast to devel op potential resource portfolios to meet the desired reserve margin crite ria. 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 (l owest net present value of costs) to customers over a wide range of alternativ e 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 por tfolio to minimize price and reliability risks to customers. More details concer ning this step of the process can be found in Chapter 8 and Appendix A.

The Company’s analytical methodology for resource p lanning includes the incorporation of sensitivity analysis of variables representing t he 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 a n average annual compound rate of 0.5% from 1996 to 2011, non-weather adjusted. The follo wing table shows historical and projected major customer class growth, at a compound annual r ate. 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 weat her 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 cla ss 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 exam ple, 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, howev er, the average growth was 30,000-35,000.

Duke Energy Carolinas’ total retail load growth ove r the planning horizon, 2012-2032, is driven by projected steady increases in the Residential, C ommercial and Other Industrial classes. Textiles, however, are projected to experience a sl ow 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 2,0 72 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 2,4 27 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 5,1 66 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 ne w contract agreements.

Wholesale Power Sales Commitments

Table 3.D on the following page contains informatio n concerning Duke Energy Carolinas’ wholesale contracts. The description ‘Full’ indicat es that Duke Energy Carolinas provides all of the needs of the wholesale customer. ‘Partial’ refe rs to those customers where Duke only provides some of the customer’s needs. ‘Fixed’ refe rs to a constant load shape. As a note, the values in Table 3.D are net of self-supplied genera tion.232012 2013 2014 2015 2016 2017 2018 2019 2020 2021Concord, NC Partial 2009-2018 181 180 184 187 190 192 195 198 201 204Dallas, NC Partial 2009-2028 11 11 11 12 12 12 12 12 13 13Due West, SC Partial 2009-2018 3 3 3 3 3 3 3 3 3 3Forest City, NC Partial 2009-2028 15 15 15 15 16 16 16 17 17 17Greenwood, SC Full 2010-2018 54 54 55 56 57 58 59 60 61 62Highlands, NC Full 2010-2029 8 8 8 8 8 8 8 8 8 9Kings Mountain, NC Partial 2009-2018 19 19 20 20 20 21 2121 22 22Lockhart Power Partial 2009-2018 54 54 55 56 57 57 58 59 6061Prosperity, SC Partial 2009-2028 2 2 2 2 2 2 2 2 3 3Western Carolina Full 2010-2021 6 6 6 6 6 6 6 6 6 6UniversityBlue Ridge EMC Full 2010-2031 224 227 230 234 238 242 246250 254 258Central EPC Partial 2013-2030 0 123 250 383 521 664 812 919 937 955Haywood EMC Full 2009-2021 20 20 20 20 21 21 21 22 22 22NCEMC Fixed 2009-2038 72 72 72 72 72 72 72 72 72 72Piedmont EMC Full 2010-2031 90 91 92 94 95 97 98 100 101 103PMPA* Backstand 2014-2020 0 0 47 47 47 47 47 47 47 47Rutherford EMC Partial 2010-2031 161 193 197 212 216 221226 230 235 240NCEMC* Backstand 1985-2043 95 95 116 116 116 116 116 116 116 116FERC Mitigation** Full 2012-2014 150 150 150 150Note: For Resource Planning purposes the contractsabove are assumed to renew through the end of the planning horizon, which is 2032.*Note: All backstand contracts represent the portion that Duke Energy Carolinas commitment.**Note: FERC Mitigation Sale represents the summerpeak MW - Sale begins July 3, 2012 and extends through February 28, 2015Customer Product TermCommitment (MWs)Table 3.DWholesale Contracts24

The Company’s Spring 2012 Forecast includes project ions of the energy needs of new future customers and current existing customers in Duke Energy Carolinas territory. Certain wholesale customers have the option of obta ining all or a portion of their future energy requirements from other suppliers. Although this may reduce Duke Energy Carolinas’ obligation to serve those customers, Duk e Energy Carolinas assumes for planning purposes that the contracts displayed in T able 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 p rovided in the pages named ‘Methodology 1’ and ‘Methodology 2’ of the Duke En ergy 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 ye ar period, including peak loads for summer and winter seasons of each year and annual e nergy forecasts, both with and without the impact of utility-sponsored energy effi ciency programs are shown below in
Tables 3.E and 3.F.

Load duration curves, with and without utility-spon sored 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 D uke 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 re tail and wholesale customer classes, which does not include the impact of new Duke Energ y 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 effici ency 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 s ummer 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 (a t 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 25,005 133,45326Chart 3.A-Load Duration Curves without Energy Efficiency27 Table 3.F Load Forecast with Energy Efficiency Programs (at G eneration)

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 23,740 124,46428Chart 3.B -Load Duration Curves with Energy Efficiency29

4. ENERGY EFFICIENCY AND DEMAND-SIDE MANAGEMENT

Current Energy Efficiency and Demand-Side Managemen t Programs

In May 2007, Duke Energy Carolinas filed its applic ation for approval of Energy Efficiency and Demand Side Management programs unde r its save-a-watt initiative. The Company received the final order for approval for t hese programs from the NCUC in July
2010 and from the Public Service Commission of Sout h Carolina (PSCSC) in May 2009.

Duke Energy Carolinas uses EE and DSM programs to h elp manage customer demand in an efficient, cost-effective manner. These program s 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 genera l, programs are offered in two primary categories: EE programs that reduce energy consump tion and DSM programs that reduce energy demand (demand-side management or demand res ponse 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 P rograms These programs can be dispatched by the utility and have the highest level of certainty. Once a customer agrees to participate in a demand r esponse 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 bil ling months of July through October in exchange for allowing Duke Energy Carolinas the right to cycle their central air conditioning systems and, additionally, to interrup t the central air conditioning when the Company has capacity needs.

Demand Response – Interruptible and Related Rate St ructures These programs rely either on the customer’s abilit y to respond to a utility-initiated signal requesting curtailment or on rates with price signa ls that provide an economic incentive to reduce or shift load. Timing, frequency and nat ure of the load response depend on customers’ actions after notification of an event o r 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 s pecified levels upon request by Duke Energy Carolinas. If customers fail to do so durin g an interruption, they receive a penalty for the increment of demand exceeding the s pecified 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 Energ y Carolinas. The generators in this program do not operate in parallel with the Du ke Energy Carolinas system and therefore, cannot “backfeed” (i.e., export power) i nto the Duke Energy Carolinas system. Participating customers receive payments f or capacity and/or energy, based on the amount of capacity and/or energy transferred to their generators.

• PowerShare ® is a non-residential curtailment program consistin g of four options: an emergency only option for curtailable load (PowerSh are® Mandatory), an emergency only option for load curtailment using on-site gene rators (PowerShare® Generator), an economic based voluntary option (PowerShare® Vol untary), and a combined emergency and economic option that allows for incre ased notification time of events (PowerShare® CallOption).

• PowerShare® Mandatory: Participants in this emerge ncy only option will receive capacity credits monthly based on the amoun t 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 eligi ble to earn additional
credits.

• PowerShare® Generator: Participants in this emerge ncy only option will receive capacity credits monthly based on the amoun t of load they agree to curtail (i.e. transfer to their on-site generator) during utility-initiated emergency events and their performance during month ly test hours. Participants also receive energy credits for the lo ad curtailed during events.

• PowerShare® Voluntary: Enrolled customers will be notified of pending emergency or economic events and can log on to a We b 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 poste d energy credit for load
curtailed.

• PowerShare® CallOption: This DSM program offers a participating customer the ability to receive credits when the customer ag rees, at the Company’s request, to reduce and maintain its load by a minim um of 100 kW during Emergency and/or Economic Events. Credits are paid for the load available for curtailment, and charges are applicable when th e customer fails to reduce load in accordance with the participation option it has selected. Participants31 are obligated to curtail load during emergency even ts. 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 an d set a limit for Economic Events to 0, 5, 10 and 15 respectively.

• Rates using price signals

• Residential Time-of-Use (including a Residential Wa ter Heating rate) This category of rates for residential customers incorporates differential seasonal and time-of-day pricing that encourages cu stomers 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 h eating electricity use.

• General Service and Industrial Optional Time-of-Use rates This category of rates for general service and indu strial customers incorporates differential seasonal and time-of-day pricing that encourages customers to use less electricity during on-peak ti me periods and more during off-peak periods.

• Hourly Pricing for Incremental Load This category of rates for general service and indu strial customers incorporates prices that reflect Duke Energy Caroli nas’ estimation of hourly marginal costs. In addition, a portion of the cust omer’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 educa tion or incentive programs. Energy and capacity savings are achieved by changing custo mer behavior or through the installation of more energy-efficient equipment or structures. All effects of these existing programs are reflected in the customer load forecas t. 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 Energ y House Call.

The PER program is a residential energy efficiency program that provides single family home customers with a customized report abou t their home and family and32 how they use energy. In addition, the customer rec eives compact fluorescent lights (CFLs) as an incentive to participate in the program.

The PER program requires customers to provide infor mation about their home, number of occupants, equipment and energy usage and has two variations:

• A mailed offer where customers are asked to complet e an included energy survey and mail it back to Duke Energy or complete the same survey online. Customers mailing the energy survey receiv e their PER in the mail and those completing it online receive their P ER online as a printable
PDF document.

• An online offer to our customers that have signed i nto Duke Energy’s Online Services (OLS) bill pay and view environment . Online participants complete their energy survey online ge t their PER online as a printable PDF.

Home Energy House Call (HEHC) is a free in-home ass essment designed to help our customers learn about home energy usage and how to save on monthly bills. The program provides personalized information uniqu e to the customer's home and energy practices. An energy specialist visits t he 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 insula tion levels, review appliances, help the customer preserve the environment for the future and keep electric costs low. A customized report is prepared, explaining t he steps the customer can take to increase efficiency. As a part of the Home Energ y House Call program, customers receive an Energy Efficiency Starter Kit. At the request of the customer, the energy specialist can install the eff iciency items to allow the customer to begin saving immediately.

• Low Income Energy Efficiency and Weatherization Pro gram The purpose of this program is to assist low income residential customers with energy efficiency measures to reduce energy usage t hrough energy efficiency kits or through assistance in the cost of energy efficie nt 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 cu rriculum provided to public and private schools. This curriculum includes less on plans, energy efficiency33 materials, and energy audits.

• Residential Smart $aver® Energy Efficient Products Program The Smart $aver ® Program provides incentives to residential custome rs who purchase energy-efficient equipment. The program h as 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 fi xtures 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 rep ly cards and a web-based ondemand ordering tool where CFLs were shipped direct ly to the customer’s home.

Heating Ventilation & Air Conditioning (HVAC) and Heat Pump The residential air conditioning program provides i ncentives to customers, builders, and heating contractors (HVAC dealers) to promote the use of highefficiency air conditioners and heat pumps. The pr ogram is designed to increase the efficiency of air conditioning systems in new h omes and for replacements in existing homes.

Tune and Seal Measures (Approved in South Carolina only) Partnering with HVAC dealers, the program pays ince ntives 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 we re included in the analysis of generation needs.

• Residential Neighborhood Program Program that targets low income neighborhoods provi ding high impact direct install measures (CFLs, pipe and water heater wrap, low flow aerators and showerheads, HVAC filters and air infiltration seal ing) and energy efficiency education. Projected impacts of this program were i ncluded in the analysis of generation needs.

• Appliance Recycling Program (Approved in South Caro lina only) This is a program to incentivize households to remo ve 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 o nly) The purpose of this program is to provide comparati ve usage data for similar residences in the same geographic area to motivate customers to better manage and reduce energy usage. The program assists reside ntial customers in assessing their energy usage and provides recommendations for more efficient use of energy in their homes. The program also helps to id entify those customers who could benefit most by investing in new energy effic iency measures, undertaking more energy efficient practices and participating i n Duke Energy programs.

• Smart $aver® for Non-Residential Customers The purpose of this program is to encourage the ins tallation of high-efficiency equipment in new and existing non-residential estab lishments. The program provides incentive payments to offset a portion of the higher cost of energyefficient equipment. The following types of equipm ent are eligible for incentives as part of the Prescriptive program: high-efficien cy lighting, high-efficiency air conditioning equipment, high-efficiency motors, hig h-efficiency pumps, variable frequency drives, food services and process equipme nt. Customer incentives may be paid for other high-efficiency equipment as dete rmined by the Company to be evaluated on a case-by-case basis through the Custo m program.

The projected impacts from these programs are inclu ded 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 targ eted 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 e ssentially in the same manner as the Company’s other CallOption offers. However, cu stomers who participate will experience considerably more requests for load curt ailment for economic purposes. Participants will remain obligated to cu rtail load during up to 5 emergency events.

The following pilot programs have been approved:

• Residential Retrofit This program was approved in North Carolina in Dock et E-7, Sub 952 on January 25, 2011. The Residential Retrofit program is desi gned to assist residential35 customers in assessing their energy usage, to provi de recommendations for more efficient use of energy in their homes and to encou rage the installation of energy efficient improvements by offsetting a portion of t he cost of implementing the recommendations from the assessment. Projected impa cts of this pilot program were included in the Company’s analysis of generati on needs.

• Smart Energy Now (SEN) The SEN pilot program was approved by the NCUC in D ocket E-7, Sub 961 on February 14, 2011 and is designed to reduce energy consumption within the commercial office space located in Charlotte City C enter through community engagement leading to behavioral modification. In order to enable building managers and occupants to effectively make these be havioral modifications, they will be provided with additional energy consumption information and actionable efficiency recommendations. Projected impacts of t his 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 de signed for home owners with broadband internet service. The product offers energy efficiency and demand response benefits through a Wi-Fi enabled thermosta t that will manage a customer’s air conditioning system by providing sch edules, modes (such as home/away/vacation), energy savings tips, messages, and alerts. The customer will have the tools to access and control their the rmostat 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 de mand response events. Overall, this product will provide simple, intuitive, and ef fective 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 h ave not yet been developed. Estimates of the impacts of these yet-to-be-develop ed 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 c osts, benefits, and risks of DSM and EE programs and measures. DSMore is a financia l 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 exami ning projected program performance and cost effectiveness over a wide variety of weath er and cost conditions, the Company is in a better position to measure the risks and benef its of employing DSM and EE measures versus traditional generation capacity additions, a nd 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 m anagement cost-effectiveness has traditionally focused primarily on the calculation of specific metrics, often referred to as the California Standard tests: Utility Cost Test (U CT), Rate Impact Measure (RIM) Test, Total Resource Cost (TRC) Test, and Participant Tes t (PCT). DSMore provides the results of those tests for any type of EE or DSM pr ogram.

• The UCT compares utility benefits (avoided costs) t o the costs incurred by the utility to implement the program, and does not cons ider 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 avoid ed costs (to the utility) resulting from the change in magnitude and/or the p attern 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-effectiven ess analyses also incorporate avoided transmission and distribution costs, and lo ad (line) losses.

• The RIM Test, or non-participants test, indicates i f rates increase or decrease over the long-run as a result of implementing the progra m.

• The TRC Test compares the total benefits to the uti lity and to participants relative to the costs to the utility to implement the progra m along with the costs to the participant. The benefits to the utility are the s ame 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 in centives or rebates are not included in the TRC.37

• The Participant Test evaluates programs from the pe rspective of the program’s participants. The benefits include reductions in ut ility bills, incentives paid by the utility and any state, federal or local tax benefit s received.

The use of multiple tests can ensure the developmen t of a reasonable set of DSM and EE programs and indicate the likelihood that customers will participate.

