DUKE ENERGY® CAROLINAS

I

i I fE PJVERBEND— rated Resource Plan (X ONFE

BUZZARD (Annal Report) --4

October 15, 2013

Public DEC 2013 IRP TABLE OF CONTENTS

PACE

ABBREVIATIONS 2

1. EXECUTIVE SUMMARY 4

2. SYSTEM OVERVIEW 10

3. ELECTRiC LOAD FORECAST 13

4. ENERGY EFFICIENCY ANI) DEMANI) Sll)E MANAGEMENT 15

5. RENEWABLE ENERGY REQUIREMENTS 17

6. SCREENING OF GENERATION ALTERNAI1VES 22

7. RESERVE CRITERIA 23

8. EVALUATION AND DEVELOPMENT OF THE RESOURCE PLAN 25

9. SHORT TERM ACTION PLAN 38

APPEN1)IX A: QUANTI’I’ATlVE ANA LYSIS 43

APPENDIX B: I)UKE ENERGY CAROLINAS OWN El) GLNERAI’ION 52 APPENDIX C: ELECTRIC i,OAD FORECAST 64 APPENDIX I): ENERGY EFFiCiENCY AND I)EMANI) SIDE MANAGEMENT 74 APPENI)EX F: FUEL SUPPLY 93

APPEN1)IX F: SCREENING OF GENERATION ALTERNA’IiVES 95

APPENDIX G: ENVIRONMENTAL COMPLIANCE 102

APPENDIX II: NON-Ul1L1tY GENERATION ANI) WHOLESALE 110

APPENDIX I: TRANSMISSION PLANNEI) OR tiNDER CONSTRUCI1ON 130

APPENI)IX J: ECONOMIC I)EVELOPMENT 134

APPENDiX K: CROSS-REFERENCEFO 2013 IRP 135

ATTACIIMFN’I’: NC REPS COMPLIANCE PLAN 136 ABBREVIATIONS

CAIR Clean Air Interstate Rule CAMR Clean Air Mercur Rule CC Combined Cycle CCR Coal Combustion Residuals CECPCN Certificate of EnvironmentalCompatibilityand Public Convenience and Necessity CFI, Compact Fluorescent Light bulbs CO Carbon Dioxide COD Commercial Operation Date COL Combined Construction and Operating License COWICS Carolinas Offshore Wind IntegrationCase Study CPCN Certificate of Public Convenience and Necessity CSAPR Cross State Air Pollution Rule CT Combustion Turbine DC l)irect Current DEC Duke Energy Carolinas I)EP l)uke Energ) Progress DOE Department of Energy DSM Demand Side Management EE Energy Efficiency EIA Energy Information Administration EPA Eiwironmental Protection Agenc) EPRI Electric Power Research Institute FERC Federal Energy Regulatory Commission FGD Flue Gas Desulfurization FLG Federal Loan Guarantee GHG Greenhouse Gas IIVAC Heating. Ventilation and Air Conditioning IGCC Integrated Gasification Combined Cycle IRP Integrated Resource Plan IS Interruptible Service JDA Joint Dispatch Agreement LCR‘Fable Load. Capacity. and Reserve Margin Fable LEED Leadership in Energ) and Environmental Design MACI Maximum Achievable Control Technology MATS Mercur’ Air Toxics Standard NAAQS National Ambient Air QuaIit Standards NC North Carolina NCDAQ North Carolina Division of Air Quality NCEMC North Carolina Electric MembershipCorporation NCMPAI North Carolina Municipal Poer Agency l NCUC North Carolina Utilities Commission

7 ABBREVIATIONS CONT.

NERC North American Electric Reliability Corp NO Nitrogen Oxide NPDES National Pollutant Discharge Elimination System NRC Nuclear ReguIator Commission NSPS Ne Source Performance Standard PD Power Delivery PEV Plug-In Electric Vehicles PMPA Piedmont Municipal Power Agency PPA Purchase Power Agreement PPI3 Parts Per Billion PSD Prevention of Significant Deterioration PV Photooltaic PVDG Solar Photovoltaic Distributed Generation Program PVRR Present Value Revenue Requirements QF Qualifying Facility RCRA Resource Conservation Recovery Act REC Renewable Energy Certificates REPS Renewable Energy and Energ Efficiency Portfolio Standard

I RFP Request for Proposal RIM Rate Impact MeasLire RPS Renewable Portfolio Standard SC South Carolina SCPSC South Carolina Public Service Commission SCR Selective Catalytic Reduction SEPA Southeastern Power Administration SERC SERC Reliability Corporation SG Standby Generation SIP State Implementation Plan SO Sulfur Dioxide TAG Technology Assessment Guide TRC Total Resource Cost The Company Duke Energy Carolinas ‘[he Plan I)uke Energ Carolinas Annual Plan LICT Utilit) Cost test VACAR VirginialCarolinas VAR Volt Ampere Reactive

3 I. EXECUTIVE SUMMARY

Each year L)ukeEnergy Carolinas (DEC or the Company) is required by both the North Carolina Utilities Commission (NCUC’)and the South Carol lila Public Service Commission (SCPSC) to submit a planning document to ensure that it can reliably and af’lbrdahiy meet the energy needs ol its cusWrners well into the future.

This year, in addition to providing a traditional standalone Base Case resource plan within the 2013 Integrated Resource Plan (1RP) Update, the Company has also developed an alternative Joint Planning Scenario that examines tile henelits of a coordinated energy and capacity expansion plan with I)uke Energy Progress (DEP).

DEC does not currently have tile regulatory approvals required to implement this joint plan, however this scenario simply begins to examine the potential benefits that would accrue to customers once T)EC and I)EP coordinate new resource additions between the companies. Ally benefits that would accrue from new jointly planned resources would be in addition to the current merger savings already being realized through the Joint I)ispatch Agreement (JI)A) and fuel procurement activities associated with existing generation resources.

Increased Energy Efficiency/Demand Side Management

I)uke Energy continues to expand its portfolio of energy efficiency products and services — offering customers more ways to take control of their energy usage and save money.

T)EC’s Energy Efficiency (EE) programs encourage customers to save electricity by installing high-efficiency measures and/or changing tile way they use their electricity.

I)EC also offers a variety of Demand Side Management (DSM) programs that signal customers to reduce electricity use during select peak hours as specified by the Company.

• Energy Eliciency programs and [)emand Side Management, combined with the use of renewable energy resources are expected to meet approximately one third of the projected growth in customer demand over the next 15 years. This equates to over 2,400 MW of new energy efficiency, demand side management and renewable resources or the eq ii ivalent of three large natural gas—generation flueii ities.

• Aggressive marketing and increased adoption of energy efficiency programs reduce the

annual forecast demand growth from I .9 to 1.5%.

4 • DEC will continue to seek Commission approval to implement new DSM and EE programs that are cost effective and consistent with DECs forecasted resource needs over the planning horizon.

Growth of Renewable Energy and Solar Resources

The Company continues to purchase renewable energy on behalf of our customers and make investments that support our delivery of clean. reliable and alfordahie electricity.

DEC’s strategy to comply with the North Carolina Renewable Energy and Energy Efficiency Portfolio Standard (NC REPS) is to develop a diverse portfhlio of cost-effective renewable resources including long—term Purchase Power Agreements (PPAs), utility—owned generation, and energy efficiency.

I)EC is committed to meeting the requirements established under the NC REPS and to procuring renewable energy in a way that minimizes costs for customers. The Company remains on target to meet these standards within the cost caps established under NC REPS. The Base Case also assumes the addition of future SC. renewable resources that could be driven by regulatory mandates or market-based threes.

Solar energy is an important part of the energy future for the Carolinas. As the net price olsolar technologies including tax incentives continues to decrease. customer use of solar continues to increase.

• The growth of solar energy has been spurred by several factors, including stale and federal subsidies that are expected to be in place through 201 5 and 201 7, respectively.

• Substantial tax subsidies and declining costs make solar energy the Company’s primary renewable resource projected within the NC REPS compliance plan.

• The Company’s plan currently prq)ects that by the end ot the planning horizon, the Company will have met over 700 MW of peak demand through solar resources - the equivalent of one large natural gas facility.

Retiring Older, Less Efficient Coal Units

Duke Energy Carolinas is investing in a brighter energy future lhr its more than 2.4 million customers in North and South Carolina. The Company has built some of the cleanest, most efficient natural gas plants to replace aging, less efficient generation facilities in order to provide essential

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is is Natural Gas: Meeting Future Customer Demand

Modernizing the power plant fleet is an important investment in the Carolinas’ environment and its Future. Because the Company continues to retire older, less efficient coal plants, new incremental resources must be added to the I)EC system. New resources are also required to keep up with increasing customer demand.

Aher accounting for the previously-discussed impacts of [)EC’s EL, DSM and renewable resources, the Company projects it will meet its customers’ remaining requirements with a combination of natural gas and nuclear resources.

‘Fhe2013 IRP identifies the need fi)r new natural gas plants that are economic, highly efficient and reliable. The following natural gas resources are included in the plan for the 2014 through 2028 planning horizon:

• 2015 — Convert a 170 MW coal unit to natural gas at the Lee Steam Station in S.C. • 2017— Construct a new 680 MW natural gas CC generation facility • 2019— Procure or construct 843 MW of natural gas CC generation • 2022 — Procure or construct 403 MW of simple cycle combustion turbines (Ci’s)

Nuc’ear Generation

1)uke Energy Carolinas believes nuclear generation is important for the long-term benefits of its customers — today and in the future. ‘l’he2013 [RP continues to support new nuclear generation as a carbon—free,cost—effectiveoption within the Company’s resource portfolio.

• W.S. Lee Nuclear Station, Cherokee, S.C. — DEC continues to pursue nuclear expansion options at the proposed site. Currently a new and updated site-specific seismic analysis is being conducted at the request of the Nuclear Regulatory Commission. Completion of this report delays licensing and pushes the project completion date to 2024.

• V.C’. Summer Nuclear Plant, Fairfield. S.C. - [)iscussions also continue with Santee Cooper to possibly purchase an interest in two units under construction at the V.C. Summer Nuclear Plant in Fairfield County. S.C. in the 201 8 through 2020 timeframe.

‘I’hetable below illustrates the Companys optimal Base Case resource plan that includes the gas and nuclear additions described above. As discussed, in addition to these traditional resources. the Base Case also includes approximately 2,400 MW of EL, DSM and renewable resources.

7 Table 1-A DFC Base Case

Duke Energy Carolinas Resource Plan Base Case

Year I j Resource — MW 2014 2015 2016 2017 2018 2019 2020 2021 - - onn 2022 - 2023 . - 2024 2025 2026 2027 - -

2028 - - Nate fable inc-ndcs both designated and undesignated capacity additions

One Company: The Benefits of Shared Capacity

DEC also examines a Joint Planning Scenario which shows the impact of capacity sharing between DEC and DEP. This exercise starts by combining the future load obligations of the two companies and combining the existing and projected resources from both [)EC’s and DEP’s independent Base Case plans. [-lowever, rather than maintaining utility-specific individual minimum reserve margins, the Joint Planning Scenario simply ensures that the combined system maintains adequate reserves when viewed in the aggregate.

The sharing of capacity between the systems defers the need tbr new additions of generation. If [)EC and l)EP receive the appropriate regulatory approvals to allow for the sharing of resources, the Joint Planning Scenario illustrates how benefits would accrue to both companies customers by delaying investment in new generation.

Federal Regulations and Future Market Conditions

With the information and data currently available, the 2013 IRP is a best projection of what the Company’s energy portfolio will look like 15 years from now. This projection can change and will change depending on changing load forecasts, energy prices, new environmental regulations and other outside factors.

8 Environmental Focus Scenario

What if there is an aggressive new carbon tax in 10years’? Or additional new government mandates are required ol electric utilities? The Company has created an l.nviromnental Focus Scenario that factors in significant increases in EF and renewable resources that would influence the plan ii regulatory, legislative, or market conditions changed from todays base assumptions to support such increases. This scenario examines how the amount of traditional supply—sideresources would change if future market conditions andlor state and federal regulations resulted in higher levels of energy ef1ciency and renewable resources.

*****************

The following chapters give an overview of the inputs incorporated into the 2013 IRP. Chapter 8 provides insight into the planning process itself and reviews the results of the Base Case resource plan as well as the two alternative scenarios developed in this planning cycle. Finally, the appendices to this document give even greater detail and specifics regarding the input development and analytic process that produced the resource plans contained in this year’s IRP filing.

9

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the of 3. ELECTRIC LOAD FORECAST

The [)uke Energy (‘aroIinas spring 2013 forecast provides projections of the energy and peak demand needs fbr its service area. The forecast covers the time period of 2014 thmugh 2028 and represents the needs of the retail classes and the wholesale buyers with whom [)EC has a contractual obligation to serve.

Long—termelectricity usage is determined by economic and demographic trends. The 2013 spring forecast was developed using industry-standard linear regression techniques, which relate electricity usage to such variables as income, electricity prices and the industrial production index along with weather and population. 1)EC has used regression analysis since 1979 and this technique has yielded consistently reasonable results over the years.

‘l’heeconomic projections used in the spring 2013 tbrecast are obtained from Moody’s Analytics, a nationally recognized economic forecasting firm, and inclLideeconomic tbrecasts br the slates of North Carolina and South Carolina.

The retail forecast consists of the three major classes: residential, commercial and industrial.

The residential class sales forecast is comprised of two projections. The first is the number of residential customers, which is driven by population. 1he second is energy usage per customer, which is driven by weather, regional economic and demographic trends, electricity price and appliance efficiencies. i’he usage per customer forecast is essentially flat through much of the forecast horizon, so most growth is primarily due to customer increases. The projected growth rate of residential sales in the spring 2013 Ibrecast from 2014-2028 is 1.2% annually.

Commercial electricity usage changes with the level of regional economic activity, such as personal income or commercial employment, and the impact of weather. The three largest sectors in the commercial class are olbices, education and retail. Commercial is expected to be the fastest growing class, with a projected sales growth rate of 1.8%.

The industrial class tbrecast is impacted by the level of manufhcturing output, exchange rates, electric prices and weather. The long—termstructural decline that has occurred in the textile industry is expected to moderate in the forecast horizon, with an overall projected sales decline of I.2%, compared to an average decline of 7.2% from 1997—2012. In the other industrial sector, several industries such as autos, rubber and plastics and primary metals, are projected to show strong growth. Overall, other industrial sales are expected to grow 0.9% over the forecast horizon. Including all industrial classes, the overall sales growth rate of the total industrial class is 0.6% over the Ibrecast horizon.

13 Including the impacts of DEC’s FE programs, the projected average annual growth rate from 2014 through 2028 is 1.5% tbr summer peak. 1.5% for winter peak and 1.5% fhr energy. Ihese groth rates represent a 4,164 MW increase in capacity and 20,826 MWh increase in energy by 2028.