Energy Efficiency and Demand-Side Management Progra ms

Duke Energy Carolinas has made a strong commitment to EE and DSM. The Company recognizes EE and DSM as a reliable, valuable resou rce 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 electri city, less cost and less environmental impact. The Company will manage EE and DSM to prov ide customers with universal access to these services and new technology. Duke Energy Carolinas has the expertise, infrastructure, and customer relationships to produ ce 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 innovat ive EE programs for the benefit of its

customers.

In 2011, Duke Energy commissioned an independent Ma rket Potential Study for both the North Carolina and South Carolina service territori es. This study was prepared by Forefront Economics Inc. and was completed in Decem ber of 2011. The results of this Market Potential Study were incorporated into the E nergy Efficiency forecasts included in the 2012 IRP.

The Duke Energy Carolinas’ approved EE plan is cons istent 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 res ults of ongoing collaborative workshops and appropriate regulatory treatment. Fo r 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, in cluding line losses, by approximately 1,159,000 MWh and have added the capa bility to reduce the Summer Peak by over 800 MW. However, pursuing EE and DSM init iatives will not meet all growing demands for electricity. The Company still envisio ns 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 Carolina s could address approximately half of the Company’s projected 2016 new resource n eed, if such programs perform as expected.38

Table 4.A provides the base case projected load imp acts 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 g row 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 r eductions associated with EE programs that have been added since the inception o f 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 M W capacity projections have increased from last year due to stronger projected growth in the PowerShare® programs.

The projected total annual MWh load reductions asso ciated with EE programs included in this base case are more than 10% higher than tho se included in the 2011 IRP base case, primarily due to updated expectations of the perfor mance 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 achievement s, including actual achievements since 2009, by 2023 that were projected to be achie ved 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 c ase represents a significant increase in the amount of EE and DSM impacts that are modele d, consistent with the Company’s merger settlement, under which the Company will asp ire to more aggressive cumulative EE achievement over the period 2014-2018 2 and annual incremental achievement beginning in 2015 of 1% of prior year retail electr icity sales. The impacts in this high case are assumed to level off after 2031 because th e projection reaches the theoretical economic potential as determined in the Market Pote ntial Study completed in 2011. However, Duke Energy Carolinas is committed to ongo ing efforts to add incremental savings to the extent they are cost effective and c ustomers embrace those measures. For DSM programs, the load impacts are increased to ref lect higher participation projections in the Company’s demand response programs.

The level of energy efficiency impacts are not ulti mately the decision of the Company. Driven by the structure of cost recovery and incent ive 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 participati on decisions based on a variety of

2 The Duke-Progress merger commitment regarding ener gy 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 Com pany models the base EE/DSM case assuming limited customer participation until the r ate of program adoption is confirmed. The high EE/DSM case reflects more aggressive progr am achievements consistent with the merger settlement.

Table 4.C incorporates December 31, 2011 participat ion levels for all demand response programs and the capability of these programs proje cted for the summer of 2012.

Table 4.A Load Impacts of EE and DSM Programs – Bas e 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 Progra ms40

Table 4.B Load Impacts of EE and DSM Programs – Hig h 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 MW41

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 perf ormed 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 perspec tive of demand response programs.

Grid Modernization – Duke Energy is pursuing implem entation of grid modernization throughout the enterprise. The recent $200 million grant awarded to Duke Energy from the US DOE helps further that goal. Grid moderniza tion 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 g oals, the NCUC proposed a requirement to include grid modernization impacts i n the IRP for North Carolina electric utilities (including Duke Energy Carolinas) in Dock et 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 81442

utility provide information regarding the impacts o f 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 IR P results in a corresponding 40 MW decrease in customers’ capacity needs by 2015. Ove r 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 N CUC 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 g rid technology plan is not required to be filed. Duke Energy Carolinas will comply wi th 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 include s 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 obliga tion to serve its customers. Duke Energy Carolinas owned generation, as well as purch ased power, is evaluated on a realtime basis in order to select and dispatch the lowe st-cost resources to meet system load requirements. In 2011, Duke Energy Carolinas’ nucl ear and coal-fired generating units met the vast majority of customer needs by providin g 52.2% and 45.7%, respectively, of Duke Energy Carolinas’ energy from generation. Hydr oelectric generation, CT generation, solar generation, long term PPAs, and e conomical purchases from the wholesale market supplied the remainder.

Existing Resources

The tables below list the Duke Energy Carolinas pla nts 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 Coa l Buck 6 128.0 131.0 Salisbury, N.C. Conventional Coa l Buck Steam Station 256.0 262.0 Cliffside 5 552.0 556.0 Cliffside, N.C. Conventiona l Coal Cliffside Steam Station 552.0 556.0 Marshall 1 380.0 380.0 Terrell, N.C. Conventional C oal Marshall 2 380.0 380.0 Terrell, N.C. Conventional C oal Marshall 3 658.0 658.0 Terrell, N.C. Conventional C oal Marshall 4 660.0 660.0 Terrell, N.C. Conventional C oal 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. Conventiona l Coal Riverbend 7 133.0 136.0 Mt. Holly, N.C. Conventiona l 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-F ired Combustion Turbine Buck 9C 12.0 15.0 Salisbury, N.C. Natural Gas/Oil-F ired Combustion Turbine Buck Station CTs 62.0 75.0 Dan River 4C 0.0 0.0 Eden, N.C. Natural Gas/Oil-Fir ed Combustion Turbine Dan River 5C 24.0 31.0 Eden, N.C. Natural Gas/Oil-F ired45

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-F ired Combustion Turbine Dan River Station CTs 48.0 62.0 Lincoln 1 79.2 93.0 Stanley, N.C. Natural Gas/Oil-F ired Combustion Turbine Lincoln 2 79.2 93.0 Stanley, N.C. Natural Gas/Oil-F ired Combustion Turbine Lincoln 3 79.2 93.0 Stanley, N.C. Natural Gas/Oil-F ired Combustion Turbine Lincoln 4 79.2 93.0 Stanley, N.C. Natural Gas/Oil-F ired Combustion Turbine Lincoln 5 79.2 93.0 Stanley, N.C. Natural Gas/Oil-F ired Combustion Turbine Lincoln 6 79.2 93.0 Stanley, N.C. Natural Gas/Oil-F ired Combustion Turbine Lincoln 7 79.2 93.0 Stanley, N.C. Natural Gas/Oil-F ired Combustion Turbine Lincoln 8 79.2 93.0 Stanley, N.C. Natural Gas/Oil-F ired Combustion Turbine Lincoln 9 79.2 93.0 Stanley, N.C. Natural Gas/Oil-F ired 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/Oi l-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 Turbine46

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 G as/Oil-Fired Combustion Turbine Rockingham 2 165.0 165.0 Rockingham, N.C. Natural G as/Oil-Fired Combustion Turbine Rockingham 3 165.0 165.0 Rockingham, N.C. Natural G as/Oil-Fired Combustion Turbine Rockingham 4 165.0 165.0 Rockingham, N.C. Natural G as/Oil-Fired Combustion Turbine Rockingham 5 165.0 165.0 Rockingham, N.C. Natural G as/Oil-Fired Combustion Turbine Rockingham CTs 825.0 825.0 Buck CT11 165.0 170.0 Salisbury, N.C. Natural Gas C T Combined Cycle Buck CT12 165.0 170.0 Salisbury, N.C. Natural Gas C T Combined Cycle Buck ST10 290.0 300.0 Salisbury, N.C. Natural Gas C T 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. Hydro47

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. Hydro48

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

MW49

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 G as/Oil-Fired Combustion Turbine Buzzard Roost 7C 20.0 20.0 Chappels, S.C. Natural G as/Oil-Fired Combustion Turbine Buzzard Roost 8C 20.0 20.0 Chappels, S.C. Natural G as/Oil-Fired Combustion Turbine Buzzard Roost 9C 20.0 20.0 Chappels, S.C. Natural G as/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 Turbine50

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 42.051

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. Hydro52

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 environmenta l emission controls.

Note c: Summer and winter capability reflects syst em configuration as of April 4, 2012.

Note d: Catawba Units 1 and 2 capacity reflects 10 0% 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 the ir 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 up rates 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 i ts load obligation. Thus, Duke Energy Carolinas will need to adjust the capabiliti es of its resource mix over the 20-year planning horizon. Below are the known and/or antic ipated 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 cap ability. 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 (CTC C) unit was operational November 2011. The 620 MW natural gas-fired CTCC g enerating station achieves high operational flexibility, high thermal efficiency, u tilizing 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 ope rational by the end of 2012. Construction is underway and the project is current ly over 90% complete.

Lee Steam Station Natural Gas Conversion Lee Steam Station was originally designed to genera te with natural gas or coal as a fuel source. Switching fuel sources from coal to natura l gas could prove to be an economic solution to avoid adding costly pollution control e quipment 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 eva luation, for IRP planning purposes, Lee Units 1 and 2 will be retired as coal units wit h 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. P reliminary engineering and analysis has been completed. Detailed project development a nd 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 reti re existing generating units. These factors, including the investment requirements nece ssary to support ongoing operation of generation facilities, are continuously evaluated a s future resource needs are considered. Table 5.D reflects current assessments of generatin g 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 th e NCUC Order in Docket No. E-7, Sub 790, granting a CPCN to build Cliffside Unit 6, req uires the retirement of the existing Cliffside Units 1-4 no later than the commercial op eration 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 reli ability 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 unit 3 . 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 uni t 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 iss ues are presently converging as the EPA has proposed new rules to regulate multiple are as 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 gene ration in the 2014 to 2018 timeframe. Anticipating that there will be increased control r equirements, the Carolinas 2012 IRP continues to include a planning assumption that all coal-fired generation that does not have an installed SO 2 scrubber will be retired in 2015.

Table 5.D shows the assumptions used for planning p urposes rather than firm commitments concerning the specific units to be ret ired and/or their exact retirement dates. The conditions of the units are evaluated a t least annually and decision dates are revised as appropriate. Duke Energy Carolinas will develop orderly retirement plans that consider the implementation, evaluation, and achiev ement of EE goals, system reliability considerations, long-term generation maintenance an d capital spending plans, workforce allocations, long-term contracts including fuel sup ply and contractors, long-term transmission planning, and major site retirement ac tivities.

3 NCUC Docket No. E-7, Sub 790 Order Granting CPCN w ith 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 Coa l Buck 4* 38 Salisbury, N.C. RETIRED Conventional Coa l Cliffside 1* 38 Cliffside, N.C. RETIRED Conventiona l Coal Cliffside 2* 38 Cliffside, N.C. RETIRED Conventiona l Coal Cliffside 3* 61 Cliffside, N.C. RETIRED Conventiona l Coal Cliffside 4* 61 Cliffside, N.C. RETIRED Conventiona l Coal Dan River 1* 67 Eden, N.C. RETIRED Conventional Coa l Dan River 2* 67 Eden, N.C. RETIRED Conventional Coa l Dan River 3* 142 Eden, N.C. RETIRED Conventional Co al 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 condi tions 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 da tes were accelerated in 2009 based on derates, availability of replacement parts and the general c ondition 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 regula tory scrutiny from an air, water and waste perspective, these units will likely either be requ ired 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 dat e may be adjusted. For example, per the MATS rule, if new generation will be located at a retire d facility site, the retirement of the existing fac ility may be extended to 4/15/2016.

**** Analysis has been performed to determine the f easibility 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 ge neration, but natural gas has begun to play a more important role in the fuel mix due to l ower pricing and the addition of the Buck Combined Cycle plant. The addition of the Da n River Combined Cycle plant later this year will further increase the importance of g as to the Company’s generation portfolio.

Coal Until the economic downturn in 2008, Duke Energy Ca rolinas had burned approximately 18 million tons of coal annually. In 2009, the bur n dropped substantially and has remained in the range of 14 to 16 million tons of c oal. The projected coal burn for the near-term is declining further due to lower gas pri ces, the addition of the Buck CC plant, more stringent environmental regulations on coal un its, and lower load growth.

The Company continues to procure coal primarily fro m Central Appalachian (CAPP) coal mines that is delivered by the Norfolk Souther n 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 result ing 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 CAP P reserves quality, increasingly stringent safety requirements, and longer and incre asingly difficult environmental permitting for CAPP mines.

For this reason, the Company has been testing North ern 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 an d environmental impacts of burning these coals in various blends. This information wil l assist the Company in determining which coal blends can be burned without requiring a dditional capital investment, as well57

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 th at the Company can nimbly respond to changes in the relative coal prices of different co al types.

Natural Gas The issues affecting natural gas supply and demand are numerous and complex. An unusually warm winter has resulted in oversupply wi thin the US gas market. Actions and reactions associated with attempts to bring this ma rket 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 industria l production costs, boost manufacturing output and demand for power, producer s 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 reserv e basis has increased due to significant gains in rig efficiency, improvements in wellhead p roductivity, and several other factors. Among these is the fact that gas is also being prod uced 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 hig her. Once again, the US is on course to set another record in total marketed US producti on of natural gas. These market responses have managed to stabilize the wholesale g as prices at around $2.50 - $3.00/mmbtu for now, and they are not likely to pus h prices significantly higher in the near term. Substantial producer discipline going fo rward 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 innov ation in the face of high marginal domestic gas prices and the threat of a future mark ed by a globally linked and high volatile liquefied natural gas (LNG) pricing. Toda y, 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 su bsidies and fueling infrastructure, and preparations for exportation of LNG are coupled wit h 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 fleet s. They cannot simply defer these decisions either, as various environmental deadline s 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 displ acement projections will soon become reality as utilities retire existing uncontr olled coal facilities instead of installing emissions controls. Natural gas has become the def ault option for new generation.

While the US has ample economic gas reserves for at least the next two decades, natural58

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 decisio ns 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 reg ulations 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 th ey become game changers. A significant price on carbon in the US has the potential to chan ge the equation, but these indications are not currently on the horizon. Shale has alread y 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 downst ream services supply contracts from
around the world.

Requirements for uranium concentrates, conversion s ervices and enrichment services are primarily met through a portfolio of long-term supp ly contracts. The contracts are diversified by supplier, country of origin and pric ing. In addition, Duke Energy Carolinas staggers its contracting so that its port folio of long-term contracts covers the majority of fleet fuel requirements in the near-ter m and decreasing portions of the fuel requirements over time thereafter. By staggering l ong-term contracts over time, the Company’s purchase price for deliveries within a gi ven year consists of a blend of contract prices negotiated at many different period s in the markets, which has the effect of smoothing out the Company’s exposure to price vo latility. Diversifying fuel suppliers reduces the Company’s exposure to possible disrupti ons from any single source of supply. Near-term requirements not met by long-ter m supply contracts have been and are expected to be fulfilled with spot market purchases

.

Due to the technical complexities of changing suppl iers of fuel fabrication services, Duke Energy Carolinas generally sources these services t o 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-pri ced legacy contracts are replaced with contracts at higher market prices, nuclear fuel exp ense is expected to increase in the future. Although the costs of certain components o f 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 per formance of its nuclear fleet through lower fuel costs than would otherwise resul t absent the significant contribution of59

nuclear generation to meeting customers’ demands.

B. Renewable Resources and Renewable Energy Initia tives

1. Overview of Planning Assumptions

Duke Energy Carolinas’ plans regarding renewable en ergy resources within this IRP are based primarily upon the presence of existing r enewable energy requirements, as well as the potential introduction of additional re newable energy requirements in the future.

Regarding existing renewable requirements, the Comp any is committed to meeting the requirements of the NC REPS. This is a statutory r equirement enacted in 2007 mandating that Duke Energy Carolinas supply the equ ivalent of 12.5% of retail electricity sales in North Carolina from eligible r enewable energy resources and/or EE savings by 2021. NC REPS allows for compliance uti lizing not only renewable energy resources supplying bundled energy and renewable en ergy certificates (RECs) and EE, but also the purchase of unbundled RECs (both in-st ate and out-of-state) and thermal RECs. Therefore, the actual energy delivered to th e Duke Energy Carolinas system is impacted by the amount of EE, unbundled RECs and th ermal RECs utilized for compliance.

With respect to potential new renewable energy port folio standard requirements, the Company’s plans in this IRP account for the possibi lity of future requirements that will result in additional renewable resource development beyond the NC REPS requirements. Renewable requirements have been ado pted in many states across the nation, and have also been contemplated as a federa l measure and by members of the General Assembly in South Carolina. As such, the C ompany believes it is reasonable to plan for additional renewable requirements withi n 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 addi tional renewable resource development in South Carolina. For planning purpos es, Duke Energy Carolinas has assumed that the requirement would be similar in ma ny respects to the NC REPS requirement, but with a different implementation sc hedule. Specifically, the Company has assumed that this requirement would have an ini tial 3% milestone in 2016 and would gradually increase to a 12.5% level by 2025. Similar to NC REPS, this assumed60

legislative requirement would incorporate both rene wable energy and EE, as well as a limited capability to utilize out of state unbundle d purchases of RECs. Further, this assumed requirement would have a solar set-aside re quirement comparable to that in NC REPS, but would not contain any additional set-a sides 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 develo pment of renewables and ultimate cost to customers were made with this assumed legislatio n, whereas the Company’s projections of renewable resource development for N C 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 analysi s, the IRP modeling process shows that, for the most part, the amount of renewable en ergy resources that will be developed over the planning horizon will be defined by the ex isting and anticipated statutory renewable energy requirements described above. In other words, the IRP modeling does not indicate any material quantity of renewabl e 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 t hese incentives has been incorporated into the IRP modeling.

2. Summary of Expected Renewable Resource Capacity Additions

Based on the planning assumptions noted above regar ding 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 g rowing to approximately 1,665 MWs by the end of the planning horizon in 2032. Ac tual results could vary substantially, with key drivers of different outcom es being future legislative requirements; relative costs of various renewable t echnologies in relation to traditional technologies; and various impediments impacting res ource development, including permitting requirements, transmission and interconn ection 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 en ergy or capacity benefits to the Company’s load requirements at any particular point in time. The details of the forecasted capacity additions, including both namep late 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 ene rgy requirements (existing and anticipated) included in the 2012 IRP are largely s imilar to the assumptions within the Company’s 2011 IRP. However, the Company’s expecta tions regarding how those requirements will be met have evolved. Changes fro m the prior year are summarized
below.

As compared to last year’s IRP, the Company has ass umed the development and interconnection of more solar resources over the pl anning horizon, along with corresponding reductions in the development of wind and biomass resources.

The installed cost of solar resources has fallen dr amatically over the past few years, driven by increased industry scale, standardization , and technological innovation. Many industry participants expect the cost of solar to c ontinue a steady decline through the end of the decade, albeit at a slower pace than in rece nt 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 Nameplate62

middle of this decade or longer. In combination wi th declining costs, such supportive policies have made solar resources increasingly com petitive with other renewable resources, including wind and biomass, at least in the near-term. While uncertainty remains around possible alterations or extensions o f policy support, as well as the pace of future cost declines, the Company fully expects sol ar resources to contribute to our RPS compliance efforts beyond the solar set-aside minim um 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. Th e Company believes it is reasonable to expect that land-based wind will be developed in bo th 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 t he end of 2012. Although the Company expects to rely upon wind resources for our RPS com pliance effort, the extent and timing of that reliance will likely vary commensurately wi th changes to supporting policies and prevailing market prices. The Company also has obs erved that opportunities currently exist, and may continue to exist, to transmit land- based wind energy resources into the Carolinas from other regions, which could supplemen t the amount of wind that could be developed within the Carolinas.

The Company’s expectations regarding biomass resour ces for the 2012 IRP are more modest than its assumptions within its prior two IR Ps. 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 Car olinas, uncertainties related to the EPA’s various rulemaking proceedings, and the proje cted availability of other forms of renewable resources to offset the needs for biomass

.

The changes in the renewable strategy discussed abo ve 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 res ources, the projected increase in volume of solar facilities results in a net increas e of renewable resources available to meet peak demand requirements in 2015 of approximat ely 40 MW.

In general, the Company expects a mix of resources will ultimately be used for RPS compliance, with the specifics of that mix determin ed 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. Further more, the Company values portfolio diversification from a resource perspective, partic ularly 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 t o 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 s eparate 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 impact s on the amount of energy and capacity that the Company projects to obtain from r enewable 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 utiliz e 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 procuremen t or development. Each of these features of NC REPS has implications on the a mount of renewable energy and capacity the Company forecasts to obtain over the p lanning horizon of this IRP. Additional details on NC REPS compliance can be fou nd in the Company’s Compliance Plan.

C. Supply-Side Resource Screening

For purposes of the 2012 IRP, the Company considere d a diverse range of technology choices utilizing a variety of different fuels, inc luding supercritical pulverized coal (SCPC) units with carbon capture and sequestration (CCS), Integrated Gasification Combined Cycle (IGCC) with carbon capture and seque stration, 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 sc reened technology types within their own respective general categories of base loa d, peaking/intermediate, and renewable, with the ultimate goal of screening to p ass 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 evaluat ion is necessary to narrow down options to be further evaluated in the quantitative analysi s process.64 1. Process Description

Information Sources The cost and performance data for each technology b eing screened is based on research and information from several sources. These source s include, but may not be limited to the following: Duke Energy’s New Generation Projec t 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 param eters for installation in the Carolinas.

Finally, every effort is made to ensure that cost a nd 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 mater ials, and manufactured equipment, remains very difficult.

Technical Screening The first step in the Company’s supply-side screeni ng process for the IRP is a technical screening of the technologies to eliminate those th at 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 suit able geothermal resources in the region to develop into a power gen eration project.

• Advanced energy storage technologies (Lead acid, Li -ion, Sodium Ion, Zinc Bromide, Fly wheels, pumped storage, etc) remain re latively expensive, as compared to conventional generation sources, but th e benefits to a utility such as the ability to shift load and firm renewable gen eration are obvious. Research, development, and demonstration continue w ithin Duke Energy Corporation (Duke Energy). Currently, Duke Energy Generation Services is installing a 36 MW advanced acid lead battery at th e 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 dem onstration in Charlotte, which includes two Community Energy Storage (CES) s ystems of 24 kW, and65 three substation demonstrations less than 1 MW each

.

• Compressed Air Energy Storage (CAES), although demo nstrated on a utility scale and generally commercially available, is not a widely applied technology and remains relatively expensive. The h igh capital requirements
for these resources arise from the fact that suitab le sites that possess the proper geological formations and conditions necessa ry 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. De partment of Energy (DOE) solicited bids for companies to participate in a sm all 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 gran t is the first-of-a-kind engineering associated with NRC design certificatio n and licensing efforts in order to demonstrate the ability to achieve NRC des ign certification and licensing to support SMR plant deployment on a dome stic site by 2022.

• Fuel Cells, although originally envisioned as being a competitor for combustion turbines and central power plants, are n ow 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 app lication to niche markets and/or subsidized installations. While a medium le vel of research and development continues, this technology is not comme rcially available for utility-scale application.

• Poultry waste and Swine waste digesters remain rela tively expensive and are often faced with operational and/or permitting chal lenges. 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 us e of these technologies.

• Off-shore wind, although demonstrated on a utility scale and commercially available, is not a widely applied technology and n ot easily permitted. This technology remains expensive and has yet to actuall y be constructed anywhere in the United States. Currently, the Cape Wind pro ject in Massachusetts has been approved with assistance from the federal gove rnment but has not begun construction.66 • Although commercially available, a 3x3x1 1200 MW na tural gas combined cycle unit was modeled as sensitivity. The 2x2x1 7 00 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 fu el prices for coal and natural gas, and
NO x , SO 2 , and CO 2 allowance prices as those utilized downstream in t he 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 scree ning within each general class, as well as the final screening across the general classes u ses a spreadsheet-based screening curve model developed by Duke Energy. This model is cons idered proprietary, confidential and competitive information by Duke Energy.

This screening curve analysis model includes the to tal 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 te chnology to be screened resulting in a family of lines (curves). The lower envelope alo ng the curves represents the least costly supply options for various capacity factors or unit utilizations. Some technologies have screening curves limited to their expected ope rating 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 cos t solution, and generally can be eliminated from further analysis.

2. Screening Results The results of the screening within each category a re shown in Appendix C.

In the quantitative analysis phase, the Company fur ther evaluates those technologies from each of the three general categories screened (Base load, Peaking/Intermediate, and Renewables) which had the lowest levelized busbar c ost 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 in cluded 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 increa sed 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 gener ally 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 whet her a resource is economical depends on the economics of an overall resource plan that c ontains all costs associated with that resource (fuel costs, O&M costs, emission costs, et c.), 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 selec ted as part of a least cost plan, joint ownership can and may be evaluated and pursued.

4. Cost, Availability, and Performance Uncertaint y 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 resour ces to confirm the reasonableness of68

the estimates. The cost estimates include step-up transformers and a substation to connect with the transmission system. Since any ad ditional transmission costs would be site-specific and specific sites are unknown at thi s time, typical values for additional
transmission costs were also added to the alternati ves. For natural gas units, gas pipeline costs were also included in the cost estimates. Th e unit availability and performance of conventional supply-side options are also relativel y well-known and the TAG®, A&E firms and/or equipment vendors are sources of estim ates of these parameters.

5. Lead Time for Construction The estimated lead time for construction and permit ting for modeling purposes for the proposed simple-cycle CT and combined cycle units i s four to five years. For coal units, the lead time is assumed to be longer, approximatel y five to six years. For nuclear units, the lead time is assumed to be twelve to thirteen y ears or longer. However, the time required to obtain regulatory approvals and environ mental permits adds uncertainty to the process, so Company judgment is incorporated into t he analysis, as necessary.

6. RD&D Efforts and Technology Advances New energy and technology alternatives will be nece ssary to ensure a long-term sustainable electric future. Duke Energy Carolinas ’ research, development, and delivery (RD&D) activities enable Duke Energy Carolinas to t rack new options including small modular nuclear reactors, advanced CTs, advanced fo ssil technologies, distributed energy sources, and energy storage technologies. To assur e a strategic advantage in electricity supply and delivery, the Company places emphasis on providing information, assessment tools, validated technology, demonstration/deployme nt support, and RD&D investment opportunities for planning and implementing project s 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 engin e efficiency and power density, as well as expanding research efforts to burn more hyd rogen-rich fuels derived from the IGCC process. The ability to burn hydrogen-rich fu els will enable very high levels of
CO 2 removal, thereby enabling a major portion of the a dvancement necessary for a significant reduction in the carbon footprint of th is coal-based technology.

Duke Energy Carolinas is evaluating more natural ga s-fueled new generation because of the increase in available fuel sources, such as sha le 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 resou rces. 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 gro ups have been evaluating various means of capturing carbon from natural gas fired ge neration through post-combustion capture and oxy-fuel combustion technologies. Thro ugh its partnerships with governmental agencies, non-governmental agencies, a cademia, and other companies, Duke Energy Carolinas is evaluating the technical a nd economic impacts of adding such systems to its existing and future generation. Wit h 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 whet her 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 achie ved through purchases and sales in the bulk power market.

D. Wholesale and QF Purchased Power Agreements

Duke Energy Carolinas is an active participant in t he 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 wi th a growing number of Qualifying Facilities (QF or QFs). Table 5.F shows both the p urchased 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 f rom suppliers and marketers are an important resource option for meeting the electrici ty 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 12/31/203 1 Davidson Gas Producers, LLC Lexington NC 1.6 1.6 12/1/20 10 12/31/2030 Gas Recovery Systems, LLC Concord NC 3 4 2/1/2010 12/31/2 030 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 O ngoing 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 2/20/201 1 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 MW71

retail and wholesale customers. Duke Energy Caroli nas has been active in the wholesale purchased power market and has entered into contrac ts 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 Du ke Energy Carolinas’ resource procurement strategy. In particular, the purchased power agreements that the Company has entered into have allowed customers to enjoy th e benefits of discounted market capacity prices and have provided flexibility in me eting 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 Ca rolinas 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 sel f-build or long-term purchased power opportunities. From the optimization step, several diverse portfolios of resources are selected for further detailed production cost model ing and ultimate selection of a resource plan for the IRP.

Once a resource need is identified, the Company det ermines the options to satisfy that need and determines the near-term and long-term act ions necessary to secure the resource. The options could include a self-build D uke Energy Carolinas-owned resource, a Duke Energy Carolinas-owned acquired resource (ne w or existing), or a purchased power resource. The Company consistently has issue d RFPs for peaking and intermediate resource needs. For example, followin g the identification of peaking and intermediate resource needs, the Company issued a R FP in May 2007 for conventional intermediate and peaking resource proposals of up t o 800 MW beginning in the 2009- 2010 timeframe and up to 2000 additional MW beginni ng in the 2013 timeframe. Potential bidders could submit bids for purchased p ower or for the acquisition of existing or new facilities. Ten bidders submitted a total o f forty-five bids spanning time periods of two to thirty years. The bid evaluation consider ed price, operational flexibility, and location benefits. Ultimately, the Company determin ed that none of the proposed bids provided sufficient advantages to offset the multip le benefits of the proposed Buck and Dan River CC projects. The consideration of purcha sed 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 from72

alternative sources from 26 different companies. T he 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 facili ties. In addition, the Company continues to receive unsolicited proposals for renewable purc hased power resources and has entered into several PPAs as a result of unsolicited propos als.

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 com mitted resources for the Cliffside Modernization project and Buck and Dan River combin ed cycle projects, as well as new nuclear generation. The new CC resources meet an i dentified 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 depen dent 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 p rojected to operate in a more
intermediate manner. These needs will be refined i n future IRPs and could be met through new self-build capacity, purchased power, a dditional DSM or any combination of the three.

Although Duke Energy Carolinas evaluates the compet itive wholesale market for peaking and intermediate resources, the Company’s purchased power philosophy does not currently include soliciting purchased power bids f or base load capacity. Duke Energy Carolinas views base load capacity as fundamentally different from peaking and intermediate capacity. Currently, there are two ke y concerns with relying upon the wholesale market for base load capacity. First, ge neration outside the control area could be subject to interruption due to transmission issu es more so than generation within the control area. Second, supplier default could jeopa rdize 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 Ener gy 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 purch ase power or resources.73

6. ENVIRONMENTAL COMPLIANCE

Legislative and Regulatory Issues

Duke Energy Carolinas, which is subject to the juri sdiction of federal agencies including the Federal Energy Regulatory Commission (FERC), EP A, and the NRC, as well as state commissions and agencies, is potentially impacted b y state and federal legislative and regulatory actions. This section provides a high-l evel 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 nu merous state and federal air emission regulations, including the current Clean A ir Interstate Rule (CAIR) NO x and
SO 2 cap-and-trade program, and the 2002 North Carolina Clean Smokestacks Act (NC CSA).

As a result of complying with the NC CSA, Duke Ener gy Carolinas will reduce SO 2 emissions by approximately 75% by 2013 from 2000 le vels. The law also required
additional reductions in NO x 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 Asse mbly in June of 2002, calls for some of the lowest state-mandated emission levels i n the nation, and was passed with Duke Energy Carolinas’ input and support.