Compared to the spring 2012 forecast, the spring 2013 Ibrecast reflects lower growth, due to a slightly slower economic outlook. For example, the growth rate of the summer peak afler all adjustments in the spring 2012 ibrecast is 1.7% versus 1.5% in the new forecast.

The load tbrecast projection tbr energy and capacity including the impacts of EE that was utilized in the 2013 IRP is shown in Table 3-A.

Table 3-A Load Forecast with Energy Efficiency Programs

YEAR SUMMER ENERGY (MW) (CWh) 2014 18,332 92,943 2015 18,691 94,721 2016 19,053 96,475 2017 19,398 98,226 2018 19,741 100,032 2019 20,117 101,678 2020 20,359 102,948 2021 20,598 104,187 2022 20,848 105,469 2023 21,104 106,748 2024 21,378 108,089 2025 21,643 109,418 2026 21,922 110,825

2027 22,209 112,294 2028 22,496 113,769 i.ote: Table 8-C differs from thesevalues due to a 150 MW firm sale in 2014 and a 47 MW Piedmont Municipal Power Aoenc (PMPA) hacksand contract through 2020

A detailed discussion of the electric load forecast is provided in Appendix C.

‘4 4. ENERGY EFFICIENCY AND DEMAND SII)E MANAGEMENT

I)EC is committedto making sure electricity remains available, reliable and affordable and that it is produced in an environmentally sound manner and, therefore, advocates a balanced solution to meeting future energy needs in the Carolinas. That balance includes a strong commitment to demand side management and energy efficiency.

Since 2009, I)EC has been actively developing and implementing new I)SM and EF programs throughout its North Carolina and South Carolina service areas to help customers reduce their electricity demands. DEC’s [)SM and hE plan was designed to be flexible, with programs being evaluated on an ongoing basis so that program refinements and budget adjustments can he made in a timely fashion to maximize benefits and cost-effectiveness. Initiatives are aimed at helping all customer classes and market segments use energy more wisely. The potential for new technologies and new delivery options is also reviewed on an ongoing basis in order to provide customers with access to a comprehensive and current portfOlio of programs.

DEC’s EE programs encourage customers to save electricity by installing high efficiency measures and/or changing the way they use their existing electrical equipment, [)EC evaluates the cost- effectiveness of DSM!EE programs from the perspective of program participants, non-participants, all customers as a whole and total utility spending using the ibur California Standard Practice tests (i.e., Participant Test, Rate Impact Measure (RIM) Test, Total Resource Cost (‘l’RC) Test and Utility Cost Test (UCI’), respectively) to ensure the programs can he provided at a lower cost than building supply-side alternatives. The use of multiple tests can ensure the development of a reasonable set of programs and indicate the likelihood that customers will participate. DEC will continue to seek Commission approval to implement DSM and EE programs that are cost—effective and consistent with DEC’s forecasted resource needs over the planning horizon. DEC currently has approval from the NCUC and SCPSC to offer a large variety of EL and 1)SM programs and measures to help reduce electricity consumption across all types of customers and end-uses.

[‘or IRP purposes, these EL-based demand and energy savings are treated as a reduction to the load forecast, which also serves to reduce the associated need to build new supply-side generation, transmission and distribution facilities. DEC also offers a variety of DSM (or demand response) programs that signal customers to reduce electricity use during select peak hours as specified by the Company. [he IRP treats these “dispatchable” types of programs as a resource option that can he dispatched to meet system capacity needs during periods of peak demand.

‘to better understand the long-term hE savings potential. DEC commissioned an update to the 2011 market potential study performed by Forefront Economics Inc. for the purpose of estimating the achievable potential fOr EE on an annual basis over a 20-year forecast period. ‘[he results of the market potential study are suitable for integrated resource planning purposes and use in long-range

15

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of by as Hydrogenerationremainsa valuableand significantpart of the generatingfleet for the Carolinas. Thepotentialforadditionalhydrogenerationon a commerciallyviablescaleis limitedandthe cost and feasibilityarc highly site-specific. Giventhese constraints,hydro is not includedin the more detailedevaluationsbut may be consideredwhensite opportunitiesare evidencedand the potential is identified. DECwill continueto evaluatehydroopportunitieson a case-by-casebasisand will includeitas a resourceoptionif appropriate.

In general, the Company expects a mix of resources will ultimately be used for meeting renewabletargets,with the specificsof that mix determinedin largepart by policydevelopments over the coming five to ten years. Costs for all the resources discussed above are highly dependentupon future subsidies, or lack thereof, and the Company’s procurementefibrts will vary accordingly. Furthermore,the Company values portfolio diversificationfrom a resource perspective,particularlyin lightof the varyingproductionprofilesof the resourcesin question.

Further Details on Compliance with NC REPS

A moredetaileddiscussionof the Company’splans to comply with the NC REPSrequirements can be found in the Company’s NC REPS Compliance Plan (Compliance Plan), which is providedas an Attachmentto this document

Details of that Compliance Plan are not duplicated hcre, although it is important to note that various details of the NC REPS law have impacts on the amount of energy and capacity that the Company projects to obtain from renewable resources to help meet the Company’s long- term resource needs. For instance,NC REPS contains several detailed parameters, including technology-specificset-aside requirements for solar, swine waste and poultry waste resources; capabilities to utilize EE savings and unbundled REC purchases from in-state or out-of-state resources and RECs derived from thermal (non-electrical) energy; and a statutory spending limit to protect customers from cost increases stemming from renewable energy procurement or development. Each of these features of NC REPS has implications on the amount of renewableenergy and capacity the Company forecasts to obtain over the planning horizon of this IRP. Additional details on NC REPS compliance can be found in the Company’s CompliancePlan.

The Company continues to see an increasingamount of alternative energy resources in the transmissionand distributionqueues. These resources are mostly solar resources,due to the combinationof federaland state subsidiesto encouragesolar development. This combinationof incentiveshas ledsolarto be the primaryrenewableresourceprojectedin the Company’sNC REPS CompliancePlan. Withstate incentivesscheduledto end in 2015and federalincentivesscheduled to be reducedinthe sametimeperiod,the exactamountof solarthat will ultimatelybe developedis highlyuncertain. If tax incentiveswere to be extendedor significantadditionalcost reductionsin

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in a 8. EVALUATION AND DEVELOPMENT OF THE RESOURCE PLAN

To meet the ftiture needs of DEC’s customers, it is necessary for the Company to adequately understand the load and resource balance. For each year of the planning horizon, 1)EC develops a load forecast of energy sales and peak demand. ‘E’odetermine total resources needed, the Company considers the load obligation plus a 14.5% minimum planning reserve margin. ‘Ihe projected capability of existing resources, including generating units, FE and [)SM, renewable resources and purchased power contracts, is measured against the total resource need. Any deficit in future years will be met by a mix of additional resources that reliably and cost-effectively meet the load obligation while complying with all environmental and regulatory obligations. It should he noted that DEC considers the non-firm energy purchases and sales associated with the iDA with 1)EP in the development of its independent l3ase Case resource plan and two alternative scenarios to be discussed later in this chapter and in Appendix A.

Figure 8-A represents a simplified overview of the resource planning process. Appendix A of the Company’s 2013 1RP provides a detailed discussion of the development ol the resource plan.

Figure 8-A Simplified IRP Process

Portfolio Development Resource Plan Data Inputs &Detailed “Quantitative” f Analysist “Qualitative” • Load Forecast • Generation Alternative • Fuel Diversity • Fuel Price Forecasts Screening • Environmental • Existing Generation • Expansion Plan Modeling Footprint • Energy Efficiency • Minimization of Revenue • Flexibility • Demand Response Requirements • Rate Impact • Renewable Resources • New Generation • Environmental Legislation

25 DEC performed its expansion plan modeling under Base Case assumptions that were updated as compared to its 2012 IRP. In addition to an updated Base Case expansion plan, DEC also considered an Environmental Focus Scenario that includes a greater amount of renewable resources and EE, as well as changes to other assumptions, such as fuel and 2CO prices. Finally, DEC and I)EP examined the potential benefits of sharing capacity as represented in a common Joint Planning Scenario.

Data Inputs

DEC utilizes updated data to develop its resource plan. For the 2013 FRP,data inputs such as load forecast, EE and DSM, fuel prices, projected 2CO prices, individual plant operating and cost information, and future resource information were updated. These data inputs were developed and provided by company subject matter experts and/or based upon vendor studies, where available. Furthennore, DEC and DEP benefitted from the combined experience of both utilities’ subject matter experts by utilizing best practices from each utility in the development of their respective IRP inputs. Where appropriate, common data inputs were applied.

As expected, certain data elements and issues have a larger impact on the plan than others. Any changes in these elements may result in a noticeable impact to the plan, and as such, these elements are closely monitored. Some of the most consequential data elements are listed below. A detailed discussion of each of these data elements has been presented throughout this document and is examined in more detail in the appendices to this document.

• Load Forecast • EE/DSM • Renewable Resource Projections • Fuel Costs • Technology Costs and Operating Characteristics • Environmental Legislation • Nuclear Issues

Generation Alternative Screening

DEC reviews generation resource alternatives on a technical and economic basis. Resources also must he demonstrated to be commercially available lhr utility scale operations. The resources that are thund both technically and economically’viable are then passed to the detailed analysis process further analysis.

26

resource

reserves

resources, required represents

and

Company’s

methods

Resource

DEC Base

Scenario Requirements In with determine

expansion

1’he input Portfolio [he

the

Load portfolio

DEP.

Case

produced an step

2013

gap. and

were

fbr between

objective

De3’eloplneiIt Plans

the

a

and designated planning

to

2012 non-firm

IRP,

However,

1)EC

thus,

development derive and best

analyzed.

Resource an

a

IRP

is updated

mix

I)EC

to the

Base of models

environmentally

resource

energy

meet

resource

filing

of’

selecting

and resource

the and

Case Balance

capacity

and Base

and

DetaikdA its

Base

and

only

DEP portlolios

along

detailed load

detailed

additions

Case

plan does

a

Chart

Case commitment

additions

robust where

sound obligation

with

analysis

not

resource

iialysis analysis

production

shown incorporates

or

and take

an

appropriate. plan

complying resource frr

lnvironmental

EE

into will

27

plan the

between

plus in

phase

that

Chart

resources (oiupanys

costing

account

determine utilizing

plans.

required

minimizes

the

utilizes

with

the

8—B

‘I’his JDA models.

all

the companies. ‘[his

Focus

do

consistent

the illustrates

stale

reserves. the

short—

plan

sharing

between

not the inlomation

step most and

Scenario

The

represents meet and

Present

in

of federal assumptions the

goal

robust The long—term

the

DEC

capacity the

resource

and

ol compile(I

[RP existing Value

regulations.

required

plan an

the

and a process

Joint

between update modeling

resource to

and DEP need

of

generating

in

meet load Planning

Revenue

analytic the

utilizes

that

to

which I)EC plans is

data

and this the to is Chart 8-B DEC Load Resource Balance

27 DEC- Load Resource Balance 26

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

• Existing Resources • Designated Resources (mci Uprates) I Non-traditional Resources (DSM, Renewable) D Resource Gap

Cumulative Resource Additions to Meet Load Obligation and Reserve Margin (MW)

Year 2014 2015 2016 2017 2018 2019 2020 2021 ResourceNeed - - 37 317 573 941 1,172 1,425

Year 2022 2023 2024 2025 2026 2027 2028 Resource Need 1,682 1,935 2,218 2,463 2,753 3,064 3,358

Tables 8-C and 8-D present the Load, Capacity and Reserves tables fhr the Base Case analysis that was completed for DEC’s 2013 IRP.

28 Table 8-C Load, Capacity and Reserves Table - Summer

Summer Projections of Load, Capacity, and Reserves for Duke Energy Carolinas 2013 Annual Plan

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2026 2026 2027 2028

Load Forecast 1 Duke System Peak 18,490 18,922 19,375 19,827 20.278 20.764 21,114 21417 21.776 22,143 22.488 22,862 23,240 23.613 23.974 2FirmSale 150 0 0 0 0 0 0 0 0 0 0 0 0 0 0 3 Cumulative New EE programs (111) (184) (275) (382) ç490) (600) (708) (819) (929) (1.040) (1.110) (1.219) (1.318) (1,404> (1.477)

4 Adjusted Duke System Peak 18,529 18.738 19,100 19,445 19,788 20,164 20,406 20,598 20,848 21,104 21,378 21,643 21,922 22,209 22,496

Existing and Designated Resources 5 Generalrng Capacity 20,366 20.386 20.218 20,218 20,263 20,263 20.263 20,259 20.259 20,259 20,259 20,259 20.259 20.259 20,259 6 Designated Additions / Uprates 20.3 202 0 45 0 0 0 0 0 0 0 0 0 0 0 7 Retirements / Derates 0 (370> 0 0 0 0 (4) 0 0 0 0 0 0 0 0

8 Cumulative Generating Capacity 20,386 20,218 20,218 20,263 20.263 20,263 20,259 20,259 20,259 20,259 20,259 N 20,259 20,259 20,259 20,259 ‘C Purchase Contracts 9 Cumulative Purchase Contracts 251 238 230 227 227 169 166 79 66 56 46 46 46 45 25

Undesignated Future Resources 10 Nuclear 0 0 0 0 66 0 66 0 0 0 1,117 0 1,117 0 0 11 Fossil 0 0 0 680 0 843 0 0 403 0 0 0 0 0 0

Renewables 12 Cumulative Renewables Capacity 185 287 316 340 425 519 572 626 668 718 760 818 847 866 921

13 Cumulative Production Capacity 20,823 20,744 20,764 21,510 21,661 22,540 22,653 22,619 23,051 23.091 24,240 24,298 25,444 25,462 25,497

Demand Side Management (DSM) 14 Cumulative DSM Capacity 911 1,010 1,068 1,118 1169 1,196 1,196 1,196 1,196 1,196 1,196 1,196 1,196 1,196 1,196

15 Cumulative Capacity WI DSM 21,733 21,754 21,832 22.628 22,830 23,736 23,848 23,815 24,246 24,287 25,435 25,493 26,640 26,658 26,692

Reserves wi DSM 16 Generating Reserves 3.204 3.016 2.732 3,183 3,042 3.572 3.442 3,217 3,399 3,183 4.057 3.850 4,718 4,448 4.196 17 Reserve % Margin 17.3% 16.1% 14.3% 16.4% 15.4% 17.7% 16.9% 15.6% 16.3% 15.1% 19.0% 17.8% 21.5% 20.0% 18.7% Table 8-fl Load, Capacity and Reserves Table — Winter

Winter Projections of Load, Capacity and Reserves for Duke Energy Carolinas 2013 Annual Plan