The following Charts 6.A and 6.B show Duke Energy C arolinas’ NO x and SO 2 emissions reductions to comply with the 2002 NC CSA requireme nts and actual emissions through
2011.74

Chart 6.A

Chart 6.B75

In addition to current programs and regulatory requ irements, 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 In terstate Rule (CAIR)

The EPA finalized its CAIR in May 2005. The CAIR l imits total annual and summertime
NO x emissions and annual SO 2 emissions from electric generating facilities acro ss the Eastern U.S. through a two-phased cap-and-trade pro gram. Phase 1 began in 2009 for
NO x and in 2010 for SO 2 . Phase 2 of CAIR would begin in 2015. In July 20 08, 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. Circ uit issued a decision remanding the CAIR to the EPA, allowing CA IR to remain in effect until EPA develops new regulations.

In August 2010, EPA published a proposed replacemen t 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 establis hes state-level annual SO 2 and
NO X budgets and ozone-season NO X 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 opinio n, the court holds that the CSAPR exceeds EPA’s statutory authority and directs EPA t o continue administering the CAIR pending completion of a remand rulemaking to replac e CSAPR with a valid rule. At this time, there is no schedule for when a new replaceme nt rule may occur, however, if the court decision were reversed on appeal, the earlie st CSAPR could likely be implemented in 2015.

Duke Energy Carolinas will continue to implement an d comply with CAIR. No significant impacts are expected for Duke Energy Ca rolinas’ continued compliance with
CAIR.

Mercury and Air Toxics Standard (MATS)

In May 2005, the EPA issued the Clean Air Mercury R ule (CAMR). The rule established mercury emission-rate limits for new coal-fired ste am generating units, as defined in Clean Air Act (CAA) section 111(d). It also establ ished 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 Maxi mum Achievable Control76

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 Haza rdous 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 e lectric generating units. Compliance with the emission limits will be required within th ree years of the effective date of the rule (April 16, 2012). The rule gives permitting a uthorities the discretion to grant up to a 1-year compliance extension, on a case-by-case basi s, for sources that are unable to install emission controls before the compliance dea dline. The one-year extension to meet compliance is not to be granted for units set to re tire, unless replacement generation is located at the site.

Based on the emission limits established by the MAT S rule, the Company expects its compliance with the MATS rule to drive the retireme nt of several non-scrubbed facilities in the Carolinas, as well as various changes to uni ts 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 s tandards 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 s ignificantly more stringent than those imposed on the existing power plant fleet. Thus, f uture construction of pulverized coal units would not currently be considered technologic ally feasible relative to MATS compliance. On July 20, 2012, EPA did announce pla ns to reconsider certain new source issues with the MATS rule. This reconsideration ru lemaking 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 announce d a decision to reconsider the 75 ppb standard. The decision was in response to a co urt challenge from environmental groups and EPA’s belief that a lower standard was j ustified. However, after much debate, EPA announced in September 2011 that it wou ld 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 classificati on.77

On April 30, 2012 EPA finalized the area designatio ns 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 dat e. For marginal nonattainment areas, states are not required to prepare an attainment de monstration. EPA in its final rule states that it performed an analysis that indicates that t he 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 t he Charlotte area’s 2013-2015 air quality does not qualify it to be reclassified as a ttainment, the area can still qualify for the first of two possible one-year extensions of the at tainment 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 qu alify for an extension, it will be bumped up to the next higher classification. For C harlotte, this would be moderate, which would then establish a 6-year attainment sche dule and require NC to develop an attainment SIP.

SO 2 Standards

In November 2009, EPA proposed a rule to replace th e 24-hour and annual primary SO 2 NAAQS with a 1-hour SO 2 standard. EPA finalized its new 1-hr standard of 75 ppb in June 2010. The SO 2 NAAQS designation process is different from all pr evious NAAQS in that EPA will not designate an area as attainmen t based solely on monitored air quality data. To support a recommended designation of atta inment the state must also have dispersion modeling of major SO 2 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 monito ring data or modeling results showing a violation of the standard.

However, in a letter dated April 12, 2012, EPA anno unced that it would not require modeling as part of the states’ June 2013 SIP submi ssions for unclassifiable areas. EPA further said that it would convene stakeholder outr each 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 Circu it Court. The court focused on whether EPA’s modeling-based implementation approac h 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 SO 2 NAAQS and at the same time ruled that EPA statemen ts 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 an78

obligation that petitioners must meet.

It remains unclear whether EPA will require states to perform source-specific modeling of major SO 2 emission sources (greater than 100 TPY) in unclass ifiable areas to either demonstrate that a source is not causing or contrib uting 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 require d for unclassifiable areas, the risk
for additional SO 2 reductions or permit changes at Carolinas stations would likely be reduced. EPA is delaying final designations for mo st areas until June 2013. As such, the Company estimates any required controls could need to be in place sometime in 2017. A major SO 2 source located in a designated nonattainment area would most likely be modeled by the state and therefore could be at a hi gh risk of being required to lower emissions if the modeling shows an exceedance of th e 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 i n identifying possible future nonattainment areas.

Particulate Matter (PM) Standard

In September 2006, the EPA announced its decision t o revise the PM 2.5 NAAQS standard. The daily standard was reduced from 65 ug/m 3 (micrograms per cubic meter) to 35 ug/m 3 . The annual standard remained at 15 ug/m 3

.

EPA finalized designations for the 2006 daily stand ard 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/m 3 primary PM 2.5 NAAQS and to equate the secondary PM 2.5 NAAQS with the primary NAAQS. EPA began undertakin g new rulemaking to revise the standards consistent with the Court’s decision. The current annual and daily PM 2.5 standards alone are not driving any emission reduct ions at Duke Energy Carolinas
facilities. The reduction in SO 2 and NO x emissions to address the current annual standard are being addressed through CAIR. Reductions to add ress 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 st andard).

On June 14, 2012, the EPA proposed to lower the cur rent 15 ug/m 3 PM 2.5 annual standard to a level within the range of 12 ug/m 3 to 13 ug/m 3 . 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 designat ions, 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 SO 2 and/or NO x 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 greenh ouse gases (GHGs). In May 2010, the EPA finalized what is commonly referred to as t he Tailoring Rule, which sets the emission thresholds to 75,000 tons/year of CO 2 for determining when a source is potentially subject to Prevention of Significant De terioration (PSD) permitting for GHGs. The Tailoring Rule went into effect beginning Janua ry 2, 2011. Being subject to PSD permitting requirements for CO 2 will require a Best Available Control Technology (BACT) analysis and the application of BACT for GHG s. BACT will be determined by the state permitting authority. Since it is not kn own 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 requireme nt are presently unknown. In addition, EPA announced in July 2011 that it was undertaking a three year study of CO 2 emissions from stationary bio-energy sources. This study is expected to yield a determination regarding the use of biomass as a carbon neutral so urce of generation and its potential use
as BACT.

On April 13, 2012, the EPA proposed new rules to es tablish GHG new source performance standards (NSPS) for new electric utili ty steam generating units (EGUs). The proposed GHG NSPS applies only to new pulverize d coal, IGCC and natural gas combined cycle units. The proposed NSPS is an outp ut-based emission standard of 1,000 lb CO 2 /gross MWh of electricity generation. At the prese nt, carbon capture and storage (CCS) is the only technology capable of attaining t his standard on pulverized coal or IGCC units. However, new pulverized coal and IGCC with CCS are currently not economically competitive technologies as new genera tion options. In addition, the geology in the Carolinas is not conducive to the se questration of CO 2. With respect to new natural gas combined cycle facilities, the prop osed standard will not require the installation of CCS technology.

The proposal excludes new simple cycle turbines fro m 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 exempts80

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 cl imate 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 fo r existing facilities to minimize impingement and entrainment of aquatic organisms. All Duke Energy Carolina’s coal and nuclear generating stations are potentially aff ected 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 Pollutan t Discharge Elimination System (NPDES) permit renewal schedule, compliance with th e rule could begin as early as
2016.

EPA’s proposed rule lists four options with a prefe rence 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 fo r cooling purposes. In order to meet fish impingement standards, intake screen modificat ions 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 requir ements. However, site specific studies are proposed by the rule in order to addres s 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 th e steam electric effluent guidelines. The regulation is to be technology-based, in that l imits are based on the capability of technology. The primary focus of the revised regul ation is on coal-fired generation, thus the major areas likely to be impacted are FGD waste water treatment systems and ash handling systems. The EPA may set limits that dict ate certain FGD wastewater treatment technologies for the industry and may require dry a sh handling systems be installed.81

According to a joint stipulation filed by EPA and e nvironmental 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 guideli ne requirements will be included in a station’s NPDES permit renewals. Thus, requirement s to comply with NPDES permit conditions may begin as early as 2017 for some faci lities. The length of time allowed to comply will be determined through the permit renewa l process. Steam electric effluent guidelines may also revise thermal discharge requir ements.

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 i nclude fly ash, bottom ash and FGD byproducts (gypsum). Since the 2008 dike failu re, numerous ash dike inspections have been completed by EPA and an enormous amount o f input has been received by EPA, as it developed proposed regulations.

In June 2010, EPA issued its proposed rule regardin g CCRs. The proposed rule offers two options: (1) a hazardous waste classification u nder Resource Conservation and Recovery Act (RCRA) Subtitle C; and (2) a non-hazar dous waste classification under RCRA Subtitle D, along with dam safety and alternat ive rules. Both options would require strict new requirements regarding the handl ing, 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 t he addition of new wastewater treatment systems. Final regulations are not expec ted until sometime in 2013 or later. EPA’s regulatory classification of CCRs as hazardou s 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 sign ificant. 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 rel iability of its transmission system and interconnections through internal analysis and participation in regional reliability groups. Internal transmission planning looks 10 ye ars ahead at available generating resources and projected load to identify transmissi on system upgrade and expansion requirements. Corrective actions are planned and i mplemented 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 transmi ssion system reliability. Duke Energy Carolinas works with PEC, NCEMC and ElectriC ities to develop an annual NC Transmission Planning Collaborative (NCTPC) plan fo r the Duke Energy Carolinas and PEC systems in both North and South Carolina. In a ddition, transmission planning is coordinated with neighboring systems including Sout h Carolina Electric & Gas (SCE&G) and Santee Cooper under a number of mechanisms incl uding legacy interchange agreements between SCE&G, Santee Cooper, PEC, and D uke Energy Carolinas.

The Company monitors transmission system reliabilit y 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 met hods that comply with SERC policy and NERC Reliability Standards and the screening re sults identify the need for future transmission system expansion and upgrades and are used as inputs into the Duke Energy Carolinas – Power Delivery optimization process. T he 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 project s which provides the greatest benefit
for the dollars invested.

Duke Energy Carolinas currently evaluates all trans mission reservation requests for impact on transfer capability, as well as complianc e with the Company’s Transmission Planning Guidelines and the FERC Open Access Transm ission Tariff (OATT). The Company performs studies to ensure transfer capabil ity is acceptable to meet reliability needs and customers’ expected use of the transmissi on system. The Power Delivery optimization process is also used to manage project s for improvement of transfer capability.

SERC audits Duke Energy Carolinas every three years for compliance with NERC Reliability Standards. Specifically, the audit req uires Duke Energy Carolinas to83

demonstrate that its transmission planning practice s meet NERC standards and to provide data supporting the Company’s annual compliance fil ing certifications. SERC conducted a NERC Reliability Standards compliance audit of Du ke Energy Carolinas in May 2011. The scope of this audit included Transmission Plann ing 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 r egional reliability groups to coordinate analysis of regional, sub-regional and i nter-control area transfer capability and interconnection reliability. The reliability groups ’ purpose is to:

• Assess the interconnected system’s capability to ha ndle large firm and non-firm transactions for purposes of economic access to res ources and system reliability;

• Ensure that planned future transmission system impr ovements do not adversely affect neighboring systems; and

• Ensure the interconnected system’s compliance with NERC Reliability Standards.

Regional reliability groups evaluate transfer capab ility 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 h igh transfer levels to verify satisfactory transfer capability.

B. Transmission System Emerging Issues

Looking forward, several items that have the potent ial 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 F ERC approval.

• FERC Order 1000 on Transmission Planning and Cost A llocation 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 r enewable 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 studie s 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 transmis sion plans in the
Eastern Interconnection and assess them on an Easte rn Interconnection wide basis; and
2. A framework to be able to perform technical analyse s to inform state and federal government representatives and policy maker s on important issues, such as future renewable resources and their impact on transmission
infrastructure.

As of late July 2012, the EIPC is performing analys is 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 com pleted 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 resou rce 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, t he Company considers the load obligation plus a 15.5% target planning reserve mar gin (see Reserve Margin discussion below). The capability of existing resources, inclu ding generating units, energy efficiency and demand-side management programs, and purchased power contracts, is measured against the total resource need. Any deficit in fu ture years will be met by a mix of additional resources that reliably and cost-effecti vely meet the load obligation.

Reserve Margin Explanation and Justification

Background

As part of the NCUC's approval of the 2010 IRP, Duk e Energy Carolinas and Progress Energy Carolinas were ordered to perform a quantita tive 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’ targe t reserve margin has been 17% with a minimum reserve margin of 15.5%. In place of a q uantitative study over the past five years, the 17% reserve margin has been justified ba sed on the Company’s review of its actual reserves and operating experience. For exam ple 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 appro ved the 17% planning reserve margin as reasonable for planning in each of the Co mpany’s IRPs from 2005 to 2011.

Duke Energy Carolinas hired Astrape, a consultant t hat specializes in reserve margin analysis, to perform the quantitative analysis. As trape's analysis was detailed, incorporating uncertainty of weather, economic load growth, unit availability, hydro availability and transmission availability for emer gency 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 us ed as the reference year because it incorporated the new generation units (Buck & Dan R iver CC, Cliffside 6) and the planned retirements.86

The physical reliability metric targets a reserve m argin 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 c ommonly 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 unse rved energy for a firm customer. Based on the results of this analysis, a 14.5% rese rve margin meets the one in every 10 year LOLE metric for Duke Energy Carolinas.

From an economic perspective, as planning reserve m argin increases, the total cost of reserves increases while the costs related to relia bility events decline. On the other hand, as planning reserve margin decreases, the cost of r eserves 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 wh ere 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 exam ined, the study shows that at a 90% confidence interval, an economic benefit would be r eceived by adding efficient natural gas combustion turbines up to a reserve margin of 1 5.5%. 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 sensitivi ty cases.

Based on the result of the analyses, the Company de veloped the 2012 IRP assuming a minimum planning reserve margin of 14.5% with a tar get of 15.5%. The 14.5% minimum planning reserve margin is 1% lower than th e 2011 IRP minimum reserve margin of 15.5%, which is equivalent to an approxim ate 200 MW reduction in generation need in the 2016 timeframe. One factor that suppor ts 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 utilitie s during periods when there are low reserves. Duke Energy Carolinas expects such purc hases 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 planni ng reserve margin is 20,911 MW. Existing resources, consisting of existing generati on and purchased power to meet load requirements, total 22,331 MW. The difference betw een available resources and the projected load obligation indicates there are suffi cient 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 a djustments, 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 req uirements needed to meet the Company’s load obligation, plus the 15.5% target pl anning reserve margin. Assumptions made in the development of this chart include:

1. Cliffside Unit 6 is online in the fall of 2012; inc luded 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 wi th the save-a-watt program are included;
5. DSM programs including those associated with the sa ve-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 th e 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 202 4 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 63 6089 B. Overall Planning Process Conclusions

Duke Energy Carolinas’ resource planning process pr ovides a framework for the Company to access, analyze and implement a cost-eff ective approach to reliably meet customers’ growing energy needs. In addition to as sessing qualitative factors, the Company has also conducted a quantitative assessmen t using simulation models.

Duke Energy Carolinas tested a variety of sensitivi ties and scenarios against a base set of inputs for various resource mixes, allowing the Com pany to better understand how potentially different future operating environments due to fuel commodity price changes, environmental emission mandates, and structural reg ulatory requirements can affect resource choices, and, ultimately, the cost of elec tricity 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 gene ration, 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 Sta tion (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 inclu ded DSM, EE and renewable resources consistent with the Company’s energy effi ciency plan approved in North and South Carolina and to meet the NC REPS. For planni ng purposes, a renewable energy standard similar to NC REPS was assumed for South C arolina beginning in 2016, in addition to the energy efficiency programs that wil l be phased in from 2015 to 2031. Nuclear uprates of approximately 100 MW are include d in the 2012 IRP. Specific projects are being developed to be implemented in t he 2013-2015 timeframe. For planning purposes, Lee Steam Station will be retire d from coal-fired generation in late 2014 and Unit 3 will be converted to natural gas ge neration in 2015.

The Company’s analysis of new nuclear capacity cont ained in the 2012 IRP focuses on the impact of various uncertainties such as load va riations, nuclear capital costs, greenhouse gas and clean energy legislation, EPA re gulations, fuel prices, and the availability of financing options such as federal l oan guarantees (FLG).

The IRP analysis included sensitivities on each of the uncertainties described below:

Load Variations: The base case load forecast incorporates the impa ct of the current recession, projected EE achievements, new wholesale sales opportunities, and the impact90

associated with future plug-in hybrid vehicles. Th e Company also developed high and low load forecast sensitivities to reflect a 95% co nfidence interval.

Nuclear Capital Costs: The Company varied the nuclear capital cost on the low end to reflect the impact of minimal project contingency a nd low escalation rates and varied on the high side to reflect increased labor and materi al cost.

Nuclear Financing Options: The nuclear cost in the 2012 IRP includes state incentives, local incentives and federal loan guara ntees.

Greenhouse Gas Legislation: The 2012 fundamental CO 2 allowance price forecast was delayed primarily due to uncertainty of Congress pa ssing carbon legislation. For the 2012 IRP, the Company evaluated a range of CO 2 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 CO 2 cap and trade mechanism, but relies upon a federal
RPS.

Fuel Prices: The base case natural gas and coal price projecti ons were based on Duke Energy’s fundamental price forecasts, which are upd ated 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 mini ng 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 nat ural gas than currently assumed and a lower demand on coal.

Results

The results of the Company’s quantitative and quali tative analyses suggest that a combination of additional base load, intermediate, and peaking generation, renewable resources, and EE and DSM programs are required ove r 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 Project s, pursuing nuclear uprates and procuring renewable energy resources, as appropriat e. However, additional resources will be needed as early as 2016 to meet forecasted system demand and energy requirements. As natural gas market price projecti ons have decreased from 2011, construction and operation of efficient combined cy cle 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 mark et, the Company’s analysis continues to affirm the potential benefits of new nuclear capaci ty in the 2022 timeframe in a carbonconstrained future.91

To demonstrate that the Company is planning adequat ely for customers, the Company selected a portfolio incorporating the impact of fu ture carbon legislation for the purposes of preparing the Load, Capacity, and Reserve Margin Table (LCR Table).

This portfolio consisted of 1,800 MW 4 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 Riv er CC, and Lee Unit 3 natural gas conversion projects.

However, the Company will likely face significant c hallenges relating to its resource planning in the future, such as specific challenges in (1) obtaining the necessary regulatory approvals to implement future demand-sid e, EE, and supply-side resources, (2) finding sufficient cost-effective, reliable ren ewable resources to meet the standard, particularly the swine and poultry set-asides, (3) effectively integrating renewables into the resource mix, particularly with the expected in crease in solar QFs, (4) ensuring sufficient transmission capability for these resour ces, 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 rel ating to its fuel diversity, the Company’s environmental profile, the stage of techn ology deployment and regional economic development, Duke Energy Carolinas has dev eloped a strategy to ensure that the Company can meet customers’ energy needs reliab ly and economically while maintaining flexibility pertaining to long-term res ource decisions.

Challenges and Considerations for New and Existing Nuclear Generation

In March of 2012, the NRC issued a request for info rmation 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 implementi ng the new CEUS seismic model is underway. However, completion of the new seismic an alysis is not expected before December 2012. This negatively impacts the schedule for NRC issuance of the Lee Combined Operating License (COL). The prior NRC sch edule for Lee COL issuance in March-April 2013 supported a Commercial Operation D ate (COD) of 2021. Completion of the new site-specific seismic analysis will dela y Lee COL issuance beyond the second Quarter 2013, which does not support a 2021 COD. A ccordingly, Duke Energy

4 The ultimate sizes of any generating unit may chan ge 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 c onfidence is central to the agency's ability to license new reactors and renew the opera ting licenses of existing reactors. On June 8, 2012, the US Court of Appeals of the Distri ct 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 ava ilable “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 decisio n, numerous parties filed a petition to suspend final decisions in all pending reactor l icensing proceedings pending completion of remanded waste confidence proceedings in new nuclear and license renewal proceedings pending before the NRC. On Aug ust 7, 2012, the NRC issued an order on the petition stating that: (1) it is cons idering all options for resolving the waste confidence issues, which could include generic or s ite specific actions, but has not yet determined a course of action. (2) it will not iss ue licenses dependent on the waste confidence rule until the Court’s remand is appropr iately addressed, however, this determination extends only to final license issuanc e; 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 opera ting license expires in 2033, which is close to the end of our current IRP planning hor izon. At this time, the Company has not made a decision concerning a second license ext ension for this plant. Oconee is a significant part of Duke Energy Carolinas’ generati on portfolio representing over 2,500 MW of capacity and annual energy output of approxim ately 20,000 GWHs. As such, it is important to start to examine the impacts of any po tential retirement of Oconee to help the Company as it considers a second license extens ion, 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 appropr iate resource plan at this point in time, however, good business practice requires Duke Energ y Carolinas to continue to study the options, and make adjustments as necessary and prac tical to reflect improved information and changing circumstances. Consequently, a good b usiness planning analysis is truly an evolving process that can never be considered compl ete.

The seasonal projections of load, capacity, and res erves of the selected plan are provided in Table 8.A.93Table 8.ASummer Projections of Load, Capacity, and Reservesfor Duke Energy Carolinas 2012 Annual Plan2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032Load Forecast1 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 25,051 25,483 25,905Reductions to Load Forecast2 New EE Programs (62) (117) (181) (247) (317) (384) (451) (517) (585) (652) (720) (785) (854) (921) (988) (1,053) (1,123) (1,190) (1,257) (1,320)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 23,861 24,227 24,585Cumulative System Capacity4 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 20,207 20,207 20,2075 Capacity Additions 1,481 66 182 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 06 Capacity Derates0 0 0 (4) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 07 Capacity Retirements (350) 0 (1,080) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 08 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 20,207 20,207 20,207Purchase Contracts9 Cumulative Purchase Contracts 340 340 328 328 328 328 261258 170 155 155 155 155 155 155 155 141 141 141 141Sales Contracts10 Catawba Owner Backstand 0 (47) (47) (47) (47) (47) (47) (47) 0 0 0 0 0 0 0 0 0 0 0 011 Firm Sale(150) (150) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 012 Cumulative Future Resource AdditionsBase Load0 0 0 0 0 0 0 0 0 1,117 1,117 2,234 2,234 2,234 2,234 2,234 2,234 2,234 2,234 2,234Peaking/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 3,700 3,700 3,850Renewables38 103 171 231 256 288 374 395 426 516 536 567 637 661 684 701 715 729 743 75813 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 27,011 27,025 27,190Reserves w/o Demand-Side Management14 Generating Reserves 3,229 2,919 1,870 2,180 1,814 2,1752,616 2,374 2,036 2,927 2,639 3,475 3,214 2,958 2,609 2,990 2,677 3,150 2,799 2,60515 % 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% 13.2% 11.6% 10.6%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% 11.7% 10.4% 9.6%Demand-Side Management17 Cumulative DSM Capacity 8729561,0431,0991,1401,1531,1671,1801,1941,2001,2071,2071,2071,2071,2071,2071,2071,2071,2071,207IS / SG10095908682828282828282828282828282828282Power Share / Power Manager 7728619531,0131,0581,0711,0851,0981,1121,1181,1251,1251,1251,1251,1251,1251,1251,1251,1251,12518 Cumulative Equivalent Capacity 22,14422,31221,70722,51822,58423,32924,16124,19324,19725,39525,42226,57026,64026,66426,68727,40527,40428,21828,23228,397Reserves w/ DSM19 Generating Reserves 4,1013,8752,9123,2792,9543,3283,7833,5543,2304,1273,8464,6824,4214,1653,8164,1973,8844,3574,0063,81220 % 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% 18.3% 16.5% 15.5%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% 15.4% 14.2% 13.4%94Winter Projections of Load, Capacity, and Reservesfor Duke Energy Carolinas 2012 Annual Plan12/13 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 29/30 30/31 31/32Load Forecast1 Duke System Peak17,443 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 23,81624,209 24,628 25,005Reductions to Load Forecast2 New EE Programs(60) (109) (164) (219) (303) (369) (435) (489) (567) (633) (699) (763) (814) (879) (963) (1,027) (1,095) (1,162) (1,203)(1,264)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 23,048 23,425 23,740Cumulative System Capacity4 Generating Capacity20,318 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 20,96520,965 20,965 20,9655 Capacity Additions2,074 36 66 182 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 06 Capacity Derates0 0 0 0 (4) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 07 Capacity Retirements(626) 0 0 (1,080) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 08 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 20,965 20,965 20,965Purchase Contracts9 Cumulative Purchase Contracts 347 347 335 335 335 335 268265 170 155 155 155 155 155 155 155 141 141 141 141Sales Contracts10 Catawba Owner Backstand 0 (47) (47) (47) (47) (47) (47) (47) 0 0 0 0 0 0 0 0 0 0 0 011 Firm Sale(25) (25) (25) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 012 Cumulative Future Resource AdditionsBase Load0 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 2,234 2,234Peaking/Intermediate0 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 3,700 3,700Renewables16 38 103 171 231 256 288 374 395 426 516 536 567 637 661 684 701 715 729 74313 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 26,955 27,769 27,783Reserves w/o Demand-Side Management14 Generating Reserves4,720 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 3,907 4,344 4,04315 % Reserve Margin27.2% 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% 17.0% 18.5% 17.0%16 % Capacity Margin21.4% 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% 14.5% 15.6% 14.6%Demand-Side Management17 Cumulative DSM Capacity 570595617635653653653653653653653653653653653653653653653653IS / SG10095908682828282828282828282828282828282Power Share / Power Manager 47050052754957157157157157157157157157157157157157157157157118 Cumulative Equivalent Capacity 22,67322,71022,85022,06322,83722,86223,52624,40924,38224,39925,60625,62626,77426,84426,86826,89127,59427,60828,42228,436Reserves w/ DSM19 Generating Reserves5,2904,9514,7193,5373,9163,5593,8494,4244,1853,8534,7774,5095,3285,1384,8734,4994,8744,5604,9974,69620 % Reserve Margin30.4% 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% 19.8% 21.3% 19.8%21 % Capacity Margin23.3% 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% 16.5% 17.6% 16.5%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 Loa d, Capacity, and Reserves tables. All values are MW ex cept 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 b e 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 St ation less 832 MW to account for NCMPA1 firm capacity sal e.

5. Capacity Additions include Duke Energy Carolinas projects that have been approved by the NCUC (Cliff side 6, Dan River Combined Cycle facility). Capacity Additions include the conversion of Lee St eam Station unit 3 from coal to natural gas in 2015 (170 MW). Capacity Additions include Duke Energy Carolinas hy dro 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 2012-201 5

6. Capacity Derate of 4 MW associated with Marshall 4 SCR is included in 2016

7. The 350 MW capacity retirement in summer 2013 rep resents the projected fall 2012 retirement date for the old fleet CT retirements The 1080 MW capacity retirement in summer 2015 repr esents 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 operatin g licenses for all Duke Energy Carolinas' nuclear f acilities. The Hydro facilities for which Duke has submitted a n application to FERC for licence renewal are assum ed to continue operation through the planning horizo n. All retirement dates are subject to review on an on going basis.

9. Cumulative Purchase Contracts have several compon ents:

A. Piedmont Municipal Power Agency took sole respon sibility 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 b e served by Duke. B. Purchased capacity from PURPA Qualifying Facilit ies 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 M W in 2013.

10-11. A firm wholesale backstand agreement up to 27 7 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 p ower mitigation.

12. Cumulative Future Resource Additions represent a combination of new capacity resources or capabilit y increases from the most robust plan.

15. Reserve Margin = (Cumulative Capacity-System Pea k Demand)/System Peak Demand Occurences when Reserve Margin exceeds +/-3% of the 15.5% target planning reserve margin:2013-2014 Res erve Margin 1) 2013-2014: Due to the addition of Buck and Dan River CC and Cliffside 6 PC units coupled with lowe r economic load growth. 2) 2019: Due to the addition of 800 MW of CT capac ity to meet resource need in 2019, 2020 and 2021. 3) 2022, 2024, and 2025: Due to the addition of 1 117 MW nuclear units to meet long-term resource nee d in 2022 and 2024.

16. Capacity Margin = (Cumulative Capacity - System Peak Demand)/Cumulative Capacity

17. The Cumulative Demand Side Management capacity i ncludes 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 rela tive shares of renewables, energy efficiency, and gas all increase, while the relativ e 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 Energy97

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 2 023 2024 2025 2026 2027 2028 2029 2030 2031 2032MW 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 2 023 2024 2025 2026 2027 2028 2029 2030 2031 2032GWh DEC Energy

Nuclear New Nuclear Coal Cliffside 6
Gas New CT Buck CC Dan River CC
New CC Hydro Renewables DSM/EE
Purchases98

Table 8.D below represents the annual non-renewable incremental additions reflected in the LCR Table of the most robust expansion plan. T he plan contains the addition of Cliffside Unit 6 in 2012, the unit retirements show n 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 80099

The details of the forecasted capacity additions, i ncluding both nameplate capacity and the expected contribution of renewable resources to wards 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 Nameplate100 

# APPENDICES101

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 co nsideration
3. Develop theoretical portfolio configurations
4. Develop final portfolio options 5. Perform portfolio analysis

Assess Resource Needs

Duke Energy Carolinas estimates the required load a nd generation resource balance needed to meet future customer demands by assessing :

• Customer load forecast peak and energy – identifyin g future customer aggregate demands to identify system peak demands and develop ing the corresponding energy load shape

• Existing supply-side resources – summarizing each e xisting generation resource’s operating characteristics including unit capability , potential operational constraints, and life expectancy

• Operating parameters – determining operational requ irements including target planning reserve margins and other regulatory consi derations.

Customer load growth coupled with the expiration of purchased power contracts, lower demand response, and renewable compliance assumptio ns, 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 o ld 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 r emaining coal units without scrubbers by 2015

• Approximately 70 MW of net generation reductions as a result of unit de rates associated with new environmental equipment

• Continued operational reliability of existing gener ation portfolio

• A 15.5% target planning reserve margin for the plan ning horizon

Identify and Screen Resource Options for Further Co nsideration

The IRP process evaluates EE, DSM and supply-side o ptions to meet customer energy and capacity needs. The Company develops DSM/EE op tions for consideration within the IRP based on input from our collaborative partn ers and cost-effectiveness screening. Supply-side options reflect a diverse mix of techno logies and fuel sources (gas, coal, nuclear and renewable). Supply-side options are in itially 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-effect ive 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-si de resource options to meet future capacity needs:

• Base load – 825 MW Supercritical Pulverized Coal wi th 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 ch iller and duct fired)

• Peaking/Intermediate – 800 MW (4 x 200 MW) Simple C ycle CT

• Renewable – 150 MW Wind - On-Shore

• Renewable – 5 MW Landfill Gas

• Renewable – 25 MW Solar PV103

Although the supply-side screening curves showed th at some of these resources would be screened out, they were included in the next step o f the quantitative analysis for completeness.