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

Load Fore cast I Duke System Peak 17,717 18,177 18,595 19,000 19.410 1 9,818 20,165 20,463 20,803 21,150 21,510 21866 22,234 22,589 22,938 Firm Sale 2 25 0 0 0 0 0 0 0 0 0 0 0 0 0 0 3 Cumulative New EE Programs (64) (123) (194) (276) (397) (486) (572) (661) (748) (837) (923) (1,013) (1,094) (1,164> (1.225)

Adjusted 4 Duke System Peak 17.678 18,053 18.401 18.724 19,013 19,332 19,593 19,802 20,054 20,313 20,588 20,853 21,140 21,425 21.713

Existing and Designated Resources Generating 5 Capacity 21.927 21.219 21,239 21,071 21,071 21.116 21,116 21,116 21,112 21,112 21.1/2 21,112 21.112 21,112 21,112 6 Designated Additions / Uprates 2 20 202 0 45 0 0 0 0 0 0 0 0 0 0 7 Retirements I Derates (710> 0 (370) 0 0 0 0 (4) 0 0 0 0 0 0 0

8 Cumulative Generating Capacity 21.219 21,239 21,071 21,071 21,116 21,116 21,116 21,112 21,112 21.112 21,112 21,112 21,112 21,112 21,112

Purchase Contracts 9 Purchase Cumulative Contracts 229 216 210 210 210 152 149 56 43 33 23 23 23 23 23

Undesignated Future Resources 10 Nuclear 0 0 0 0 0 66 0 66 0 0 0 1,117 0 1.117 0 Fossil 11 0 0 0 0 711 0 875 0 0 443 0 0 0 0 0

Renewabies 12 Cumulative Renewables Capacity 62 112 119 127 134 168 214 221 234 238 252 260 270 268 263

13 Cumulative Production Capacity 21,509 21,567 21,400 22,119 22,171 23,088 23,131 23,107 23,550 23,544 23,548 24,673 24,683 25.797 25,793

Demand Side Management (DSM) 14 Cumulative DSM Capacity 561 584 604 626 649 649 649 649 649 649 649 649 649 649 649

15 Cumulative Capacity w/ DSM 22.070 22.151 22,004 22,745 22,820 23,737 23,780 23.756 24,199 24,193 24,197 25,322 25.332 26.446 26,442

Reserves w!DSM 16 Generating Reserves 4.392 4.098 3.603 4,021 3,807 4,405 4,187 3.954 4,145 3.880 3,610 4,469 4,191 5,021 4.729 17 % Reserve Margin 24.8°/a 22.7°A 19.6% 21.5°/a 20.0% 22.8% 21.4% 20.0% 20.7% 19.1% 17.5% 21.4% 19.8% 23.4% 21.8%

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uprates,

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peak

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to

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facility

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shown

tune

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repaired

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assumed

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(170

Station.

to MW).

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Reserve

Sum Cumulative

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Also

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New

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and

difference

of

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lines

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target

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margin

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and

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201

South

of

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in

wind

be

programs

8

available

selected

is Load,

included

capacit

Carolina

Ccle

14.5%

resources

capacit

Peak

to

including

units

capacity

Capacity,

in

iii

32

meet

as

available

2017

to

{)emand)/Sstem

a

in

in

placehulder

meet

load

2022

2019

for

(based

load

1’C

and

the

capacit)

control

and

winter

on

minimum

REPS

to

the

for

reflect

Reserves

Peak

and

compliance

peak

need

the

DSDR

planning

Demand

ofthat

determined

a

summer

possible

year.

Table

reser

peak

state

in

e

of

2012

margin

or

cont.

that

kderal

[RP) year The following charts illustrate both the current and Forecastedcapacity by fuel type for the DEC system, as projected by the Base Case expansion plan. As demonstrated in Chart 8-E, the capacity mix for the DEC system changes with the passage of time. In 2028, the Base Case projects that DEC will have a smaller reliance on coal and a higher reliance on gas—firedresources, nuclear, renewable resources and EE as compared to the current state. Gas price projections continue to make natural gas an attractive resource for future capacity needs.

Chart 8-E I)uke Energy Carolinas Capacity by Fuel Type — Base Case’

2014 Duke Energy Carolinas Capacity 2028 Duke Energy Carolinas Capacity Base Case Base Case

DSM Renewables ER 4% 0.8% j 5% Purchases “\ 1%

A detailed discussion of the assumptions, inputs and analytics used in the development of the Base Case is contained within Appendix A.

Environmental Focus Scenario l)EC also developed an Environmental [octis Scenario that includes aspirational EE targets, as well as contributions from renewable resources at levels approximately twice the level considered in the Base Case resource plan. This scenario illustrates the amount of traditional supply-side resources that would be eliminated or deferred if future market conditions and/or state and federal regulations resulted in higher levels of efficiency and renewable resoui’ces.

The supply-side resources were analyzed in light of the higher EE contributions and accounting for additional renewable resources. The Environmental Focus Scenario also assumed higher carbon prices

In 2021. the REPS compliance plan of 12.5°/bis comprised ofapproximatel 25% Energy Efflcienc3. 25% purchases of out—of—stateRECs. 5-10% from RE.Qsnot associated ith electrical energ (including animal waste resources), and the balance from purchases of rene able electricity.

33

mix.

resources.

i’he

as

of

locus

The

The

resource

Table

with

annual

and

Note.

doubling

projected

2028 2026

2027 2025

2023

2024

202!

2022 2021)

2019

2018

‘s’earT

•

•

•

•

following

Environmental

increase

slightly

Fables

the

Scenario,

8-F

Cl’

1)elay contribution

Increase

Incremental

Duke

incremental

plan:

Base

represent

resource

Natural

the

by

lower

Energy

in

in

charts

Case

the

renewable

DEC

thus

FE

in

the

only

Environniental

FE

fuel

Base

(‘arolinas

Focus

gas

expansion

additions

undesiiznated

increase

and

need

to

F

in

illustrate

increasing

Environmental

of

2022 peak) - - -

- -

prices

CC

Case

renewable

724

for

resources Scenario

Resource

and

moves

in

by

the

resources

reflected

both

MW

due

plan.

renewable

the

2028

nuclear

new

Focus

to

the

by

results

resources

beyond

impact

as

.1

Plan

from

declining

CC

Focus

I

2028

current

compared

in

208

Scenario

“w

capacity

the resource - - - -

-

in

energy

that

through

2028

Scenario

the

Environmental

and

reduce

demand

those

ftllowing

to

2028

34

timell’ame

expansion

resources

is

Ibrecasted

from

the

still

no

the

haseload

for

Base changes

20

economically

Company’s

2027

2028

changes

2026

2025 2023

2024

2021

2020

2022

2019

2018

Year

fissil

I

of

9

plan.

Case

capacity

Focus

to

to

1,857 Duke

the

resources

2022

fuels.

Base

and

Chart

Environmental

as

Scenario

Energy

MW

compared

(‘use

by

reliance

including

selected

Table

8-G

fuel

build

have

nameplate

Carolinas

Resrnwce

expansion

demonstrates

type

plan

8-F

on on - - - - -

-

Focus

to

occurred

aspirational

in

coal,

fbr

the

below

the

the

Resource

Scenario

the

(734

Base

system

in

Environmental

plan

hydro

pror

represents

1)EC’

the

MW

Case

years

Plan

EE

contrasted

capacity

and

impacts

system.

goals. MW - - - - -

-

CT the Chart 8-C Duke Energy Carolinas Capacity by Fuel Type — Environmental Focus Scenario

2014 Duke Energy Carolinas Capacity 2028 Duke Energy Carolinas Capacity Environmental Focus Scenario Environmental Focus Scenario RenewabIe FE EE DSM 08% 05% Renewjbies Purchses 4% \ 6% 1% OSM 4%- 2jrchases

Joint Planning Scenario

A Joint Planning Scenario that begins to explore the potential for DEC and l)EP to share firm capacity between the companies was also developed. The Ibcus of this scenario is to illustrate the potential for the utilities to collectively defer generation investment by utilizing each other’s capacity when available and by jointly owning new capacity. This plan does not address the specific implementation methods or issues required to implement shared capacity. Rather, this scenario illustrates the benefits of joint planning between DEC and DEP with the understanding that the actual execution of capacity sharing would require separate regulatory proceedings and approvals.

Table 8-LI below represents the annual non-renewable incremental additions reflected in the Joint Planning Scenario system expansion plan for the combined DEC and DEP Base Cases as compared to the Joint Planning Scenario. The plan contains the undesignated additions for I)EC and DEP over the planning horizon.

35 Table 8-H DEC and DEP Joint Planning Scenario

Duk I-in’pr (mimi and Duke Fmrj Pnigre’ l)uke 1ner (‘andinas and Duke Energy I’nignss lla,i- (use (‘onibint-dkesourre Plans Joint Planning Scenaiiu Rnsourre Plan Vear Resaune MW \tar Resnwte MW

2014 - 2014 - -

2015 — - 21)15 - -

20(6 2(1)6 - -

20)7 20(7 - - 2018 2(1)8 20(9 2019 202)) 202)) 0, C 202! 202! 2622 2022

2023 I 21)23 21)2-I 2024 2025 2026

2027 - - ‘!t 2028 -

The following charts illustrate both the current and forecasted energy and capacity by fuel type for the l)EC system, as projected by the Joint Planning Scenario. In this Joint Planning Scenario, the Companies continue to rely upon nuclear, C1’ and coal resources, hut the reliance on natural gas CC resources increases due to the favorable natural gas prices. The Companies’ renewable energy aiid EE impacts continue to grow over time, as also reflected in the Base Cases.

Chart 8-1 DEC and DEP Capacity by Fuel Type — Joint Planning Scenario

2014 Duke Energy Carolinas and Duke Energy Progress 2028 Duke Energy Carolinas and Duke Energy Progress Capacity - Joint Planning Scenario Capacity- Renewables EE Joint Planning Scenario DSM 1.0% 05% Rc-newab)es 00 DIM 5%\ 3%

Purhoses

36 Chart 8-J DEC and DEP Energy by Fuel Type — Joint Planning Scenario

2014 Duke Energy Carolinas and Duke Energy Progress 2028 Duke Energy Carolnas and Duke Energy Progress Energy - Joint Planning Scenario Energy - 1ont Planning Scenario

P,se EE Renewables Rnnewab’es 1% yurchases rydro

2%

37 9. SHORT-TFRM ACTION IThAN

The Company’s Short-Term Action Plan, which identifies accomplishments in the past year and actions to he taken over the next live years, is summarizedbelow:

• Take actions to ensure capacity needs beginning in 2017 are 2met. As discussed later in this chapter, DEC issued a Request for Proposals (RFP) to address the 2017 capacity need. After evaluating multiple bids including a self-build option, the Company has determined the most economic alternative to meet the 201 7 need is to construct a new natural gas combined cycle facility at the Lee Steam Station site in Anderson County S.C.

• Retire older coal generation. Buck Steam Station tJnits 3 and 4 were retired in May

2011. Chffside Units I through 4 and Dan River Units I and 2 were retired in October 2011 and April 2012, respectively, in advance of the initial testing of new generation at those locations. The remaining tin-scrubbed coal units at Buck and Riverbend were retired in April 2013, nearly two years earlier than previously planned. The retirement of Lee Steam Station is currently planned for April 2015 to correspond with the compliance requirements of the Mercury and Air Toxics Standard. Duke Energy Carolinas also retired 350 MWs of its older CTs in October 2012.

• Continue to execute the Company’s FE and I)SM plan, which includes a diverse portfolio of EE and l)SM programs, and continue on-going collaborative work to develop and implement additional cost-effective EE and DSM products and services.

• Continue to seek enhancements to the Company’s DSM/EE portfolio by: (1) adding new or expanding existing programs to include additional measures, (2) program modifications to account for changing market conditions and new measurement and veritication (M&V) results and (3) other FE research and development pilots.

• Completed construction of the new Dan River Combined Cycle unit. The unit was operational December 2012. The 620 MW natural gas-tired CC generating station achieves high operational flexibility and high thermal efficiency while utilizing state-of- the-art environmental control technology to minimize plant emissions.

• Completed construction of the 825 MW Cliffside Unit 6, at the existing Cliffside Steam Station. As of December 2012, Cliffside Unit 6 began commercial operation.

• Move fbrward with the conversion of Lee Steam Station Unit 3 from coal to natural gas fuel.

2 Whilethereisa slightcapacit)needin2016. the Compan will continue to monitor that small need and take action asnecessary.

38

timeframe.

> Continue

dew

coal

of

Lee

>

>

and

The

and

The

The

Environmental has 201

Lee

analysis

(published

and

for

update

accuracy

for

In

concluding

environmental

Lnvironmental

(NRC)

The

License well

acquisition

respectively.

Carolina

share

Steam

DEC

lopment

unit

April

5.

planning.

favorable NRC

moved

Nuclear

Company

risk

Company

Company

Company

as

in

Eastern

to

of

continues

the

Station

the

multiple

fhr

will

reduction (COL)

Preliminary

pursue

the

and

2012,

in

issuance Electric

the as

Lee

fourth

of

W.S.

in

that

historical

two

delay

regulatory

financing

NUREG-2

will

will

South

Conmiercial this

United

Compatibility

While

submitted Unit

Nuclear

report

continues

and

Impact

the

the

regulatory

to

1,100

the

quarter

Lee

continue

and

in

continue capacity

Lee

of

explore

3

option

an

NRC

Carolina,

engineering

new

NCUC’s

is

shown

the

was

load

options

IH

Gas

units

environmental

efforts

COl.

States

site-specific

Statement

reflected

115

of

an

to

(Lee)

staff

resource Lee

tor

approvals.

Operation

to

filed

forecasting V.C.

is

201

to

the

application

being

in

issuance

and

evaluate to

assess

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still

are

at

pursue

new

(CEUS)

COL.

January

4

evaluation

subsequently

potential

Nuclear

well

he

the

September

and

Summer

in

ongoing.

Public

has

39

subject

available

lbr

decisions

nuclear

cost-effective

the

federal

opportunities

seismic

as

converted

available

[)ate

until

report

Completion

the

been

the

within

2012).

2013

pursue

for

Convenience

Seismic

on

to

for

nuclear

(COD)

second

of

and

optimal

a

Lee

generating

for

analysis

24, successful

to

I)ec.

completed

L)uke

Combined

by

requested a

the

DEC’s

other

This

federal,

to

state

the

the

joint

Nuclear

2009.

considering

to

natural

2011

for from

quarter

Source

station.

of

12,

Nuclear summer

Energy

negatively

time

relevant

benefit

level.

to

ownership

Lee

and the

future

2007.

capacity

state

completion

incorporate

IRP

a

Construction

I)uke

The

and

gas

plant

to

Nuclear

new

2016.