Energy Efficiency and Demand-Side Management EE and DSM programs continue to be an important par t of Duke Energy Carolinas’ system mix. The Company considered both demand res ponse and conservation programs in the analysis.

The Company modeled the program costs associated wi th EE and DSM based on a combination of both internal company expectations a nd projections based on information from the Company’s 2011 Market Potential Study. Th ese program costs are expected to increase throughout the planning horizon as additio nal 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 o f 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% targe t planning reserve margin while minimizing the long-run revenue requirements to cus tomers, with differing operating (production) and capital costs.

The set of basic inputs included:

• Fuel costs and availability for coal, gas, and nucl ear generation

• Development, operation, and maintenance costs of bo th 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 optio ns with corresponding costs and timing parameters104

Duke Energy Carolinas reviewed a number of variatio ns to the theoretical portfolios to aid in the development of the portfolio options dis cussed in the following section.

Develop Final Portfolio Options

Using the insights gleaned from developing theoreti cal portfolios, Duke Energy Carolinas created a representative range of generation plans reflecting plant designs, lead times and environmental emissions limits. Recognizing that d ifferent 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 fac tors 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 out lines 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 N C REPS in NC and applied to SC. In addition, each portfolio contains the addition of C liffside Unit 6 in September 2012, Dan River CC in December 2012, Lee Unit 3 Gas Conversio n in January 2015 and the unit retirements shown in Table 5.D.

The RPS assumptions are based on NC REPS in North C arolina. 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-o f-state, unbundled RECs

• Solar requirement

o 0.02% by 2010

o 0.07% by 2012

o 0.14% by 2015

o 0.20% by 2018105 • Swine waste requirement (NC only – using Duke Energ y 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 Ene rgy 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 re newable projects that supply energy to the resource inventory. The costs associated wi th each of these resources are included in the resource plan, but only those that provide c apacity 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 fro m 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 scenari os, in order to understand the strengths and weaknesses of various resource configurations a nd evaluate the long-term costs to customers under various potential outcomes.

For this IRP analysis, the Company selected three m ain portfolios to illustrate the impacts of key risks and decisions. Each portfolio include s renewable resources to meet regulatory requirements and the base amount of EE/D SM resources as shown in Table
4.A.

The three analyzed portfolios are shown below:

1. Natural Gas – Combustion turbine/combined cycle por tfolio (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 20 22 and 2024, and 558 MW in 2028106

The sensitivities performed for these scenarios wer e 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 sensitivity 5

- Costs to construct a new nuclear plant (+20/- 10% h igher 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 g as prices 20% lower)

• High EE and DSM

- For EE, this sensitivity assumes full compliance wi th the Duke EnergyProgress Energy merger settlement agreement with th e cumulative EE achievements since 2009 counted toward the cumulati ve settlement agreement impacts. The incremental impacts stop in 2031 after reaching the full economic potential of 16.5 million MWH. F or DSM, an additional 100 MW of load curtailment is added by 2 017.

• Carbon Emission Price

- The reference case is a cap and trade program with CO 2 emission prices based on the Company’s 2012 fundamental prices. Th e prices ranged from $17/ton starting in 2020 to $44/ton in 2032. The reference CO 2 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 w ith higher CO 2 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, i ncreasing to 30% by
2030

5 These sensitivities test the risks from increases in construction costs of one type of supply-side re source at a time. In reality, cost increases of many constru ction component inputs such as labor, concrete and steel would affect all supply-side resources to varying d egrees rather than affecting one technology in isol ation.107 - Alternative compliance payment of 30$/MWh

- “Clean Energy” includes renewable resources, EE, nu clear, natural gas CC, or alternative compliance payment

• No Carbon Emission Price

- Although the Company believes there will be a carbo n constrained future a sensitivity analysis without a CO 2 emission price was provided to show the relative impact of carbon on the nuclear and ga s portfolios. In addition, a sensitivity analysis was also performed with high er fuel prices to reflect the impact fuel volatility can have on the portfoli os without carbon prices.

An overview of the specifics of each portfolio is s hown 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 Portfolios108

Quantitative Analysis Results

Three potential resource planning strategies were t ested under base assumptions and variations in CO 2 price, fuel costs, load/energy efficiency, and nuc lear and combined cycle capital costs. These three potential resourc e planning strategies are:

• No new nuclear capacity (the CT/CC portfolio)

• Full ownership of new nuclear capacity (the 2 Nucle ar Units portfolio)

• Regional co-ownership of new nuclear capacity (the Regional Nuclear portfolio)

For the base case and sensitivities, the Company ca lculated the PVRR for each portfolio. The revenue requirement calculation estimates the c osts to customers for the Company to recover system production costs and new capital inc urred. Duke Energy Carolinas used a 50-year analysis time frame to fully capture the lo ng-term impact of nuclear generation added in the 20 year planning horizon. Table A.2 b elow 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 portfoli o 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 i s the PVRR savings in $billions
between the cases.

Table A.2 - Comparison of Nuclear Portfolios to the CT/CC Po rtfolio ($ Billions)

6 The difference between the CT/CC and Nuclear portf olios is less than $10 million. Reference Case CO2 Price Clean Energy

Portfolio Base 5 High CO 2 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% Inc rease Gas 5% Decrease 6

Nuclear (1.2) (0.7)

Regional Nuclear (1.3) (0.8) (0.02)

CT/CC 2.4 Nucl / 2.2 Reg 0.1 Nucl No Carbon Sensitivity Load Sensitivity Fuel Sensitivity

Capital Cost Sensitivity109

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 p rojected load for the 2012 IRP, the portfolios with nuclear remain competitive with nat ural 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 sho ws 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 CO 2 Cap and Trade construct.

The Company’s proposed portfolio including full own ership of two nuclear units in 2022 and 2024 continues to be cost effective, but the Co mpany recognizes the potential benefits to customers of securing new nuclear gener ation in smaller capacity increments through regional nuclear development. Duke Energy Carolinas’ analysis indicates that the regional nuclear portfolio is lower cost to cus tomers in the base case and most scenarios, but the full nuclear portfolio was chose n for the 2012 IRP preferred plan because there are no firm commitments in place at t his time for the regional nuclear portfolio. Several advantages to a regional nuclear approach are:

• Load Growth: Smaller blocks of base load generatio n brought on-line over a period of years would more closely match projected load growth.

• Financial: The substantial capital cost would be ph ased in over a longer period of time and would spread the risk if there were cost i ncreases.

• Regulatory Uncertainty: The optimal amount and timi ng of additional nuclear generation will depend on the outcome of final GHG legislation. Using a regional approach would allow utilities to better optimize t heir 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 c ontinue to assess opportunities to
benefit from economies of scale and risk reduction by considering the prospects for joint ownership for new nuclear generation resources incl uding potentially with Progress Energy Carolinas. As the Company announced in 2011 Duke Energy Carolinas has agreements with JEA, located in Jacksonville, Flori da, and with the Public Service Authority of South Carolina (Santee Cooper). Duke E nergy Carolinas has an agreement with Santee Cooper to perform due diligence to pote ntially 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 th e 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 potent ially 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 CO 2 emission price has been incorporated to show the relative impact of carbon on the nuclear and gas po rtfolios. 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 CO 2 prices significantly advantages the natural gas portfolio. However, as s hown 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 a pproximately $3 billion PVRR.

The high nuclear capital cost sensitivity analysis reflects the importance of minimizing cost increases on the new nuclear generation. Howe ver, there is the risk that natural gas generation cost could also increase with the signif icant amount of natural gas generation that will be added over the planning horizon.

Quantitative Analysis Summary

One of the major benefits of having additional nucl ear generation is the lower system
CO 2 footprint and the associated economic benefit. Th e projected CO 2 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 th e Company to achieve material system reductions in CO 2 emissions, it must add new nuclear generation to th e future resource portfolio. In the absence of a CO 2 policy, the CO 2 emissions in each portfolio would be at least two million tons higher by 2032.111

Chart A.3 - CO 2 Emissions

The biggest risks to the proposed nuclear portfolio s 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 constrai ned 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 analyse s 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 genera tion. Duke Energy Carolinas is pursuing favorable financing options and continues to seek potential regional generation partners.

The overall conclusions of the quantitative analysi s 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 2032Thousands of Tons/Year CO2 Emission Projections

CT/CC Nuclear Regional Nuclear112

• The new levels of EE and DSM are cost-effective for customers.

- The screening analysis shows that portfolios with t he 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 st udy. The high EE sensitivity is cost effective if there is an equal participation between residential and non-residential customers. If a si gnificant number of nonresidential customers opt out, then the high EE cas e may no longer be
cost effective.

• Significant renewable resources will be needed to m eet the new NC REPS and a potential federal standard.

• There is a capacity need in the 2016 to 2020 timefr ame to maintain the target 15.5% reserve margin.

• The analysis demonstrates that the nuclear option i s an attractive option for the Company’s customers.

- Continuing to preserve the option to secure new nuc lear generation is prudent under the circumstances.

- Favorable financing is very important to the projec t cost when compared to other generation options.

- Co-ownership is beneficial from a generation and ri sk perspective.

For the purpose of demonstrating that there will be sufficient resources to meet customers’ needs, Duke Energy Carolinas has selecte d 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 C ompany’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 renewable s into the resource mix, and ensuring sufficient transmission capability for the se resources.113

APPENDIX B


# Duke Energy Carolinas Spring 2012 Forecast

Sales

Rates Billed

Peaks

2012-2027114 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 29Table of Contents115

( 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

Growth Forecasted 2012

Amount Forecasted 2013

Amount Amount System Sales & System Peak Summer (2012 Spring Fore cast vs. 2011 Spring Forecast)

System Sales is the sum of Retail and Wholesale. Ret ail Sales include Residential, Commercial, Industrial and Other Retail (Public Str eet 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 d emand 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 project ed 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 Industria l 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 weake r than expected . Adjustments were made to the Spring 2012 Forecasts and the Spring 2011 Forecasts to account for Duke Energy Carolinas Sponsored Energy Efficiency p rograms and the expected ban of incandescent lighting mandated by the Energy Independence and Se curity Act of 2007, as well as for the expected growth Plug-in Electric Vehicles. Additional adjust ments 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 202 0 Duke Carolinas will supply 100% of their load.Executive Summary116

( 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 tha t Duke Energy Carolinas is contractually obligated to serve and is used as the basis for Duk e's Integrated Resource Plan. The forecasts include an adjustment for proposed ut ility sponsored energy efficiency programs as well as adjustments for the expected gro wth in Plug-in Hybrid Electric Vehicles (PHEV) and the proposed ban on incandescent lightin g. The Spring 2012 Forecast also reflects the impacts of expected growth in solar en ergy. The system summer peak demand on the Duke Energy Ca rolinas 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 Car olinas energy and demand forecasts for Spring 2012

Duke Energy Carolinas’ Spring 2012 forecasts repres ent projections of the energy and peak demand needs for its service area, which i s 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 a nd represent the energy and peak demand needs for the Duke Energy Carolinas system c omprised of the following customer classes and other utility/wholesale entiti es:

• Residential • Commercial • Textiles • Other Industrial • Other Retail • Duke Energy Carolinas full/partial requirements w holesale

Energy use is dependent upon key economic factors s uch as income, energy prices and employment along with weather. The general fra mework of the Company’s forecast methodology begins with forecasts of regio nal 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 e conomic forecasts for the Duke Carolinas service area region. These economic foreca sts 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., text iles • Manufacturing Employment industry group • Total real personal income

Total population forecasts are obtained from the tw o states’ demographic offices for each county in each state which are then used to de rive the total population forecast for the 51 counties that the Company serves in the Carolinas.Forecast Methodology118 ( Load Forecast Pg 4)

General forecasting methodology (continued)

A projection of weather variables, cooling degree d ays (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 identif ied 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 cu stomers are developed at a customer class level, i.e., residential, commercial, textile, othe r industrial and street lighting along with forecasts for its wholesale customers. Econometric models incorporating the use of industrystandard linear regression techniques were develope d utilizing a number of key drivers of energy usage as outlined above. The following provi des information about the models.

Residential Class: The Company’s residential class sales forecast is c omprised of two separate and independent forecasts. The first is the number of residential r ates billed which is driven by population projections of the counties in which the Company pr ovides electric service. The second forecast is energy usage per rate billed which is d riven primarily by weather, regional economic and demographic trends, electric price and appliance efficiencies. The total residential sales forecast is derived by multiplyin g 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 i mpact of weather.

Textile Class: The level of electricity consumption by Duke Energy Carolinas’ textile group is impacted by the level of textile manufacturing output, exchang e rates, electric prices and weather.

Other Industrial Class: Electricity usage for Duke’s other industrial custo mers was forecasted by 5 groups according to the 3 digit NAICS classification and then aggreg ated to provide the overall other industrial sales forecast. Usage is driven primarily by region al manufacturing output at a 3 digit NAICS level, industrial production indices, electric price s and weather.

Other Retail Class: This class in comprised of public street lighting a nd traffic signals within the Company’s service area. The level of electricity usage is imp acted not only by economic growth but also by advances in lighting efficiencies.

Full / Partial Requirements Wholesale: Duke Energy Carolinas provides electricity on a con tract basis to numerous wholesale customers. The larger wholesale entities are foreca sted by using an econometric model with aggregate economic drivers such as regional GDP or i ncome. The very small entities are forecasted by assuming they grow at the same rate a s Duke's retail sector. The Wholesale category is also affected by the terms of the contr acted sales agreements and any changes therein.119 ( Load Forecast Pg 5)Billed Sales and Other Energy Requirements120 ( 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, Commer cial, Industrial, Street and Public Lighting, and Traffic Signal Service classes . Full/Partial Requirements Wholesale sales include GWH sales billed to municip alities and public utility companies that purchase their full power requiremen ts from the Company, plus in the forecast period, supplemental sales to specifie d 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 projec tions for the Spring 2012 Forecast to reflect the effects of utility sponsor ed energy efficiency programs, and additions from the expected growth in Plug-in Hybri d Electric Vehicles (PHEV) in the forecast. The expected ban on incandescent ligh ting mandated by the Energy Independence and Security Act of 2007 is reflected in the residential sales model by adjusting the appliance efficiency variable. Als o, 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 serv ice area. The resulting annual growth in Residential billed sales is expected to a verage 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 ho rizon, 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 h orizon.

• The Full/Partial Requirements Wholesale class is expected to grow at 5.1% annually over the forecast horizon, primarily due t o 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 202 7) 1380 1.5 2011 81,851 -2,237 -2.7 Spring 2011 Forecast (2011 to 2 027) 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 vs SPRING 2011 SPRING 2012 FORECAST AVERAGE ANNUAL GROWTH

HISTORY

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 2023GWH

Year History Spring 2011 Forecast Spring 2012 Forecast122 ( 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 20 27) 308 1.0 2011 28,323 -1,726 -5.7 Spring 2011 Forecast (2011 to 2 027) 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 AVERAGE ANNUAL GROWTH

HISTORY

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 2023GWH

Year

History Spring 2011 Forecast Spring 2012 Forecast123 ( 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 202 7) 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 2023GWH

Year

History Spring 2011 Forecast Spring 2012 Forecast124 ( 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 202 7) 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 2023GWH

Year History Spring 2011 Forecast Spring 2012 Forecast125 ( 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 2023GWH

Year
History Spring 2011 Forecast Spring 2012 Forecast126 ( 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 202 7) 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 2023GWH

Year History Spring 2011 Forecast Spring 2012 Forecast127 ( 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 AVERAGE ANNUAL GROWTH

HISTORY

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 2023GWH

Year

History Spring 2011 Forecast Spring 2012 Forecast128 ( 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 202 7) 1011 1.2 2011 76,985 -1,937 -2.5 Spring 2011 Forecast (2011 to 2 027) 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 AVERAGE ANNUAL GROWTH

HISTORY

Growth SPRING 2011 FORECAST

Growth 60,000 70,000 80,000 90,000

1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 2020 2023GWH

Year

History Spring 2011 Forecast Spring 2012 Forecast129 ( 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 202 7) 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 2023GWH

Year

History Spring 2011 Forecast Spring 2012 Forecast130 ( Load Forecast Pg 16)Number of Rates Billed131 ( Load Forecast Pg 17)



### Total Rates Billed
(Sum of Major Retail Classes: Residential, Commerci al 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 Bil led % 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 AVERAGE ANNUAL GROWTH

HISTORY

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 2023Rates Billed

Year History Spring 2011 Forecast Spring 2012 Forecast132 ( 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 Bil led % 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 AVERAGE ANNUAL GROWTH

HISTORY

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 2023Rates Billed

Year

History Spring 2011 Forecast Spring 2012 Forecast133 ( 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 20 27) 5,197 1.4 2011 336,099 2,139 0.6 Spring 2011 Forecast (2011 to 20 27) 5,844 1.5

SPRING 2012 vs SPRING 2011

Growth Year Rates Billed Rates Billed % Rates Billed Rates Bil led % 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 2023Rates Billed

Year

History Fall 2011 Spring 2012134 ( 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 Bil led % 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 AVERAGE ANNUAL GROWTH

HISTORY

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 2023Rates Billed

Year History Spring 2011 Forecast Spring 2012 Forecast135 ( 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 Bil led % 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 2023Rates Billed

Year History Fall 2010 Forecast Spring 2011 Forecast136 ( 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 Bil led % 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 AVERAGE ANNUAL GROWTH

HISTORY

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 2023Rates Billed

Year
History Spring 2011 Forecast Spring 2012 Forecast137 ( Load Forecast Pg 23)System Peaks138 ( Load Forecast Pg 24)Summer Peak

The Summer peak forecast represents the maximum dem and during the summer season on the Duke Energy Carolinas system. The Summer Pe ak Forecast includes all load that Duke Energy Carolinas is contractually obligat ed to serve and is used in the Integrated Resource Plan. It includes all Retail cl asses, 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 Hybr id Electric Vehicles (PHEV) and the proposed ban on incandescent lighting. The Spr ing 2012 Forecast also reflects the impacts of expected growth in solar energy. Thus, the Summer Peak forecast shown is after all ad justments.

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 AVERAGE ANNUAL GROWTH

HISTORY

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 2025MW

Year

WN History Spring 2011 Forecast Spring 2012 Forecast Actual History140 ( Load Forecast Pg 26)Winter Peak

The Winter peak forecast represents the maximum dem and during the winter season on the Duke Energy Carolinas' system. The W inter Peak Forecast includes all load that Duke Energy Carolinas is contractuall y obligated to serve and is used in the Integrated Resource Plan. It includes all Retai l classes, Wholesale, Company Use and is at generation.

The forecast reflects Duke Energy Carolinas sponsor ed energy efficiency programs as well as adjustments for the expected gro wth in Plug-in Hybrid Electric Vehicles (PHEV) and the proposed ban on incandescen t lighting. The Spring 2012 Forecast also reflects the impacts of expected grow th in solar energy. Thus, the Winter Peak forecast shown is after all ad justments.

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 202 7) 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 AVERAGE ANNUAL GROWTH

HISTORY

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 2027MW

Year TC History Spring 2011 Forecast Spring 2012 Forecast142 ( 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 2011143Load DefinitionsThe following table shows differences in the load forecasts that are utilized for various Company andregulatory documents, reports, and filings.(Load Forecast Pg 29)LOAD TYPES/LOAD COMPONENTSBALANCINGAUTHORITY IRP RPO FERC FORM1 SERCLOADFORECASTBOOKREGULARBILLEDSALES TRANSMISSIONRETAILX X X X X X X XS10A - CONCORDX X X X X X X XS10A - DALLASX X X X X X X XS10A - KINGS MOUNTAINX X X X X X X XS10A - FOREST CITYX X X X X X X XS10A - DUE WESTX X X X X X X XS10A - PROSPERITYX X X X X X X XS10A - LOCKHARTX X X X X X X XWESTERN CAROLINA UNIVERSTIYX X X X X X X XHIGHLANDX X X X X X X XGREENWOODX X X X X X XSENECAXXSCEGXXPIEDMONT EMCX X XXBLUE RIDGE EMCX X XXRUTHERFORD EMCX X XXHAYWOOD EMCX X XXNCEMC TOTALXX XNCMPA TOTALXX XPMPA TOTALXX XSALUDA RIVER TOTALX XNCEMC OWNERSHIP OF CATAWBANET OF PBRH CATAWBA(630-98-3)X XNCEMC FIXED LOAD SHAPEX XXNEW HORIZON STEP-UP CONTRACTX (Start in 2013) X (Start in 2013) X (Start in 2013)X (Start in 2013) X (Start in 2013) X (Start in 2013)LINE LOSSESX X X X X X XUNBILLEDX X X X X X XCOMPANY USEX X X X X X XNotes:1. Changes from 2011 definition1) NCEMC's ownership reduced from 682 to 630 because they are moving 52 MWs of their entitlement to PJM (off-system)2) Remove 432 NCMPA entitlement, backstand agreement ends Dec 31, 20112. Greenwood became part of Duke's native load forIRP and RPO beginning Jan 1st 2010.3. Seneca was added to Balancing Authority load onJuly 14 2010 @ HE 1000.4. The loss multiplier to convert meter load to generation is 1.030927835051555. New Horizon co-ops include Little River EC, BlueRidge EC, Broad River EC, York EC and Laurens EC.This table serves a reference for developing forecast for various load definitions. Because historicalload for different loaddefinitions are derived from the balancing autorityload, please refers to the Load Calculation page for the equations used tocome up with historical load actuals.6. Balancing Authority load is an all-in load, meaning it includes loads from loads supplied by sources other than Duke'sgeneration (SEPA and BTM). The engineering definition of BA load is: Sum of Duke's Generation + Load Flowing in + LoadFlowing Out144

APPENDIX C: SUPPLY-SIDE SCREENING

The following sets of estimated Levelized Busbar Co st 8 charts provide an economic comparison of the technologies in their respective categories. Despite the usefulness of levelized busbar cost comparisons, comparisons invo lving some renewable resources, particularly wind and solar resources, can be somew hat misleading because these
resources do not contribute their full installed ca pacity at the time of the system peak 9

. Since busbar charts attempt to levelize and compare costs on an installed kW basis, wind and solar resources appear to be more economical th an they would be if the comparison was performed on a peak kW basis. The Renewables B usbar Chart shows a single point for each type of resource at the particular capacit y factor specified.

Base load

The following technologies are found on the base lo ad technologies screening chart:

1) 2 x 1,117 MW Nuclear 2) 825 MW Supercritical Coal with Carbon Capture and S equestration at 60% 3) 618 MW IGCC with Carbon Capture and Sequestration a t 55% 4) 700 MW – 2x2x1 Combined Cycle (Inlet Chiller and Du ct Fired)

8 While these estimated levelized busbar costs provi de a reasonable basis for initial screening of technologies, simple busbar cost information has li mitations. In isolation, busbar cost information h as limited applicability in decision-making because it is highly dependent on the circumstances being considered. A complete analysis of feasible techno logies must include consideration of the interdependence of the technologies within the cont ext of Duke Energy Carolinas’ existing generation portfolio.

9 For purposes of this IRP, wind resources are assum ed to contribute 15% of installed capacity at the t ime of peak and solar resources are assumed to contribu te 40% of installed capacity at the time of peak.145

With lower gas prices combined with larger capaciti es and increased high efficiency, combined cycle is the lowest cost base load technol ogy. However, if these curves incorporated the impacts of CO 2 escalating at a rate higher than inflation after 2 032, as anticipated, the nuclear and CC costs are competiti ve at 90% capacity factor and above.

It is important to note that the capital and operat ing 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 CO 2 once it is captured. The sequestration geology is not favorable in the Carolinas.

Intermediate and Peaking

The following technologies are found on the peak/in termediate 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 L146

The peak and intermediate screening curves include two options for simple cycle CTs with the 7FA unit making up the lower envelope of t he curves. Historically, CTs are limited to peaking generation due to permit restric tions. CCs were shown as a base load technology, however with higher gas prices or not i ncluding the impacts of CO 2 , CC becomes an intermediate technology.

Renewables

The following technologies are found on the renewab le 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 2012-203 2

Simple Cycle (4 CTs) 7FA Simple Cycle (8 CTs) 7EAs 

### C O N F I D E N T I A L147

One must remember that busbar chart comparisons inv olving some renewable resources, particularly wind and solar resources can be somewh at misleading because these resources do not contribute their installed capacit y at the time of the system peak 10 . Since busbar charts attempt to levelize and compare costs on an installed kW basis, wind and solar resources appear to be more economic than the y would be if the comparison was performed on a peak kW basis. In addition, the cos t 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 C O 2 emissions or are deemed to be carbon neutral, the cost of CO 2 emissions does not impact their operating cost. L andfill gas appears to be the least-cost renewable alternat ive 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 assum ed to contribute 15% of installed capacity at the t ime of peak and solar resources are assumed to contribu te 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 L148

APPENDIX D: DEMAND SIDE MANAGEMENT ACTIVATION HIST ORY

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 07/1 2/2011 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 12/1 5/2010
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 01/13/2011149

Time Frame Program Times Activated Reduction Expected Reduction

Achieved Activation

Date 9/09 – 9/10* Air Conditioners Economic Event 46 MW 50 MW 6/14/20 10
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 Test150

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 11/19/2002151

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 9/14/20 00
Water Heaters Communication Test N/A N/A 9/14/200 0 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 5/29/1998152

Time Frame Program Times Activated Reduction Expected Reduction

Achieved Activation

Date 9/96 – 9/97 Air Conditioners Communication Test N/A N/A 6/17/19 97 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 m onthly test event activations.153

APPENDIX E: PROPOSED GENERATING UNITS AT LOCATIONS NOT KNOWN

A list of proposed generating units at locations no t 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 rel iably. Resource additions may be a combination of short/long-term capacity purchases f rom the wholesale market, capacity purchase options, and building or contracting of ne w generation154

APPENDIX F: TRANSMISSION LINES AND OTHER ASSOCIATED FACILITIES PLANNED OR UNDER CONSTRUCTION

NCUC Rule R8-62(p) requires the following informati on:

1. For existing lines, the information required on FERC Form 1, pages 422, 423, 424 and 425: (Please see Appendix J for Duke Energy Carolin as’ current FERC Form 1 pages 422, 423, 422.1, 423.1, 422.2, 423.2, 423.3, 424, 4 25, 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 pro ject is needed to accommodate a transmission service request to trans fer 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 Stat ion. 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 projec ts. This project will replace two existing transformers, with a total cap acity 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 informatio n becomes available:

There are no proposed lines at this time. Informat ion will be added as it becomes available.155156157158159160161162163164165166

GENERATION AND ASSOCIATED TRANSMISSION FACILITIES S UBJECT TO CONSTRUCTION DELAYS

A list of any generation and associated transmissio n facilities under construction which have delays of over six months in the previously re ported 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 d elays:

There are no delays over six months in the stated i n-service dates.

2012 FERC Form 715

The 2012 FERC Form 715 filed March 2012, is confide ntial and filed under seal.167

APPENDIX G: OTHER INFORMATION (ECONOMIC DEVELOPMEN T)

Customers Served Under Economic Development:

In the NCUC Order issued in Docket No. E-100, Sub 9 7, 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 (dema nd) 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 Carolina168

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 Nor th Carolina utilities to provide a separate list of all non-utility electric generatin g facilities in the North Carolina portion of their control areas, including customer-owned and s tandby 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 atte mpted 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 ta bles in this Appendix represent those non-utility generation and stand-by generation cont racts that were signed as of August 1, 2012. It is prudent to note that additional contra cts are in various phases of signing and negotiation, and these tables frequently change. T ables 5.E and 5.F in Chapter 5 also represent a high-level snapshot of some of the whol esale 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 P hotovoltaic Yes Advantage Investment Group, LLC Gastonia 640 Hydroelectric Yes AKS Realty & Development (Solar Tech South) Chapel H ill 3 Photovoltaic Yes Alamance Hydro, LLC Glen Raven 240 Hydro electric 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 Pho tovoltaic Yes Arrowood Construction Franklin 4 Win d Yes Barbara Ann Evans Caroleen 324 Hydroelec tric 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 Ph otovoltaic 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 Phot ovoltaic Yes Bryan C. Turner Durham 7 Photovoltaic Yes Burlington Hydro LLC Burlington 150 Hydr oelectric 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 P hotovoltaic 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 Photovo ltaic Yes Commonwealth Brands Inc. Reidsville 169 Photovoltaic Ye s 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 Ph otovoltaic 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 16 00 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 Phot ovoltaic Yes Diann M. Barbacci Kernersville 2 Pho tovoltaic 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 1 1 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 Mari on 4 Photovoltaic Yes Fogleman Construction, Inc. Graham 3 Photovoltaic Yes Foothills Wineworx Inc. Morganton 24 Photovoltaic Yes Frances L. Thompson Hickory 5 Photov oltaic Yes Friendship Trays, Inc. Charlotte 8 P hotovoltaic Yes Gail D. Schmidt Tryon 3 Photovoltaic Yes Gail Severs Schneitler Pilot Mountain 10 Photovoltaic Y es Gas Recovery Systems, LLC Concord 5,000 Land fill 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 Hyd roelectric Yes Hardins Resources Company Hardens 820 Hy droelectric Yes Haw River Hydro Company Saxapahaw 1,500 Hydr oelectric Yes Hayden-Harman Foundation Burlington 2 Photovoltaic Yes Hendrik J. Roddenburg Chapel Hill 3 Photovoltaic Yes Holzworth Holdings, Inc. Durham 3 Ph otovoltaic Yes Innovative Solar Solutions Charlotte 4 Photovoltaic Yes Irvine River Company Eden 500 Hydroelect ric 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 Photo voltaic 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 Photovo ltaic Yes171

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 Photovo ltaic 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 Photov oltaic Yes Matthew T. Ewers Charlotte 3 Photovoltaic Yes Mayberry Solar LLC Mount Airy 1,000 Photovol taic Yes Mayo Hydropower, LLC Mayodan 951 Hydroel ectric Yes Mayo Hydropower, LLC Mayodan 1,275 Hydroelec tric Yes Megawatt Solar, Inc. Hillsborough 5 Photovoltaic Yes Mehul Shah Huntersville 4 Photovoltaic Yes Michael G. Hitchcock Yadkinville 8 P hotovoltaic 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 Pho tovoltaic Yes Newton-Conover City Schools Conover 135 Photovoltaic Ye s Norris Job Galyan Concord 4 Photovoltaic Yes Northbrook Carolina Hydro, L.L.C. - Turner Shoals Mi ll Spring 5,500 Hydroelectric Yes Nypro INC dba Nypro Carolinas Mebane 222 Photovoltaic Yes Oakdale Holding, LLC Hillsborough 18 P hotovoltaic Yes Oenophilia Hillsborough 18 Photovoltaic Yes Old Dominion Freight Line Inc Thomasville 1, 500 Yes Optima Engineering Charlotte 8 Photo voltaic Yes172