Necessity

planning

Carolinas

Characterization

from

The

peaks

Regulatory

and

regulatory

was

the

before

tile

NRC

load

more

A

impacts

Energy

site-specific

in

in

local plan

economies

Accordingly, share

prospects

supplement

a

the

of

Unit

the

I)ecernher

of

demand

reasonable

the

the

issued

perspective,

detailed

(CECPCN)

2018

IRP

shows

and

Certificate

tax discussions

approvals.

201

the Carolinas

of

Commission summer

new

1

to

as

incentives

Operating

the

and

7

schedule

fbr

its

of

2024.

seismic

a

Central

to

and

a

model

project

to

retired

2011,

South

scale

2020,

Drafi

1)EC

basis

joint

5.9%

2028

peak

for

the

the

of

its

to as A which Table

represent summarization •

•

• • • 9-A. the Continue

regulatory Continue Continue agreements (CSAPR)

as operational Continue Continue

resources.

appropriate. unhundled cumulative change MATS. Capacity ownership to to and to of is

to to actions. RE(’s Additionally, impacts

within monitor the projected

the evaluate

examine PPAs totals. investigate pursue retirements the

and/or Coal capacity from new

the have associated energy—related existing market sales Combustion wind, to

1)uke ozone the

occur.

been REC

resource the and agreements benefits solar Energy National options

additions future

with signed

purchase

and

The PV, changes statutory Residuals existing balancing

potential of values

environmental

solar with Ambient

fbi’ fbi’ 40 joint are agreements renewable new thermal

for developers presented shown and and capacity authority opportunities the t’itle, nuclear Air potential regulatory Base for and Quality the have control generation as renewable

generation of hydroelectric planning Case area. incremental

Cross—State solar environmental been Standard activities.

for

requirements

in PV, executed the and and resources, wholesale resources. 2013 landfill facilities. values (NAAQS). procure Air pursue regulations fbr

IRP

Pollution

and gas

I)SM in

ower purchases

capacity, appl’opriate is

the

shown and resulting and year

sales

wind

Rule such

EE of’

as in in Table 9-A DEC Short-Term Action Plan

Duke Energy Carolinas Short-Term Action Plan

Renewable Resources (CiuimlativeNanplate MW)

(21 Year Retitnnts Additions Solar Bitiniass/Hvdro FE DSM °

2014 12 MW Nuc 0 294 62 I I 1 91 1 170 MW Lee NG Conx 2015 370 MW Lee 1-3 Coal 20 MW Nuc 0 519 69 184 1010 2016 0 569 77 275 1068 45 MW Nuc 2017 68OMWCC’ 0 609 84 382 1118 2018 66MWVCSunmer 0 730 118 490 1169 Notes (I) Includes 77MW ofnuclear uprates

(2) Capacity is shossii in nameplate ratings For planning purposes. sond presents a lSo contribution to peak and solar has a 40 contribution to peak (3) Bionss includes ssone and poultrs contracts (4) Includes impacts ofurid irxdemizution

[)EC RFP Activity

Supply-Side

As determined in the Base Case, DEC”s first significant capacity need is in 2017. [)EC recogiiized the need for near-term capacity in its 2012 IRP which indicated a need ibr approximately 700 MW of capacity in the 2016 tirneframe. ‘l’hroughout the IRP analysis this need was met by a generic CC. Concurrent with the IRP analysis, DEC issued a RFP fbr capacity and energy on October 26, 2012. The RFP was for up to 700 MW of dispatchable, non-peaking capacity and energy available by either June 1,2016 or June 1,2017.

On November 27, 2012, DEC received multiple proposals from twelve companies including a DEC selthuild bid for the construction of a natural gas combined cycle fcility at the existing Lee Steam Station site in Anderson County, S.C. ‘[‘liebids were reviewed for compliance with RFP guidelines and were ranked economically to determine the least cost options. ‘l’he initial economic analysis identified the short—listedbidders to continue proposal discussions. In late February 2013, DEC notified the short—listedbidders to provide refreshed proposals to meet capacity needs beginning June 2017.

Refreshed proposals received on May 29, 2013 were ranked economically and modeled utilizing detailed production cost modeling techniques. The results of detailed analysis including PROSYM

41

Renewable

No

the

production

renewable

Lee

CC

cost

Enerp

selt-huild

energy

modeling,

RFPs

proposal

along

have

to

been

he with

the

issued

all

least—cost

other

since

42

fixed

option

the

and

filing

of

variable

the

ol’

l)LC

refreshed

revenue

s

2012

proposals.

IRP.

requirements. indicated AflEN DIX A: QUANTITATIVE ANALYSIS

This appendix provides an overview of the Company’s quantitative analysis of resource options available to meet customers’ future energy needs in the Base Case and for an Environmental Focus Scenario that reflects increased C02 cost, FE and renewables. The future resource needs were optimized based on DEC and DEP independently. However the benefits of jointly planning on a system basis for the Base Case and Environmental Focus Scenario were also presented.

A. Overview of Analytical Process

The analytical process consists of tour steps:

1. Assess resource needs 2, Identit’ and screen resource options for further consideration 3. 1)evelop portfolio configurations 4. Perform portfolio analysis

I. Assess Resource Needs

The required load and generation resource balance needed to meet future customer demands was assessed as outlined below:

• Customer load peak and energy forecast — identified future customer aggregate demands to determine system peak demands and developed the corresponding energy load shape

• Existing supply-side resources — summarized each existing generation resource’s operating characteristics including unit capability, potential operational constraints and life expectancy

• Operating parameters — determined operational requirements including target planning reserve margins and other regulatory considerations

Customer load growth, the expiration of purchased power contracts and additional asset retirements result in significant resource needs to meet energy and peak demands. The following assumptions impacted the 2013 resource plan:

• In the Base Case, the summer peak demand and energy growth after the impact of energy efliciency averaged 1.5% through 202g. In the Fnvironmental Focus Scenario afier the

impact of energy efficiency, summer peak demand growth averaged 1.3% and energy

growth averaged 1.2% over the next 15 years

• Retirement of an additional 350 MW of old fleet combustion turbines and 710 MW of older coal units since the 2012 IRP filing

• Retirement of an additional 370 MW at Lee Steam Station by April 2015

43

quantitative

Based Supply-Side Resource

analysis

basis capabilities,

The

options

diverse

from

capacity

based Ihe

2.

•

•

•

•

•

•

•

•

•

• •

•

•

•

Company

is

IRP

its

on

on

Renewable Peaking/Intermediate

Renewable

Peaking/Intermediate

Baseload

Baseload

Baseload

Baseload

shown

Compliance

Technical

Reasonableness

Long-run

IdentiJj’

A

Continued

are

mix

phase.

EE/DSM

needs.

Options

the

existing process

14.5%

analysis

initially

with

of

results

in

compared

technologies

aiid An

—

— —2

The

Appendix

minimum

reliability

feasibility the

—

680

843 operational

evaluated

132

Collaborative

EE/1)SM

as

screened

with

25

overview

x

1

Screen

of Company

50

most

potential

1,117

MW MW

MW

MW

of

the

MW

all

cost

capacity

F. planning —

—

lèderal

Purchase

screening and

cost-effective Resource

— MW

—

program

based

FE,

and

2

2

reliability

of

403

805

parameters

Solar

supply-side

developed

On-shore

x

x

commercial

and

resources

Nuclear

I

I

fuel

E)SM

MW

MW

on

Combined

Advanced

and

options

reserve

PV

cost-effectiveness

of

experience,

the

analysis,

Options

sources

of state —

—

V.

and

Wind

4

2

units

thilowing

existing

EE

options

screened

resource

C.

x

x

margin

within

availability

requirements

supply—side

7FA.05

7FA.05

Combined

and

Summer

Cycle

44

for

(gas,

(API

the

generation

l)SM

the

Further

being

for

options

ft)llowing

their

on attributes:

(Inlet

000) coal.

CR

CTs

most

the

Nuclear

technical

screening.

options

in

Cycle

selected

options

respective

planning

nuclear

Chiller

the

to

Consideration

recent

portlblio

meet

technologies

marketplace

(Inlet

(API000)

for

basis

to

and

for

and

market

horizon

future

Supply-side

consideration

meet

fttel

Chiller

Fired)

inclusion

and

renewable).

capacity

types

potential

customer

a

were

and

levelized

options

and

in

Fired)

included

within

needs:

the

study,

Supply-side

energy

operational

economic

portfolio

reflect

the

in

input

IRP

anci

the a Energy Efficiency and Demand-Side Management

FE and DSM programs continue to be an important part of Duke Energy Carolinas’ system mix. The Company considered both DSM and FE programs in the 1RP analysis. As described in Appendix D, EE and I)SM measures are compared to generation alternatives to identiI’ cost- effective EE and DSM programs.

In the [3ase Case, the Company modeled the program costs associated with FE and DSM based on a combination of both internal company expectations and projections based on infbrma(ion from the 2013 update of the Company’s 2011 market potential study. In the DEC and DEP merger settlement agreement, the Company agreed to aspire to a more aggressive implementation of FE throughout the planning horizon, and the impacts of this goal were incorporated in the Environmental Focus Scenario. The program costs used for this analysis leveraged the Company’s internal projections tbr the first five years. in the longer term, updated market potential study data incorporating the impacts of customer participation rates over the range ol potential programs.

3. Develop Portfolio configurations l’he Company conducted a screening analysis using a simulation model to identify the most attractive capacity options under the expected load profile for both the Base Case and Environmental Focus Scenario. The set of basic inputs included:

• 2CO price starting in 2020 increasing throughout the planning horizon

Base Case - 17 s/ton in 2020 increasing to 33 $/ton by 2028 Environmental Focus Scenario - 20 S/ton in 2020 increasing to 45 S/ton by 2028;

• Coal, natural gas and fuel oil

Short-term: Based on the market observations Long—term: Based on the Company’s fundamental fuel price projections For the Environmental Focus Scenario, the Company’s fundamental fuel price projection incorporated the impact of ditierent 2C0 EE and renewable 1-equirements consistent with that scenario ,

• Availability and operating and maintenance cost for both new and existing generation

• Compliance with current and potential environmental regulations,

• Financial updates including cost of capital, escalation and discount rates

• System operational needs for load ramping, and spinning reserves

45 The projected load and generation resource need incorporating the impacts of EE and [)SM.

- I’he Base Case reflects FE savings projections based on the updated market potential study at the end ol the planning horizon

l’he Environmental Focus Scenario assumes lull compliance with the Duke Energy-Progress Energy merger settlement agreement with the cumulative FE achievements since 2009 counted toward the cumulative settlement agreement impacts

Compliance with NC REPS requirements and a placeholder renewable requirement for South Carolina that could represent a federal or state program starting in 201 8

.r The Environmental [ocus Scenario reflects a doubling of the amount of renewables included in the Base Case by 2028

4. Perform Portfolio ,4,,a!vsis

For the Base Case and Environmental Focus Scenario, the optimal portfolios were developed for I)EC without the benefit of sharing capacity with DEP. To demonstrate the value of sharing capacity with [)EP, a Joint Planning Scenario was developed that examined how the combined plans of DEC and DEP would change if a 14.5% minimum planning reserve niargin was applied at the combined system level rather than the individual company level.

An overview of the specific details of the optimal portiblios for both the Base Case and Environmental Focus Scenario without the benefit of sharing capacity with L)EP is shown in Table A-I below.

46

renewables,

requirements

amount

need

The

dependent

two

expansion

1

Even

cycle

Case

V.C’.

in

‘l’he

Focus

5-year

Table

2024

Environmental

additional

of

first

Summer

and

though

generation

Note:

r

Scenario.

the

of

planning

Total

A-I

and

resource

Total

Total

Environmental

renewable

model.

on

Advanced

This

the

2028

2027 2025

2026 2024

2023

2022

2021

2020

2019

2018

2017

2016 2014

2015

associated

shared

Nuclear

2026.

arriving

Nuclear

CCs

CTs

table

DEC

scenarios

Environmental

was

horizon.

In

need

Focus

addition

includes

V.C.

resources

selected

These

Optimal

CC

at

Station

with

was

commercially

Focus

66

66

in

However, Summer

Scenario

of

onl’

2019

nuclear

MW

MW(V.C.

higher 843

to

determined

as

this

in

by

1,II7MW(N) l,II7MW(N) 403

680MW(CC)

Portfolios

significant

Scenario,

new.

Focus

the

2,366

2018

1,523

MW(AdvCC)

(V.C.

2028.

403

to

IRP,

Nuclear

MW

EE

incorporates

Base

most

because undesignated

2022.

resources

MW

and

Scenario

MW

acceptable

MW

and

Summer

SummerN)

The

(CT)

to

the

the

economical

levels

2020

In

he

increased

was

Optimal

of

impact

optimized

procurement

addition,

in

were

47

the

resources.

and

present

a

N)

of

selected

2017

terms

more

higher

FE,

of

the

1

selected

cost resource Portfolios

these

66

66

the

in

portfolios

1)SM

addition

with

value

aggressive

Environmental

and

CO 2

associated

MW

both

MW(V.C.

843

2022

of

additions

1,II7MW(N)

1.II7MW(N)

680MW(CC)

Santec

economically

and

to

incorporated

2,366

aiiy

MW

1,523

price

of

the

(VC.

CT

of

meet

included

revenue

renewable

Base

the

portion

(Adv

FE

need

projection.

MW

Cooper.

MW

with

Summer

Summer

allowed

this

W.

portfolio

Case

Focus

was

CC’)

doubling

need.

5.9%

S.

requirements

in

utilizing

of

resources,

Lee

delayed

for

the

and

N)

N)

increased

V.C.

ownership

and

In

a

Nuclear

Base

Environmental

the

deferral

both

the

doubles

Summer

beyond

amount

combined

Case

(PVRR)

the

capacity

revenue

Station

of

in

Base

and

the

the

the

the

of is through 2028 is $2 billion more than the Base Case even with deferral of the advanced CC’and CT resources.

An evaluation was performed comparing the DEC and [)EP optimally selected Base Case porttoiios to a combined .Joint Planning Scenario where existing and future capacity resources conic! he shared between DEC and DEP to meet a minimum 14.5% planning reserve margin. In this Joint Planning Scenario. sharing the W.S. Lee nuclear station on a load ratio basis with 1)EP vas the best economic selection. ‘fable A-2 shows the total incremental natural gas and nuclear capacity needed to meet the projected minimum planning reserve margin between 2014 and 2028 for 1)FC and DEP if separately planned. The total of these two combined resource requirements is then compared to the amount of resources needed if l)EC and DEP were to jointly plan.