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 Photovolta ic Yes Philip E. Miner Ellenboro 5 Photovoltaic Yes Phillip B. Caldwell Brevard 3 Photov oltaic Yes Pierre Burke Sylva 9 Photovoltaic Yes Pickens Mill Hydro, LLC Charlotte 600 Hy droelectric 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 Ph otovoltaic 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 Photo voltaic Yes RayLen Vineyards, Inc. Mocksville 10 P hotovoltaic Yes Rebecca A. Durante Charlotte 2 Photo voltaic Yes Rebecca G. Laskody Chapel Hill 3 Pho tovoltaic Yes Rebecca T. Cobey Chapel Hill 2 Photo voltaic 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 Ph otovoltaic 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 Hy droelectric 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 P hotovoltaic Yes Strates Inc. DBA Westtown Eatery & Express Winston-S alem 6 Photovoltaic Yes173

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 Photov oltaic Yes Lockhart Power Company Wellford 1,600 Landfi ll 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 Greenvill e 2,400 Hydroelectric Yes Pelzer Hydro Company, Inc. Pelzer 2,020 Hydr oelectric Yes Pelzer Hydro Company, Inc. Pelzer 3,300 Hydr oelectric Yes Thomas W. Bates Simpsonville 5 Photovoltaic Yes174

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 3000175

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 2000176

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 500177

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 2000178

APPENDIX I: WHOLESALE PROJECTIONS FROM EXISTING A ND POTENTIAL CUSTOMERS

Table I.1 below provides the historical and project ed growth in peak loads for the Company’s wholesale customers. The wholesale custo mer growth rates vary. With respect to wholesale sales contracts, the Company h as developed econometric forecasting models for the larger wholesale customer in a proce ss 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 C entral 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 r equirement such that the Company will provide 15% of Central’s total member cooperative l oad in Duke’s Balancing Authority Area requirement in 2013. This initial load requir ement 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 co ntract

The wholesale sales contracts, shown in Table 3.D, are gross loads and are not reduced by the resources that some wholesale entities opera te.179

TABLE I.1 (CONFIDENTIAL)

There are no undesignated wholesale contracts ident ified in the 2012 Duke Energy Carolinas IRP. Duke Energy Carolinas Historical and Projected Load

Municipal Other

Customers 1 Piedmont 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 2001-2 011 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 2012-2 032 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 Conco rd, Kings Mountain, Forest City,Due West, Prosperit y, Dallas, and the electric company Lockhart and Western Carolina, Unive rsity 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 wholes ale to Retail in early 2009.180

APPENDIX J: CARBON NEUTRALITY PLAN

Greenhouse Gas Reduction Compliance Plan – Cliffsid e Unit 6

On January 29, 2008, the NCDAQ issued the Air Quali ty Permit to Duke Energy Carolinas for the Cliffside Unit 6. The Permit spe cifically requires that Duke Energy Carolinas implement a Greenhouse Gas Reduction Plan (Greenhouse Plan), and specifically obligates Duke Energy Carolinas to tak e the following actions in recognition of NCDAQ’s issuance of the Permit for Cliffside Uni t 6: (1) retire 800 MWs of coal capacity in North Carolina in accordance with the s chedule 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 fut ure carbon control technology; and (3) take additional actions to make Cliffside Unit 6 ca rbon 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 f ollowing generating units to satisfy the required retirement schedule set forth in the G reenhouse Plan.

Table J.1 - Cumulative Coal Plant Retirements

1 In the 2012 IRP, this data appears in Table 5.D, pa ge 55. Plant retirements that were applicable to t he first obligation were put in this table. References hav e been updated to match the 2012 IRP.
2 The IRP Retirement Schedule indicates that the ret irements would exceed the Greenhouse Plan by close to 50%.

With respect to obligation (2) listed above, the re quirement 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 prac tical 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 1299181

proposed plan to achieve this requirement is set fo rth below. The Greenhouse Gas Reduction Plan states that the plan for carbon neut rality:

may include energy efficiency, carbon free tariffs, purchase of credits, domestic and international offsets, additional retirements or re duction in fossil fuel usage as carbon free generation becomes available, and carbon reduc tion through the development of smart grid, plug in hybrid electric vehicles or oth er 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 su ch 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 o f the plan from the NCUC as required by the NCDAQ Air Permit. The NCUC’s Order Approvin g 2011 Annual Updates to 2010 Biennial Resource Plans and 2011 REPS Complian ce 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 reductio n standards of the air quality permit and is not approving any individual specific activi ties nor expenditures for any activities shown in the Plan.”

The estimated emissions reductions required to rend er Cliffside Unit 6 carbon neutral in 2018 are approximately 5.3 million tons of carbon d ioxide (the Emission Reduction Requirement). The Company calculated the estimated emission reductions by estimating the actual tons of carbon dioxide emissions that wi ll be released per year from Cliffside Unit 6 less 681,954 tons of carbon dioxide emission s 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 CO 2 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 & 2008 1

Total Increase 5,318,046 Emissions Reduction Requirement

1 The emissions attributable to coal plant retirement s are identified as the highest two year average CO 2 emissions for the five years prior to the operation s of Unit 6 in 2012, consistent with the methodolog y 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 Reduct ions Requirements includes actions from multiple categories and associated met hodologies 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 re leases from coal plant retirements, addition of renewable resources, implementation of energy efficiency measures, nuclear and hydropower capacity upgrades. This also includ es the expected retirement of coalfired operations at Lee Units 1, 2 and 3 in South C arolina in 2015. In addition, carbon dioxide bio-sequestration offsets from the Greentre es program, which sequesters carbon as trees grow, is identified as a Qualifying Action

.

While the reductions associated with retirements fo r each of the coal plants shall be the same each year, the reductions for the remaining Qu alifying Actions will vary based on actual results for each of the categories and the t hen current system carbon intensity factor. The system carbon intensity factor shall b e equal to the actual carbon dioxide emissions of all Company-owned generation dedicated for Duke Energy Carolina customers divided by the megawatt hours generated b y those same resources (the “Conversion Factor”).183

Table J.3 - Qualifying Actions for carbon dioxide emission redu ctions Categories Tons of CO 2 Equivalent Emissions Methodology Description

Buck 3 216,202 Average of emissions in 2007 & 2008 1 Buck 4 139,429 Average of emissions in 2007 & 2008 1 Buck 5 606,837 Average of emissions in 2007 & 2008 1 Buck 6 653,860 Average of emissions in 2007 & 2008 1 Riverbend 4 462,314 Average of emissions in 2007 & 2008 1 Riverbend 5 435,895 Average of emissions in 2007 & 2008 1 Riverbend 6 684,010 Average of emissions in 2007 & 2008 1 Riverbend 7 710,023 Average of emissions in 2007 & 2008 1 Dan River 1 249,900 Average of emissions in 2007 & 2008 1 Dan River 2 282,944 Average of emissions in 2007 & 2008 1 Dan River 3 677,334 Average of emissions in 2007 & 2008 1
Lee 1 5 335,583 Average of emissions in 2007 & 2008 1

Lee 2 5 390,965 Average of emissions in 2007 & 2008 1
Lee 3 5 783,658 Average of emissions in 2007 & 2008 1
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 retirement s are identified as the highest two year average CO 2 emissions for the five years prior to the operation s of Unit 6 in 2012, consistent with the methodolog y for calculating emissions for major modifications under the Clean Air Act Prevention of Significant Deterioration regulations. Company reserves the ri ght to use any credits for reduction of nitrogen ox ide, sulfur dioxide and carbon dioxide emissions generat ed 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 I RP. Actual nameplate capacity is 602 MW. The contribution to peak is 288 MW.
4 Data is a portion of the total capacity addition o n 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 t o natural gas to allow continued operation for peak generation demand only (at a low annual capacity fa ctor). Any CO 2 from operating with natural gas would be subtracted from the reductions shown in the tabl e.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 Requiremen t in 2018. The expected Qualifying Actions total 9.2 million tons of emissi on reductions by 2018. The Company’s proposed Qualifying Actions clearly demonstrate tha t 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 th e 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 r equirements 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 prepar e a comprehensive reserve margin requirements study and include the r esults of such study as part of their 2012 biennial IRPs.

A discussion of the comprehensive reserve margin st udy that Duke Energy Carolinas performed is found in Chapter 8 on page 85.187

b) Each IOU and EMC should investigate the value o f activating DSM resources during times of high system load as a mea ns 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 resou rces.

A detailed discussion of this order is discussed be low:

Dispatching DSM Resources for Fuel Savings In Docket No. E-100, Sub 128, issued October 26, 20 11, 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 reso urces during times of high system load as a means of achieving lower fuel costs by no t having to dispatch peaking units with their associated higher fuel costs if it is le ss expensive to activate DSM resources. This issue should be addressed as a specific item i n 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 Avai lable to Capture Fuel Savings

Duke Energy Carolinas administers and implements a portfolio of DSM resources. Several of these DSM resources are specifically des igned for use only during system emergency conditions, while others may be used as a n economic resource. Resources utilized during system emergency conditions, progra ms such as Interruptible Service (IS), and PowerShare® Mandatory programs are dispatched b y the Duke Energy Carolinas System Operations Center with an emphasis on system reliability. When implemented, these programs may capture fuel savings during thes e emergency implementations but cannot be dispatched in the absence of emergency co nditions (i.e. economically) unless changes are made to the programs.

In contrast, Duke Energy Carolinas primarily implem ents the Power Manager ® DSM resource for economic use and captures fuel savings when the power supply from generation options results in a relatively high mar ginal price. Utilizing DSM resources economically only on high marginal cost days mainta ins the number of activations at a reasonable level, and thus retains customer partici pation in these programs.

This discussion will concentrate on the Power Manag er ® 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 participa tion in the PowerShare® Voluntary program produced relatively small load reduction am ounts (i.e., average load reduction188

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 DS M Resources

DSM resources can provide both avoided capacity cos t benefits and avoided energy cost benefits. The capability to use Power Manager ® for economic implementation was provided in Duke Energy Carolinas’ filings in Docke t 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 fro m the summer of 2011, Duke Energy Carolinas explores the value of using the Power Man ager ® 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 th e 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 thr oughout 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 NPV s incorporates the rebound impacts of AC units using more energy after event hours tha n they would have used during the same hours had the event not occurred. The value c aptures price differentials between on-peak hours and off-peak hours. The energy valu es 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 Hours189

approximately $337 Million over a 15 year period fo r 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 DS M Resources

To address DSM resource implementation from the par ticipant’s perspective, Duke Energy Carolinas has gathered data from three sourc es to investigate customer reaction to increased program implementation, including a measu re of their behavioral response (i.e., their decision to continue or terminate their parti cipation 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 dissati sfied. The primary message Duke Energy Carolinas takes from the E-Source respo nse is that participants should be engaged and “trained” on how the program works and the expectations of program implementation. This will allow custome rs to make an informed decision about participating in demand response pro grams. Duke Energy Carolinas will also carefully manage the cost of ad ditional communications and customer training to avoid expenses beyond the savi ngs provided by economic event implementation.

2. Primary Research Study with Power Manager® Particip ants and Nonparticipants : 532 Power Manager ® Participants and 700 Power Manager ® nonparticipants responded to a survey. The primary ob jective of this study was to investigate how customers would respond if program implementation increased up to approximately 100 hours each summer. This st udy 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 t hat participating customers are very concerned with the end time of an event. Ther efore, 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 Progra m Comments from Duke Energy Carolinas DSM Program Managers

a. PowerShare® Voluntary – Experience shows that event participation is low unless participant perception is that the syste m is stressed and an emergency could be pending. It is assumed that the large commercial and industrial customer participants are cognizant of t he differential costs of curtailment versus the commitment to produce or ser ve their customers. Those costs or profits, are likely greater than the incentives possible through DSM avoided energy incentives. Most load r eduction from this program is captured during emergency and close-to-e mergency events. b. PowerShare® CallOption – For the summer of 2011, t here 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 P ower Manager® program that allows for both economic and emergency implementation. This allows the capture of some of the additional b enefit of avoided energy costs and provides increased operational fle xibility. Prior to the summer of 2012, it was uncertain if a transition fr om an economic cycling event to an emergency full-shed event would functio n properly. During that time, on days when emergency events were consi dered possible, a Power Manager® economic cycling event was not imple mented. The System Operations Center no longer requires that ec onomic implementation be withheld now that upgraded system s will reliably transition from an economic event to an emergency e vent, if needed.

D. Duke Energy Carolinas’ Current and Recommended DSM Implementation
Process

Duke Energy Carolinas has established a portfolio o f DSM programs to allow customers to select their level of involvement with demand re sponse programs. Duke Energy Carolinas frequently communicates with customers ab out their program choices. Customers also benefit from savings through economi c implementation of the programs. In addition, several programs are under considerati on to provide customers more options and more active involvement with economic implement ation 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® device s with new functioning
devices

Conclusion: Based on the research analyzed for the Power Manager ® program, an increased number of short duration events ending ea rly 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 betw een avoided capacity cost benefits and avoided energy cost benefits, the increased imp lementation strategy must be implemented slowly in order to monitor customer per ception and closely track program enrollment levels. This new bias towards implement ation can start as early as the summer of 2013. Therefore, Duke Energy Carolinas p lans to continue its current economic event implementation process with a slight ly 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 Ma rket 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 REP S 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 th e next.

The projected total annual MWh load reductions asso ciated with EE programs included in the base case for this 2012 IRP are mor e than 10% higher than those included in the 2011 IRP base case, primarily due t o 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 appro ximately the same total cumulative achievements, including actual achieveme nts since 2009, by 2023 that were projected to be achieved by 2031 in the 2011 I RP.194

b. Each IOU shall include a discussion of the statu s of market potential studies or updates in their 2012 and future IRPs.

In 2011, Duke Energy commissioned an independent Ma rket Potential Study for both the North Carolina and South Carolina service territori es. This study was prepared by Forefront Economics Inc. and was completed in Decem ber of 2011. The results of this Market Potential Study were incorporated into the E nergy 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 I ntegrated Resource Planning in North Carolina addressing Smart Grid Technology Pla ns , 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 IR P.

b. The Smart Grid Technology Plan – By July 1, 2013 and every two years thereafter, each utility subject to Rule R8-60 shal l file with the Commission its smart grid technology plan. Significant amendments or re visions to a smart grid technology plan shall be reported to the commission in each ye ar in which the biennial smart grid technology plan is not required to be filed.

A discussion of the Smart Grid Impacts and the Smar t 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 requirem ents 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 Resour ces Ch 5, Sec B NC R8-60 (e) Yes Assessment of Demand-Side Management Ch 4, App D NC R 8-60 (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 Deman d-Side

Resources * 10-year History of Customers and Energy Sal es Ch 3 & App B NC R8-60 (i) 1(i) Yes * 15-year Forecast w & w/o Energy Efficiency C h 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 Po wer * Wholesale Purchased Power Contracts Ch 5, Se c 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 Resour ces * 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 C h 5, Sec C & App C NC R8-60 (i) 7(ii) Yes Evaluation of Resource Options (Quantitative Analys is) 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