Table A-2 Comparison of Base Case Portfolio to Joint Planning Scenario

DEC l(ote ( one ll99) 2(114 21)15 21)16 2(117 2019 2019 2(121) 21(21 2022 21(23 21(24 2(125 2026 21)27 2028

(unnUni!s 6813 843 403 ‘nuclear J 66 66 1117 3117

D6P Bane Coon,(MW) 2014 2015 2016 20)7 2(110 2(119 21(20 2021 21(22 2(123 2024 2025 j 2026 2(127 2(129

Gun Loito 843 843 843 401

Nuclear 46 46

DEC & DEl’ (‘onthjoe,l Bone Cane (51W) 680 112 1686 132 843 1248 1117 1117 403

Combined Bone Cone Rcnerve Mmin 17.7% 17.7% 160% 166% 15.7% 18,6% 172% 16.6% 18.0% 16.8% 18.6% 17.8% lg.4% 19.1% 17.4%

joint Ploonitin, (‘one (MW} 792 843 112 1246 843 403 1117 1137 loin! P!oonin (‘one Renerve ‘nIoniin 17,7% 37.7% 160% 14.6% 15.7% 16.1% 14.8% 35.3% 15.6% 15.6% 174% 16.6% 18.3% 36.855 15.2%

A comparison of the DEC and [)EP Combined Base Case resource requirements to the Joint Planning Scenario requirements illustrates the ability to defer CC and C”!’resources over the 2014 through 2028 planning horizon. Consequently, the Joint Planning Scenario also results in a lower overall reserve margin. This is confirmed by a review of the reserve margins for the Combined

Base Case as compared to the Joint Planning Scenario, which averaged 17.6% and 16.0%, respectively, from the first resource need in 201 7 through 2028. ‘l’he lower reserve margin in the Joint Planning Scenario indicates that DEC and DEP are more efficiently and economically meeting capacity needs. This is reflected in a total PVRR savings of $0.4 billion for the Joint Planning Scenario as compared to the l3ase Case through 2028.

48

Nuclear

completion accident.

specific

recommendations

impacts Source

‘I’here

20

ownership

outstanding

Scenario

DEP working discussing

been

DEC generation.

shared Nuclear

br ‘[he

Energy

10%

‘l’he

as

B.

12,

well

resource

2.

3.

quantitative

Base

ownership

signed.

and

were

the

are

Characterization

among

were

New

V.C. deferral

‘[‘he

The

as

Environmental

Corporation

the

Quantitative

seismic

site-specific

the

[he

by

described

towards

NRC

several

In [)EP

planning

the

interest

Case

also

need

of’

commercial

l)EC.

results

schedule The

April

Base

ability

additions

selected.

Summer

nuclear

Any

commercial

the

the

on

issued

analysis

of

interest

illustrated

idea

analysis

and

challenges fbr

a

Case

of’ a

2012,

participation

in new

parties.

above.

new of

br

However

final

load

to

is

analysis

new

the

V.C.

of

Analysis

Environmental

tbr

a

this

generation

in to

the

in

Focus

and

jointly

generation

request

model

sharing

seismic

the

in

to

items

ratio

Near—Term

decision

discussions

2018

resulted

he

NRC

generation

analysis

tenns longer

Summer

the

incorporate

with

Environmental

‘Ibis

NRC

that

better

implementing

the

Scenario.

basis.

and

(published

Summary

new

plan

and

for

in

issuance

new

and

have

analysis

the

results term.

Company

staff

is in

in

the

resources

information

show

continued

matched

2020

Units

nuclear

several

currently

with

baseload

selected

the

‘[‘ask

ability

‘T’he

with

in

Focus

impacted

V.C.

subsequently

the

201

in

In

next

that

of

and

2

is

benefits

as

[)EP

Santee

new

Force

the

I

positive

Summer

the

and

continues

units

7

key

the

with

not

to ocus

NUREG-2

Scenario

over

this

demonstration

generation

several

as

the to

have

letter

1

new

Central the jointly

49

3,

5-year provides

Lee

takeaways

expected

meet

review

an

at

load need

Cooper Scenario

the

of

addition

the

schedule

not

requested

benefits

CEUS

V.C.

project

to

co-ownership

Nuclear

economic

2014

months.

ownership to

analyses

growth

the

is

operating

plan

planning

and

115

reconciled

of

resources

consider

best

Summer concerning

customer hefbre

minimum

seismic

show that

of

through

Eastern

in

is

insights

for of’

as

fbr

COL.

met

premised

January

DEC

and

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If

customer

represented

the impact

resource

support

the

horizon,

power

optimal

is

l)uke

January

the

Lee with

differences

lbr

of

between

Units

model

expected

Lee

to

United

2028

Company’s

from

savings

Completion

reserve

the

the

update

benefits

2012).

new

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near—term

CC

Nuclear

on

reactor

Energy

100%

2

benefits.

potential

Lee

planning

port(b

a

for

the

is

201

successful

States

and

construction 5.9%

generation

multiple

in

underway.

to

by

the

margin

Nuclear

the

4.

[‘ukushinia

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and

of’

the

licensees

be was ownership

3.

in

lios

lhcility.

customers.

allowing

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decision—

ownership

of

(CEUS)

regional

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Rase

2024

acquisition

shared no

horizon.

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that

to

on

parties

the

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requirement.

resolution

contract

facility

procure

a

parties

parties

negatively

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risk

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recognize

new

and

regarding

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new

between

1)ai—ichi

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making

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of

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allows

in

l)uke

to

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and

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are are

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interest

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impacts

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dependent

proceedings

considering

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before the

petition NRC’s

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reactors

reactors

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approximately

remanded

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expiration

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production

ol’the

specific

PVRR

reasonable

on

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of

output

necessary”

analysis

to

concerning

of

and

current

operating

seismic

generation

this

license of

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to

regional

major

part

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suspend

supporting

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results

any

all

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facilities

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assist

actions,

waste

renew

the

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determination

Carolinas

of

of

the

of

Summer

cost

options

assurance

N

was

schedules,

6

potential

benefits

a

for

analysis

approximately

T)istrict

On

DEC’s and

RU

and

presented

plant’s

million

the

Waste

license

confidence

nuclear

continue

and

final

the

seeking

if

Oconee

insufficient

were

but

August

Company

new

issued

remanding

that

existing

operating

for

carbon-free

and

has

decisions

of

generation

has

must

license.

Confidence

utility

expires.

will

of

tons

retirement

selected

spent

nuclear

this

resolving

planning

having

moved

extends

sharing

a

to

in

an

Nuclear

7,

not

Columbia

second

proceedings

he

move

delay

the

is

nuclear

2012,

of

updated

as

to

spent

20,000

fuel

not

licenses

yet

resolved

it

In

in

CO 2 additional

economically, IRP

the

it

were

Waste

support

generation.

to

Lee

only

portfolio

considers

forward.

all can

expected response

with

the

Lee

determined

license

Station

of’

the

Rule

commercial

fuel

the

analysis

for

generation

Nuclear

pending

GWh.

extended

Waste

Circuit

to safely

Oconee

waste

NRC

conlidence

COL

of

L)EP, to

NRC

in

can

its

DEC

final

until

existing

extension

nuclear

support

new

expires.

representing

findings

The

to

seeking

to

50

Confidence

he

confidence

be

issued

It were

issuance

As

Stations,

fur

reactor

license

DEC

impact

issued

and

they

a

the

the

Nuclear

is

nuclear

to

stored

safely

operation

NRC

is

course

important

such,

further

2052

generation

is

reactors.

issuance

based

remand

[)EP

Court’s

retired

would

an

At

a

procures

that

for

central

issuance

issuance,

second

licensing

expects

a

stored

on-site

until

order

the

and

this

over

to

it

this

of

by

decision

Station

the

issues,

Rule

on

proceedings.

date

also

is

capture

resulting

in

action,

license

to

of

decision,

2028 time, remand

to

second

a

plant.

permanent

On

on

2,500

important

license

is

fhr

this

the

its at

note

the

the

in

1

of

ft)r

serve

and

proceedings

5-year

the

which

the

June

nuclear

as

2010

at

the

(from

the

agency’s

future.

issue

Lee

Lee vacating

load

the

renewal

(2)

that

Oconee

MW

lower

(3)

petition

reduction

least

quarter

compared

is

extension.

as

Lee

Company

8,

numerous

Nuclear

planning

Nuclear

long-term

aIlirm

it

could

all

appropriately

replacement

while

to

ratio

to

storage

The

a

2012,

plants

of

Nuclear

will

60

system

2013

be

licensing

start

In

ability

proceedings

capacity

Nuclear

the

pending

stating 2016.

years

Court

ing

resolved

share

include

V.C.

2033,

not

in

the

Unit

C’OL.

fur

to

will

baseline).

horizon,

to

has

CO 2

updated

that

CO 2

benefits parties

COL.

to

issue

60

U.S. after

new

examine

Summer

held

Accordingly,

that:

of’

reviews

be

carbon-free

not 1

Station

the

and

license

completion

the

addressed,

emissions

generic years

to

Ilowever,

footprint. in

the

available

Court

pending

a

nuclear licenses

made

2024.

that

current (1)

August

but

annual

filed ageiicy

of

Waste

power

‘[his

I

afler

O%

new

and

is

and

it

the

the

the

the

or

of

is

a

a a

business

practical

practice

resource The

new

illustrates

Company’s

nuclear

requires

planning

plan

to

that

reflect

generation

is

for

the

planning

DLX’

the

framework

improved

mOSt

Company

to

to

appropriate

the

continue

process

future

is

information

to

truly

achieve

must

to

resource

an

resource

study

evolving

he

material

and

dynamic

portfolio.

the

plan

changing

options

process

system

at

and

this

and

circumstances.

adaptable

that

reductions

point

make

can

in

never

time.

adjustments

to

in

changing

CO 2

he

However,

Consequently.

considered

emissions,

as

conditions.

necessary

good

it

complete.

must

business

a

strong

‘[his

and add _____

APPENDIX B: DUKE ENERGY CAROLINAS OWNED GENERATION

Duke Fnergy Carolinas generation portfolio includes a balanced mix of resources with different operating and fuel characteristics. This mix is designed to provide energy at the lowest reasonable cost to meet the Companys obligation to serve its customers. [)uke Energy Carolinas-owned generation, as well as purchased power, is evaluated on a real-time basis in order to select and dispatch the lowest-cost resources to meet system load requirements. In 2012, Duke Energy Carolinas’ nuclear and coal-flred generating units met the vast majority of customer needs by providing 62°/o and 3 1%, respectively, of l)uke Energy Carolinas’ energy from generation. Ilydroelectric generation, Combustion Turbine generation, Combined Cycle generation, solar generation, long term PPAs, and economical purchases from the wholesale market supplied the remainder.

The tables below list the Duke F.nergy Carolinas’ plants in service in North Carolina (NC) and South Carolina (SC) with plant statistics, and the system’s total generating capability.

Existing Generating Units and Ratings All Generating Unit Ratings are as of January 1, 2013

Coal Unit Winter Summer Location Fuel Type Resource Type (MW) (MW)

Allen 1 167 162 Belmont, NC. Coal Intermediate Allen 2 167 162 Belmont,N.C. Coal Intermediate Allen 3 270 261 Belmont, NC. Coal Intermediate Allen 4 282 276 Belmont, NC. Coal Intermediate Allen 5 275 266 Belmont, NC. Coal Intermediate

Belews Creek 1 1135 11lO Belews Creek, NC. Coal Base

Belews Creek 2 I 135 1I 10 Belews Creek, NC. Coal I3ase Cliffside 5 556 552 Cliflside, N.C. Coal Base Cliffside 6 825 825 Cliffside, N.C. Coal Base

Lee I 100 100 Pelzer, S.C. Coal Peaking Lee 2 102 100 Pelzer, S.C. Coal Peaking Lee 3 170 170 Pelzer. S.C. Coal Peaking

Marshall 1 380 380 Terrell, NC. Coal Intermediate Marshall 2 380 380 Terrell, NC. Coal Intermediate Marshall 3 658 658 Tenell, NC. Coal Base Marshall 4 660 660 Terrell, NC. Coal Base Total NC 6.890 6,802 Total SC 372 370 ‘lotal Coal 7,262 7,172

52 Combustion Turbines

Unit Winter Summer Location Fuel Fype Resource (MW) (MW) Lee 7C 41 41 Pelzer, S.C. Natural Gas/Oil-Fired Peaking Lee 8C 41 41 Pelzer, S.C. Natural Gas/Oil-Fired Peaking

Lincoln 1 93 79.2 Stanley, NC. Natural Gas/Oil-Fired Peaking Lincoln 2 93 79.2 Stanley, NC. Natural Gas/Oil-Fired Peaking Lincoln 3 93 79.2 Stanley. NC. Natural Gas/Oil-Fired Peaking Lincoln 4 93 79.2 Stanley, N.C. Natural Gas/Oil-Fired Peaking Lincoln 5 93 79.2 Stanley, N.C. Natural Gas/Oil-Fired Peaking Lincoln 6 93 79.2 Stanley, NC’. Natural (las/Oil-Fired Peaking Lincoln 7 93 79.2 Stanley, NC. Natural Gas/Oil-Fired Peaking Lincoln 8 93 79.2 Stanley, N.C. Natural Gas/Oil-Fired Peaking Lincoln 9 93 79.2 Stanley, NC. Natural Gas/Oil-Fired Peaking Lincoln 10 93 79.2 Stanley, N.C. Natural Gas/Oil-Fired Peaking

Lincoln 11 93 79.2 Stanley, N.C. Natural Gas/Oil-Fired Peaking Lincoln 12 93 79.2 Stanley, .C. Natural Gas/Oil-Fired Peaking Lincoln 13 93 79.2 Stanley, N.C. Natural Gas/Oil-Fired Peaking Lincoln 14 93 79.2 Stanley, N.C. Natural Gas/Oil-Fired Peaking

Lincoln 15 93 79.2 Stanley, NC. Natural Gas/Oil-Fired Peaking Lincoln 16 93 79.2 Stanley, N.C. Natural Gas/Oil-Fired Peaking

Mill Creek 1 92.4 74.42 Blacksburg, S.C. Natural Gas/Oil-Fired Peaking Mill Creek 2 92.4 74.42 Blacksburg, S.C. Natural Gas/Oil-Fired Peaking Mill Creek 3 92.4 74.42 Blacksburg, S.C. Natural Gas/Oil-Fired Peaking Mill Creek 4 92.4 74.42 Blacksburg, S.C. Natural Gas/C)il-Fired Peaking Mill Creek 5 92.4 74.42 Blacksburg, S.C. Natural Gas/Oil-Fired Peaking Mill Creek 6 92.4 74.42 Blacksburg, S.C. Natural Gas/Oil-Fired Peaking Mill Creek 7 92.4 74.42 Blacksburg, S.C. Natural Gas/Oil-Fired Peaking Mill Creek 8 92.4 74.42 Blacksburg, S.C. Natural Gas/Oil-Fired Peaking

Rockingham 1 179 165 Rockingham, NC. Natural Gas/Oil-Fired Peaking Rockingham 2 179 165 Rockingharn, NC. Natural Gas/Oil-Fired Peaking Rockingham 3 179 165 Rockingharn, NC. Natural (las/Oil-Fired Peaking Rockingham 4 179 165 Rockingham, NC. Natural (las/Oil-Fired Peaking Rockingharn 5 179 165 Rockingham, N.C’. Natural Gas/Oil-Fired Peaking Total NC 2,383 2,092 Total SC 821.2 677.4 Total CT 3,204 2,770

53

Total

Bad

Jocassee

Bad Bad

Jocassec

Bad

Jocassee

Jocassee

Total

Dan Dan

Dan

Buck

Buck Buck

Dan

Creek

Creek Creek

Creek

River

River River

Pump

River

Buck

CTCC

CTCC

Stor

CTCC

CTI2 CT]]

SilO

4

2

3

4

CT9

3

2 ST7 CT8

I

Unit

I

I

Winter

2,140

(MW)

340

340 340

Winter

340

(MW)

195

195

1,280

195

195

640

300

640

300

170

170

170

170

Summer

Summer

2,140

(MW)

Pumped

(MW)

1

340 340

340

340

Combined

195

195

195 195

620

290

620 290

,240

1

165

165

165

65

54

Storage

Salisbury,

Salisbury. Salisbury,

Cycle

Salem,

Salem,

Salem.

Salem,

Salem,

Salem,

Salem,

Salem,

Eden,

Eden.

Eden,

Location

Location

NC.

NC.

S.C.

NC.

SC’. S.C.

S.C.

S.C.

S.C. S.C.

S.C.

NC.

N.C. N.C.

Pumped

Pumped

Pumped

Pumped

Pumped

Pumped

Pumped

Pumped

Natural

Natural

Natural Natural

Natural

Natural

Fuel

Fuel

Type

Storage

Storage Storage

Storage

Storage

Storage

Storage

Storage

Type

Gas

Gas

Gas

(las

Gas

Gas

Peaking

Resource

Peaking

Peaking

Peaking

Peaking Peaking Peaking

Peaking

Resource

IYP

Base

Base

Base

Base

Base Base

Gaston

Gaston Gaston

Gaston

Fishing

Franklin Fishing Dearborn

Franklin

Fishing

Dearborn Dearborn Cowans

Fishing C’owans

Fishing

Cowans Cedar

Cowans Cedar

Cedar

Cedar

Bridgewater

Biyson Bridgewater

Bryson Bridgewater

99

99

99

99

Bear

99

99

Islands

Islands

Islands

Islands

Islands

Islands

Creek

Creek

Creek

Creek

Cliff

Shoals

Shoals

Shoals

Shoals

Creek Creek

Creek City

Creek

(‘reek

City

Ford

Ford

Ford

Ford

Unit

6

4

2

5 3

4

5 3 2

3 4

2

3

2

3

2

1

2 2

3

4

6

1 1

1 3

1 5 2

1

1

1

I

1

Winter

(MW)

81.3

81.3

81.3 0.48

81

9.45

0.6

9.5

9.5

6.4

1.5

1 1

1

14

1.6

1

14 14

1)

15

15 15 1

0

15

0

8 I

0

I

I

0

0

.6

.6

.6

1

5

1

.3

Summer

(MW)

81

81.3

81.3 0.48

8

9.45

0.6

9.5

9.5

6.4

1

1.6

I 1

I 14

0 14 14 15 1

1.6

15

15

0

0

15

8 15

0

I

1 I

0

0

.5

.6

.6

I

I

.3

.3

Hydro

Tuckasegee,

Tuckasegee,

Blackshurg.

Blackshurg,

Blackshurg,

Blacksburg,

Great Morganton,N.C.

Great

Great

Great

Great Great Morganton,

Great Morganton,

Great Great

Blackshurg,

Great Blackshurg,

Blacksburg,

Great

Blacksburg,

Blackshurg,

Blackshurg,

Franklin,

Franklin,

Whittier,

Whittier,

Stanley,

Stanley,

Stanley,

Stanley,

Location

Falls, Falls, Falls,

Falls, Falls,

Falls,

Falls,

Falls.

Falls,

Falls,

Falls,

NC’.

N.C. N.C.

N.C.

NC.

N.C.

N.C.

N.C.

S.C. N

S.C.

S.C.

S.C. S.C. NC.

S.C. S.C.

S.C.

S.C. S.C.

S.C. S.C.

S.C.

S.C.

S.C.

NC.

N.C. S.C.

S.C.

S.C.

S.C.

S.C.

S.C.

.U.

Fuel

Ilydro

[lydro Hydro

Ilydro Ilydro Hydro

I Hydro

Hydro Hydro

Hydro

Hydro

Hydro Hydro Hydro

Hydro

Hydro

Hydro Hydro

Hydro Hydro

1-lydro Hydro

Hydro Hydro

Hydro

[—lydro

Hydro Ilydro

Hydro

Hydro

Hydro Hydro

Hydro

lydro

Type

Peaking Peaking

Peaking Peaking

Peaking Peaking Peaking

Peaking Peaking

Peaking Peaking

Peaking Peaking Peaking

Peaking Peaking

Peaking

Peaking Peaking Resource

Peaking Peaking

Peaking

Peaking Peaking Peaking

Peaking Peaking

Peaking

Peaking

Peaking Peaking

Peaking

Peaking

Peaking Iyp

Rocky Rocky

Rocky

Rocky Nantahala

Rhodhiss Rhodhiss

Rhodhiss Queens

Oxford

Oxford

Mountain

Mountain

Mountain

Mission

Mountain Mission

Mission 1.ookout

Lookout

Lookout Great

Keowee

Great

Great

Keowee Great

Great

Great

Great

Great

Falls

FaIls

Falls

Falls

Falls

Creek

Creek Falls

Creek

Falls

Creek Falls

Creek

Shoals

Shoals

Shoals

Island

Island

Island Island

Unit

4

2

3

3

2

2

4

3

2

2

3

3

I

2 2

I 1

I

I

8 6 4

1

5

7

1 3

2

I 1

1

Winter

(MW)

1

I

9.5

0.6

9.3

20 9.3

9.3

20

50

1

76

76

0

.44

0 14

0 14

9 17

0

1.5

0

0

0

0

3 0

3

0

3

3

7

Summer

(MW)

Hydro

I I

9.5

0.6

9.3

9.3

20 9.3

20

50

76

76

0 .44

17

0 0 17 14

14

9

0

1.5

0

0

0

0

3

3

0

0

3

3

56

cont.

Mount

Mount Mount

Mount

Great

Great

Great

Great

Statesville,

Great

Great

Statesville, Great

Statesville, Great

Great

Great

Great

Great

Rhodhiss,

Rhodhiss,

Rhodhiss,

Conover,

Conover,

Murphy,

Murphy,

Murphy,

Topton,

Topton,

Seneca,

Seneca,

Location

Falls,

Falls, Falls,

Falls,

Holly,

holly,

Holly,

Holly.

Falls,

Falls, Falls,

Falls,

Falls,

Falls,

Falls, Falls,

NC’.

N.C.

S.C.

S.C.

N.C.

N.C.

N.C.

N.C.

N.C.

N.C.

NC’.

NC.

NC. N.C.

N.C.

S.C.

S.C.

SC’.

S.C.

S.C.

S.C.

SC’.

S.C.

S.C.

S.C.

S.C.

S.C.

N.C.

N.C.

NC.

N.C.

Fuel

Hydro

Hydro I

Hydro

Hydro

Hydro

Hydro Hydro

Hydro

Ilydro Hydro

Hydro

Hydro

Flydro Flydro

[-Jydro Hydro

Flydro

Hydro Hydro

Ilydro Hydro

1-lydro

ilydro Hydro

[Tydro Hydro

l-{ydro

Flydro Hydro

1-lydro

lydro

Type

Peaking Peaking

Peaking Peaking

[‘caking Peaking

Peaking

Peaking Peaking Peaking Peaking

Peaking

Peaking

Peaking Peaking Peaking

Peaking Peaking Peaking

Peaking

Resource

Peaking Peaking

Peaking Peaking

Peaking

Peaking

Peaking Peaking

Peaking

Peaking

Peaking yp Hydro cont.

Unit Winter Summer Location Fuel Type Resource (MW) (MW) jyp Rocky (‘reek 5 0 0 Great Falls, S.C. 1-lydro Peaking Rocky Creek 6 0 0 Great Falls, S.C. [lydro Peaking Rocky Creek 7 0 0 Great Falls, S.C. [Tydro Peaking Rocky Creek 8 0 0 Great Falls, S.C. Hydro Peaking

Tuxedo 1 3.2 3.2 Flat Rock, N.C. Ilydro Peaking Tuxedo 2 3.2 3.2 Flat Rock, NC, Hydro Peaking

Tennessee Creek 1 9.8 9.8 Tuckasegee, N.C. Hydro Peaking

Thorpe I 19.7 19.7 Tuckasegee, N.C. Hydro Peaking

Tuckasegee 1 2.5 2.5 Tuckasegee, N.C. Hydro Peaking

Wateree 1 17 17 Ridgeway, S.C. Hydro Peaking Wateree 2 17 17 Ridgeway, S.C. Hydro Peaking Wateree 3 17 17 Ridgeway, . C. Hydro Peaking Wateree 4 17 17 Ridgeway, S.C. Hydro Peaking Wateree 5 17 17 Ridgeway, S.C. Flydro Peaking

Wylie 1 18 18 FortMill,S.C. Hydro Peaking Wylie 2 18 18 Fort Mill, S.C. Hydro Peaking Wylie 3 18 18 Fort Mill, S.C. Hydro Peaking Wylie 4 18 18 Fort Mill, S.C. Kydro Peaking Total NC 623.97 623.97 Total SC 465.4 465.4 Total Kydro 1,089.37 1,089.37

Solai

Winter Summer Location Fuel Type Resource Type (MW) (MW) NC Solar 8.43 8.43 NC’. Solar Intermediate Total Solar 8.43 8.43

57 Nuclear

Unit Winter Summer Location Fuel Type Resource (MW) (MW) Iyp McGuire 1 1156 1129 Huntersville, NC’. Nuclear Base

McGuire 2 1156 I 129 Huntersville, N.( Nuclear Base

Catawba 1 1163 1129 York, s.C. Nuclear Base

Catawhu 2 1163 1129 York, S.C’. Nuclear Base

C)conee I 865 846 Seneca, S.C. Nuclear Base C)conee 2 865 846 Seneca, SC’. Nuclear Base Oconee 3 865 846 Seneca, S.C. Nuclear Base Total NC 2,312 2,258 Total SC 4,921 4,796 Total Nuclear 7,233 7,054

Total Generation Capability

Winter Capacity (MW) Summer Capacity (MW) TOTAL DEC SYSTEM - NC. 13,497 13,025 TOTAL DEC SYSTEM - S.C. 8,720 8,449 TOTAL I)EC SYSTEM 22,217 21,473

Note a: Unit infbrmation is pro ided by State.hut resourcesare dispatchedon a sstem—widebasis.

Note b: Suniiner and inter capabilitydoes not take into account reductions due to future environmental emission controls.

Note C: Catawba (.inits I and 2 capacit reflects 100% of the stations capabilits. and does not factor in the North Carolina Municipal Power Agenc ill’s (NCMPA#I) decision to sell or utilize its 832 MW retained ownership in Catawha.

Noted: ‘I’heCatasha units multipleownersand theireffective ownership percentages arc: (atawba Owner Percent Of Ownership Duke Energy Carolinas 19.246% NorthCamlina ElectricMembership 30754%

Corporation(NCEMC) NCMPA#l 37,5% PMPA 12.5%

58

Note

Units resource

for

Note

Oconee3

Oconee

Oconee

McGuire McGuire

Catawba

McGuire

McGuire

the

b:

a:

and

Joint

The

Unit

I.

plan

mit

Ratings

2

I

1

2

2

I’

Exchange I uprate Liprate

a

section. capacit

effective

Agreement

Apr

Jan2017

Oct

Jan2017

Oct

Jan

Jan

Jan

Date

represented

as

2017

2014 2013

2013

2013

2015

Planned

ofJanuary

for

Catawba

in

Uprates

Winter

this

I,

201

(40%)

table

and 1

6.0 11.6

6.0

6.0

13

13

8

1

3

.6

59

MW 1

McGuire.

capacity

is

the

total

reflected

The

Summer

operating

adjusted

32.5

32.5

20

29

29

15

15

15

in

Existing

MW

capacity

values

Generating

addition

are

utilized

and

in

is

the

not adjusted Retirements

Unit & Plant Name Location Capacit’,(MW) FuelType Expected Summer Retirement Date Buck 3 Sahshur,’, NC. 75 Coal RETIREE) 4a Buck Salishui-’,.NC. 38 Coal RETIREI) Cli1ide la (‘hiliode. NC. 38 Coal RFTIRE[)

Cliflide 2” (‘lifliode.NC. 38 Coal RETIRET) Clifide 3” (Ii0ide. N C 61 Coal RETIRED Cliide 4” (‘liPiode.NC. 61 Coal RETIREE)

Dan Riser I” Eden. NC. 67 Coal RETIRED

Dan Riser 2” Eden. NC. 67 Coal RETIRED Dan Riser 3’ Eden. NC. 142 Coal RETIRED Buzzard Roost 6C” (‘0pp. S.C. 22 Combustion Turbine RETIRED Buzzard Roost 57C Chappels. S.C. 22 Combustion Turbine RETIRED Buzzard Roost 8C” Chappels. S.C. 22 Combu.stionTurbine RETIRED Buzzard Roost 9C’ Chappels. S.C. 22 Combustion Turbine RETIRED Buzzard Roost bC’ Chappels. S.C. 18 Combustion Turbine RETIRED

Buzzard Roost I IC” Chappels. S.C. 18 (‘ombustion Turbine RETIRED Buzzard Roost l2C” Chappels. S.C. 18 Combustion Turbine RET[RED Chappels, 18 Buzzard Roost 1IC S.C. Combustion Turbine RETIREE) (Shappels. S. 18 Buzzard Roost I4C” C. Combustion Turbine RETIRED SCb Chappels. Buzzard Roost I S.C. IS CombLLstion Turbine RET[RED Riverbend SC” Mt l1oH. N C. 0 Combustion [iwbine RETIRED Riverbend 9Ch Mt. [loll’,. NC. 22 Combustion Turbine RETIRED

Riverbend i0C Mt. Holly.N C 22 Combustion I’urbine RETIREE) Mt. Holk. NC. 20 Combustion Turbine RETIRED Ri’erbend I 5IC Buck 57C Spencer. NC. 25 Combustion Turbine RETIRED Buck 8C” Spencer. NC. 25 Combustion Turbine RETIRED Buck 9C” Spencer, NC. 12 Combustion Turbine RETERE[) Dan River 4Ct Edei. NC. 0 Combustion Turbine RETIRED Dan Riser 55C Eden. NC. 24 Combustion Turbine RETIRE[) Dan Riser 6C” Eden. NC. 24 Combustion Turbine RETIRED Riserbend 4’ Mi. holly, NC. 94 Coal RETIRED Riserbend ‘ Mt. [loll’,, NC’. 94 Coal RETiRED Riverhend 6” Mi. Holly. NC. 133 Coal RETIRED

Riserbencl7” Mt. Holls, N C. 133 Coal RETIRED

F3ucks” Spencer N.C. 128 Coal RETIREE)

Buck 6” Spencer. NC. 128 Coal RETIRE[)

Lee I” Peir. S.C. 100 Coal 4/15/20 5 Lee 2 PeIir. S.C. 100 (‘oal 4/15/2015

Lee 3” Pelzer. S.C. 170 Coal /1/2015

Total 2,037 MW

60

Note

Note

Note Note

\jte

e:

d:

c:

a:

h:

Ihe

I,ee replacement

retirement

Retirement

the

The

coii

Steam

decismn

old

ersion

a

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date I

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general

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15,

retire

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2015.

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retirement

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with

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a

&

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natural

to

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o[

and

conditions

the

retired

dates

gas

61

Riverbend

remaining

unit

were

as

indicated

is

in

accelerated

planned

6

units.

the

&

7

NCUC

earb

in

tbr

the

in

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on

table.

2009

Order

April

o12()

based

in

1.

IS.

2013.

Docket

on

derates.

The

No.

original

E-7.

aailabilit

Sub

e’ipected

790. of Operating License Renewal

Planned Operating License Renewal

Original Operating Date of Extended Operating Plant & Unit Name Location License Expiration Approval License Expiration

Catawba Unit I York, SC 12/6/2024 12/5/2003 12/5/2043

Catawba Unit 2 York, SC 2/24/2026 12/5/2003 12/5/2043

McGuire Unit I Iluntersville, NC 6/12/202! 12/5/2003 6/12/2041 McGuire Unit 2 Huntersville, NC 3/3/2023 12/5/2003 3/3/2043

Oconee Unit 1 Seneca, SC 2/6/2013 5/23/2000 2/6/2033 Oconee Unit 2 Seneca, SC 10/6/2013 5/23/2000 10/6/2033

Oconee Unit 3 Seneca, SC 7/19/20 14 5/23/2000 7/19/2034 Bad Creek (PS)(1-4) Salem, SC N/A 8/1/1 977 7//31/2027 Jocassee (PS) (1-4) Salem, SC N/A 9/1/1966 8/31/2016 C’owans Ford (1-4) Stanley, NC 8/31/2008 Pending 8/31/2064 (Est) Keowee (1&2) Seneca. SC N/A 9/1/1966 8/31/2016 Rhodhiss (1-3) Rhodhiss, NC 8/31/2008 Pending 8/31/2064 (Est) Bridge Water (1-3) Morganton, NC 8/31/2008 Pending 8/31/2064 (Est) Oxford (1&2) Conover, NC 8/31/2008 Pending 8/31/2064 (Est) Lookout Shoals (1-3) Statesville. XC 8/31/2008 Pending 8/31/2064 (Est) Mountain Island (1-4) Mount Holly, NC 8/3 1/2008 Pending 8/31/2064 (Est) Wylie(l-4) Fort Mill, SC 8/31/2008 Pending 8/31/2064(Est)

Fishing Creek ( 1-5) Great Falls, SC 8/31/2008 Pending 8/31/2064 (Est) Great Falls (1-8) Great Falls, SC 8/3 1/2008 Pending 8/31/2064 (Est)

Dearborn ( I-3) Great Falls, SC 8/3 1/2008 Pending 8/3 1/2064 (Est) Rocky Creek (1-8) Great Falls, SC 8/31/2008 Pending 8/31/2064 (Est) Cedar Creek (1-3) Great Falls, SC 8/31/2008 Pending 8/31/2064 (Est) Wateree (1-5) Ridgeway, SC 8/31/2008 Pending 8/31/2064 (Est) Gaston Shoals (3-6) Blacksburg, SC 12/31/1993 6/1/1996 5/3 1/2036

Tuxedo ( I&2) Flat Rock, NC N/A N/A N/A Ninety Nine (1-6) Blackshurg, Sc, 12/3 1/1993 6/1/1996 5/31/2036

Cedar Cliff(1) luckasegee, NC Ii3 1/2006 5/1/201 I 4/30/2041 Bear Creek (1) l’uckasegee, NC 1/31/2006 5/1/2011 4/30/2041

lennessee Creek ( I) luckasegee, NC 1/31/2006 5/1/201 1 4/30/2041 Nantahala (1) Topton, NC 2/28/2006 2/1/20 12 1/31/2042

62 Planned Operating License Renewal cont.

()riginal Operating Date of Extended (.)perating Plain & Unit Name Location License Expiration Approval License Expiration Queens Creek (1) Tupton, NC 9/30/200! 3/1/2002 2/29/2032

Thorpe (I) luckasegee. NC 1/31/2006 5/1/20! 1 4/30/2041

Tuckasegee ( I) ‘[uckasegee, NC 1/31/2006 5/1/201 I 4/30/204! Bryson City (l&2) Whittier, NC 7/31/2005 7/1/2011 6/30/2041 Franklin (1&2) Franklin, NC 7/31/2005 9/1/2011 8/31/2041

Mission (1-3) Murphy, NC 7/3 1/2005 10/1/201 I 9/30/204 I

63 API[NDIX C: ELECTRIC LOAD FORECAST

MethodoIoy

The 1)uke Energy Carolinas’ spring 2013 forecast provides projections of the energy and peak demand needs for its service area. The forecast covers the time period of 2014 through 2028 and represent the needs of the lollowing customer classes:

• Residential • Commercial • Industrial • Other Retail • Wholesale

Long-term electricity usage is determined by economic and demographic trends. The spring 2013 forecast was developed using industry-standard linear regression techniques, which relate electricity usage to such variables as income, electricity prices, industrial production index along with weather and population. DEC has used regression analysis since 1979 and this technique has yielded consistently reasonable resu Its over the years.

[he economic projections used in the spring 2013 ibrecast are obtained from Moody’s Analytics, a nationally recognized economic fbreeasting firm, and include economic forecasts fbr the states of North Carolina and South Carolina.

The retail forecast consists of the three major classes: residential, commercial and industrial.

The residential class sales forecast is comprised of two proiections. ‘l’he first is the number of residential customers, which is driven by population. [he second is energy usage per customer, which is driven by weather, regional economic and demographic trends, electric price and appliance efficiencies. The usage per customer threcast is essentially flat through much of the forecast horizon, SO most growth is primarily due to customer increases. ‘[he projected growth rate of residential sales in the spring 2013 forecast from 20 14-2028 is 1.2%.

Commercial electricity usage changes with the level of regional economic activity, such as personal income or commercial employment, and the impact of weather. ‘[he three largest sectors in the Commercial class are offices, education and retail. Commercial is expected to he the fastest growing class, with a projected sales growth rate of 1.8%.

The industrial class forecast is impacted by the level of manufacturing output, exchange rates, electric prices and weather. The long term structural decline that has occurred in the ‘I’extileindustry is expected to moderate in the forecast horizon, with an overall projected sales decline of 1.2%,

64 compared to an average decline of 7.2% from 1997-2012 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 0.9% over the forecast horizon. Including all industrial classes, the overall sales growth rate of the total industrial class is 0.6% over the forecast horizon.

County population projections are obtained from the North Carolina Office of State Budget and Management as well as the South Carolina Budget and Control Board. These are then used to derive the total population forecast for the 51 counties that comprise the DEC service area.

Weather impacts are incorporated into the models by using Fleating Degree Days and Cooling

Degree Days with a base temperature of 65 degrees. The forecast of degree days is based on a 10- year average, which is updated every year.

Peak demands are forecasted by an econometric model where the key variables are:

• Degree Hours from 1pm - 5pm on Day of Peak • Minimum Morning Degree Hours on Day of Peak • Annual Weather Adjusted Sales

Assumptions

The primary long-term drivers of electricity growth are economic and demographic factors. The table below includes the historical and projected average annual growth rates of several key drivers from DEC’s spring 2013 forecast.

1992-2012 2012-2032 Real Gi)P 2.9% 3.0% Real Income 3.1% 2.8% Population 1.6% 1.0%

In addition to economic and demographic trends, the Ibrecast also incorporates the expected impacts of utility sponsored energy efficient programs, as well as projected effects of electric vehicles and solar technology.

The residential fbrecast also uses the Energy lnfhrmation Administration (EIA) appliance efficiency and saturation projections by Census regions, in an effbrt to more fully reflect the ongoing naturally occurring energy efficiency trends as well as government mandates. The utility-sponsored EE programs are over and above the naturally occurring trend.

65 Wholesale

Table C—Ibelow contains iniormation concerning E)EC’s wholesale contracts. [he description tull indicates that the Company provides all of the needs of’ the wholesale customer. Partial’ refers to those customers where DEC only provides some of the customers needs. ‘Fixed’ refers to a constant load shape.

For resource planning purposes, the contracts below are assumed to he renewed through the end of the planning horiion unless there is definitive knowledge the contract will not he renewed. The values in the table are net MW, i.e. they reflect projected loads after the buyer’s own generation has been subtracted.

66 Table C-I Wholesale Contracts

Wholesale Contracts Commitment (MW) Customer Product Term 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Concord Partial Requirements 2009-2018 167 169 172 174 177 180 212 215 217 220 l)allas Partial Requirements 2009-2028 11 11 11 12 12 12 12 12 13 13 I)ue Vv’est Partial Requirements 2009-2018 2 2 2 2 2 2 2 2 2 2 Forest (‘itv Partial Requirements 2009-2028 18 18 19 19 19 20 20 20 21 21 (ircenv’ood Full Requirements 2010-2018 53 53 54 55 56 57 58 58 59 60 I Iiihlands Full Requirements 2010-2029 9 9 9 9 9 9 9 9 10 10 Kings Mountain Partial Requirements 2009-2018 21 21 21 22 22 22 30 30 30 31 I ock hart Partial Requirements 2009-2018 50 50 51 52 54 75 76 77 78 Prosperity Partial Requirements 2009-2028 2 2 2 2 2 3 3 3 3 Western Carolina Full Requirements 2010-2021 6 6 6 6 6 6 6 6 6 6 Blue Ridge FMC I nil Requirements 2010-2031 225 229 233 237 241 245 249 253 257 261 Central Partial Requirements 2013-2030 120 244 374 509 649 793 900 918 936 953 I lay wood LMC Full Requirements 2009-2021 23 23 23 24 24 24 25 25 25 26 NC! MC Fixed Load Shape 2009-2038 72 72 72 72 72 72 72 72 72 72 NCEMC Backstand 1985-2043 95 116 116 116 116 116 116 116 116 116 Piedmoni FMC Full Requirements 2010-2031 87 88 89 90 92 93 94 96 97 99 PMPA Baekstand 2014-2020 0 47 47 47 47 47 47 47 47 47 Rutherfbrd I MC Partial Requirements 2010-203 I 185 189 204 208 212 217 221 226 230 235 Historical Values

Two major events occurred in the past decade that significantly impacted DEC sales. One was the recession of 2008-2009, which was the most severe since the Great Depression. ilie second is the

ongoing re—structuring of the textile industry, which began in the late I990s. The average growth rate in retail sales from 1997-2007, excluding textiles, was 2.2%. From 2007- 20 12, the average growth has been -0.1 %, primarily due to the effects of the recession. In Tables C-2 & C-3 below the history of DEC customers and sales are shown. The values in Table C-3 are not weather adjusted.

Table C-2 Retail Customers (Thousands, Annual Average) 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Residential 1,872 1,901 1,935 1,972 2,016 2,052 2,059 2,072 2,081 2,092 Commercial 307 313 319 325 331 334 333 334 336 339 Industrial 8 8 7 7 7 7 7 7 7 7 Other II 12 13 13 13 14 14 14 14 14 R)tal 2,198 2,234 2,275 2,317 2,368 2,407 2,413 2,427 2,439 2,452

Table C-3

Electricity Sales (GWh Sold - Years Ended December 31) 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Residential 23,947 25,150 26,108 25,816 27,459 27,335 27,273 30,049 28,323 26,279 Commercial 24,355 25,204 25,679 26,030 27,433 27,288 26,977 27,968 27,593 27,476 Industrial 24,764 25,209 25,495 24,535 23,948 22,634 19,204 20,618 20,783 20,978 Other 270 269 269 271 278 284 287 287 287 290 Total Retail 73,336 75,833 77,550 76,653 79,118 77,541 73,741 78,922 76,985 75,022 Wholesale 1,448 1,542 1,580 1,694 2,454 3,525 3,788 5,166 4,866 5,176 Total System 74,784 77,374 79,130 78,347 81,572 81,066 77,528 84,088 81,851 80,199

68 Results

A tabulation of the utility’s Ibrecasts for a 15—yearperiod, including peak loads for summer and winter seasons of each year and annual energy forecasts, both with and without the impact of’utility— sponsored EL programs are shown below in Fables C-4 and C-6.

Load duration curves, with and without utihly—sponsoredEL programs, follow fables C-4 and C-6, and are shown as Charts C-5 and C’-7.

‘Ihe values in these tahies reflect the loads that I)uke Energy Carolinas is contractually obligated to provide and cover the period from 2014 to 2028.

The lorecast of the needs of the retail and wholesale customer classes from 2014—2028,not including the impact of [)[C EL programs, projects a compound annual growth rate of I.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 1.9% helbre energy efficiency program impacts are subtracted. if the impacts of l)EC LE programs are included, the projected compound annual growth rate lbr the summer peak demand is 1.5%, while winter peaks are forecasted to grow at a rate of 1.5%. The forecasted compound annual growth rate for energy is 1.5% afler the impacts of EL are subtracted.

As a note, all of the loads and energy in the tables and charts below are at the generator.

69

and

Note.

Table

Load

a

47

Table

MW

YEAR

2028

2027

2026

2025

2024 2023

2022

2021

2019

2020

2018

2017

2016

2015

2014 Forecast

C-4

8-C

PMPA

differs

hacksiand

without

from

these

SUMMER

contract

24,017

23,655

23,280

22,901

22,525 22,143

21,776

21,417

21,067 20,717

20,231

19,780

19,328 18,875

(MW)

18,443

alues

Energy

through

due

to

Efficiency

a

2020

70

150

MW

WINTER

23,015

22,660

22,299

21,925 21,563

20,495

21,195 20,842

20,143

19,376

19,789

18,961

18,553

17,718 (MW)

18,132

fim

Programs

sale

in

20

4

ENERGY

122,243

120,327

1

112,522 110,634

116,405

114,471

108,749

106,904 105,027

102,773

100,356

(GWh)

98,023

93,566

95,762 18,371 ______

Chart C-5 Load Duration Curve without Energy Efficiency Programs

24,000

22,500

21,000

19,500

18,000

16,5O0

15,000 d c:,_—•-

10,500

9,000 -______

7,500 “I’h’

6,000

4,500 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Percent of Hours

-2O13 2018 2023 —2028

and

Note:

Table

Load

a

47

Table

YEAR

2028

2027 2026

2025

2024

2022

2023

2020

2021

2019

2016

2017

2015 2014

MW

Forecast

C-6

8-C

PMPA

differs

hackstand

from

with

SUMMER

22,209

22,496

21,922

21,643

21,378

21,104

20,848

20,359

these 20,598

20,117

19298

19,741

19,053

(MW)

18,691 18,332

Energy

contract

values

throuh

due

Efficiency

to

a

2020.

72

150

WINTER

21,790

21,496

21,206

20,913

20,640

20,093

20,359

MW

19,834

19,304

19,571

18,979 18,685 (MW)

18,359

17,654

18,009

Programs

firm

sale

in

2014

ENERGY

113,769

112,294

110,825

108,089

109,418 104,187

106,748

105,469

102,948

100,032

101,678

(GWh)

98,226

96,475

92,943 94,721 Chart C-7 Load Duration Curve with Energy Efficiency Programs

24,000

22,500

21,000

19,500

18,000 I o 16,500 a ci 15,000

13,500 M w 12,000

10,500

9,000

7,500

6,000

4,500 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Percent of Hours

—2013 2018 —2023 —2028 APPENDiX D: ENERGY EFFICIENCY AND DEMANI) SIDE MANAGEMENT

Current Energy Efficiency and Demand-Side Management Programs

In May 2007, I)EC filed its application for approval of Energy Efficiency and Demand Side Management programs under its save-a-walt initiative. The Company received the final order for approval ftwthese programs from the NCUC in July 2010 and from the Public Service Commission of South Carolina (PSCSC) in May 2009.

E)FC uses EE and DSM programs to help manage customer demand in an efficient, cost-effective manner. These programs can vary’greatly in their dispatch characteristics, size and duration of load response, certainty of load response, and level and frequency of customer participation. In general, programs are offered in two primary categories: EE programs that reduce energy consumption and DSM programs that reduce peak demand (demand-side management or demand response programs and certain rate structure programs). Following are the EE and DSM programs currently available through DEC.

• Residential Energy Assessments Program • Low Income Energy Efficiency and Weatherization Assistance Program • Residential Neighborhood Program • Energy Efficiency Education Program for Schools • Residential Smart Program • Appliance Recycling Program • My Home Energy Report • Residential Retrofit Pilot Program (‘Closedto New Participants) • Smart Energy Now (SEN) Pilot (On/vAvailable in NC • Smart $aver’ for Non-Residential CListomers • Power Manager’ • Interruptible Power Service (Closed to New Participants,) • Standby Generator Control (‘Closedto New Participants) • PowerShare’

A new portfilio tiling with essentially the same set of programs was made in March 2013 in N.C. and Aug. 2013 in S.C. Pending approval of this new portiilio, a revised set of programs will he included in the 2014 IRP.

Energy Efficiency Programs

‘l’hese programs are typically non-dispatchable education or incentive programs. Energy and capacity savings are achieved by changing customer behavior or through the installation of more

74

below.

programs energy—efficient

•

energy

specialist

personalized about

home

occupants,

The

program.

customized

receives

The

Personalized The

Residential

i)E(”s

I)ecemher

December

through

•

•

PER

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home

Residential

Energy

saving

online

bill An

their

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house and

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201

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where

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to

2012

as

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energy

their

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customers

Participants

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Home

Report

a

Assessments

and

customers

(PER)

a

86,318

12,902

or

printable

The

they are

include:

customers

their

free

light

home

PER

complete

how

to

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Energy

reflected

energy

All

use

the and

provides

in—home PER

rrogram

online

bulbs

that

cumulative

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document energy

customer’s

(2)1

and

75

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in

are

save

analyze

provide

specialist

program

the

Comparison

have

the

Energy

in

has

as

Energy Tome

(CFLs)

assessmcnl

asked

customers

same

within

the

a

on

mail

(MWh)

signed

two

(MWh)

24,493

printable

participants

3,547

Report

eflècts

Energy

information

total

home

customer

monthly

Savings

to

Savings

survey

variations:

explains

includes

and

as

their

complete

into

home

Report

an

in

those

designed

since

and

fiouse

document

home.

single

online.

incentive

I)EC’s

hills.

load

energy

complete

how

two

about

the

energy

completing

an

Call

Peak

Peak

inception

forecast

to

to

family

In

The

included separate

Online

Customers

their

practices.

(kW)

2,788

(EIEHC).

(kW)

help

addition,

improve

387

Demand

to

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usage

their

program

participate

home,

dwellings

customers

it

and

and

Services

of

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online

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measures:

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the

mailing

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summarized

number

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receive

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(1)

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installation

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of

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not

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immediately.

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equipment

high

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install

this

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levels,

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Education

impact

been

to Efliciency

program

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repoi-t

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reduce

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check

or

implemented.

preserve

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schools

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Program

Home

well

21,293

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is

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76

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Ventilation

for

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and

measures.

targets

plans,

low

House

a

efficiency

Energy

students

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through

included

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Schools

examine

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(MWh)

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(MWh)

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energy

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for

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and

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about

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neighborhoods

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levels,

program,

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allow

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customer

(kW)

customer,

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(kW)

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793

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kits

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(HVAC)

or

customers

31,

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assistance

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appliances

for

2012

private

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filters

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ways.

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Demand

during

bulbs

Demand

CFLs

high-ef’ficiency

fin’

air

increase

installed.

who

the

were

builders

their

conditioners

free

managers

CELs

have

purchase

coupons

shipped

routine utilized

energy

been

and

and

air to

•

•

to

measures,

recommendations

‘The

‘Flie

the

My

E’his

freezers

Appliance

conditioner

been

Partnering

Tune

systems

and

identify

December

l)ecember

same

December

Home

purpose

program

heat

previously

is

and

a

and

geographic in

As

As

undertaking

As

pumps.

program

Seal

those

with

Energy

new

Recycling

and

have

of:

of

of

of:

31,

31,

assists

31,

Residential

this

Ilieasures

HVAC

homes

ollered

heat

customers

2012

2012

those

2012

tor

Residential

The

Report

to

program

area

residential

more

pump

more

Program

incentivize

and

units

dealers,

in

program

to

Appliance

any

Smart

Participants

efficient

Participants for

who

Participants

energy

tune

motivate

properly

is

37,383

1,990

of

Smart

replacement

to

23

the

could

customers

ups

DEC’s

is

Saver®

provide

households

efficient

program

designed

use

Recycling

and

customers

recycled.

$aver®

benefit

78

of

jurisdictions.

duct

Program

comparative

energy

systems

practices

in

Energy

Energy

pays

Energy

to

Program

sealing.

most

assessing

to

Program

(MWh)

to

(MWh)

(MWh)

increase

3,286

37,032

incentives

remove

in

better

1

in Savings

--

Savings

by 1

Savings

their

and

Tune

existing

usage

investing This

--

manage

their

participating

the

homes.

HVAC

old

to

anti

is

data efficiency

homes.

partially

energy

inefficient

a

Seal

Peak

Peak

and new

in

Peak

for

‘[‘he

new

(kW)

(kW)

7,835

(kW)

reduce

610

similar

in

program

[)emand

Demand

usage

Demand

3

oftset

program

of

DEC

energy

refrigerators

air

energy

and

the

residences

programs.

conditioning

and

also

efficiency

cost

provides

has

usage.

helps

of

and

not

air in

•

•

•

to

pumps, equipment

to

incentives

The

lighting,

new Smart

consumption

office

make

behavioral

The

Smart

[jecember

efficient

recommendations

assessing

more The

Residential

;.

he

ofiset

December

I)ecem

purpose

and

SEN

evaluated

Residential

efficient

space

these

Saver®

Energy

variable

As

high—efficiency

a

existing

As

As

their

her

may pilot

improvements

portion

are

modification.

of:

31,

of

of:

of:

Retrofit

located

infbrmation

31,2012

behavioral

3

eligible

on

energy

be

this

1,

for program

use

Now

2012

non—residential

201

frequency

a

Retrofit

of

paid

from

Non-Residential

program

case-by-case

of

the

2

in

(SEN)

Pilot

usage.

energy

for

for

Smart

the

Residential

My

air

Charlotte

higher

is

and

modifications,

In

Participants

by

other

incentives

Participants pilot

assessment.

conditioning

designed

Participants

Home

Program

702,215

order

is

Pilot

drives,

actionable

The

offsetting

in

to Energy

70

cost

94

establishments.

high-efficiency

basis

program

encourage

their

to

City

program

(Only

Energy

Retrofit

of

enable

to

food

Customers

as

through

(Closed

Now

energy—efficient

homes

Center

reduce

79 efficiency

equipment,

Available

part

they

a

is

Report

services

is

building

Energy

the

Energy

Pilot

portion

Pilot

of

also

designed

Capability

the

and

will through

energy

to

160,021

(MWh)

installation

(MWh)

equipment the

(MWh)

14,108

The

New

Program

Custom designed

4

Program

recommendations.

Program

in

to

Savings

I

high—efficiency

Savings

Prescriptive

be

0

and managers

program

of

N.C.)

encourage

consumption

Participants)

equipment.

community

to

provided

the

pmcess

program.

of

as

assist

to

high—efficiency’

provide

detennined

provides

cost

and

Summer

program:

Peak

Peak

the

residential

with

equipment.

occupants

motors,

engagement

1’he

within

of

2,649

(kW)

33,857

(kW)

installation

(kW)

recommendations

Demand

Demand

68

incentive

Capability

following

implementing

additional

by

the

high—efficiency

high—efficiency

the

equipment

to

customers

commercial

effectively

Company leading

Customer

payments

ol

types

energy

energy

the

for

of’

in

to in Non-Residential Smart Saver® rrogram Energy Savings Peak Demand As of: Participants (MWh) (kW) December 31, 2012 1,342,909 617,614 103,225 [

Deniand Side Maiuigemenl Programs

DEC’s current I)SM programs will he presented in two sections: I)ernand Response [)irect Load Control Programs and 1)emand Response Interruptible Programs and Related Rate Tarift.

Demand Response Direct Load Control Programs These programs can he dispatched by the utility and have the highest level of certainty. I)EC’s current direct load control curtailment programs arc:

• Power Managers’ - The Power Manager program is a residential direct load control program that allows [)EC, through the installation of load control devices at the customer’s premise, to remotely control residential central air conditioning.

Participants receive hilling credits during the hilling months of July through October in exchange for allowing DEC the right to cycle their central air conditioning systems and, additionally, to interrupt the central air conditioning when the Company has capacity needs.

The program provides DEC with the ability to reduce and shift peak loads, thereby enabling a corresponding deferral of new supply-side peaking generation and enhancing system reliability.

Participating customers ai-e impacted by (I ) the installation of load control equipment at their residence, (2) load control events which curtail the operation ol their air conditioning unit fbr a period of time each hour, and (3) the receipt of bill credits from [)EC in exchange for allowing DEC the ability to control their electric equipment.

Power Manager Statistics Summer Capability As of: Participants (MW)

December 3 I, 2012 185,043 280.4

The following table shows Power Manager program activations that were not fbr testing purposes from Jtine 1, 2011 through June 30, 2013.

80

•

shill

notification

interruptible

recuesting

‘liese

Demand

‘[he

specified

1,2011 so

reduce

Interruptible

load.

*

during

programs

clock

August

Ibllowing iir

June

July

July

Ju1y26,2012—2:3OPM

June

July July

July

July

July11,

July9,2012—1:3OPM

Response

curtailment

their

through

‘Timing.

Loud

and hours.

of

27,

level.

21,

29,

20,

29,

17,2012—2:3OPM

21,2011

13.

an

Start

2,

an

electrical

time—ofuse

2012—

Reduction

201

2011 201

2011

2011

2012—

interruption,

201

rely

table

Power

June event

—

frequency

1

1

Time

I Interruptible

—

—2:30

or — —2:30 —

— either

—

shows

2:30

1:30PM

2:30

2:30 2:30

30.

2:30

on 3:30

Service

i

loads

or

the

2013.

rates

rate

PM

PM

PM

PM

PM

PM

PM

after

on

PM

they

IS

and

clecruge

to

structure

program

with

the

(IS)

Power

specified

nature

receive receiving

Programs

August

customer’s

loud

price

June

July27,

July

Ju1y26,2012—6:OOPM

(North

June

July

July

July

July

July

July9,2012—5:OOPM

curtailment

Nllanagerk

ot

activations

reduction

a

21,2011

29,

20,

17,2012—5:00

29,

signals

13,

21,2011

11,2011—6:00

levels

the

penalty

2,

pricing

nd

Carolina

and

2012—4:00

201

81

2011

201

2012—

201

load

ability

Time

that

upon

1

1

‘a!

Related 1

— —5:0() —

— Activations

—

programs —

that

response

for

signals.

5:00

6:00

5:00

5:00

(he

5:00

6:00

Only)

provide

request

the

generu!or

to

were

PM

PM

PM PM

PM

PM

PM

PM

PM

Rate

PM

respond increment

-

depend

include:

not

Participants

an

[)uke

by

Structures

I

economic

fbr (N’linutes)

Duration

over

DEC.

210

210

to

150

150 210

210

150

150

150

150

150

testing on

150

Energy

of

the

a

customers’

demand

If

event

agree

utility—initiated

incentive

customers

PUPOSC5

Carolinas’

period Red

MW

contractually

exceeding

152

143 152

141

113

115

1

102

1

uction*

108 101

101

10

15

actions

to

Load

for

from

fail

reduce

fit!!

current

signal

to

June

afler

the

do

to or

•

option

emergency

option

based

PowerShare

and/or

1,2011

customers

and

the

to

The

Standby

transfer

•

*1111

Company.

*?fJJ.

following

July

therefore,

June

July

voluntary June

that

PowerShare

for

capacity

utility-initiated

load

PowerShare energy

through

Load

Load

12,

Cenerator

12,

1,2011

load

allows

Start

receive

electrical I,

only

Start

curtailed

Reduction

201

2011

2011

Rehieiion

table

transferred

December

cannot

is

The

curtailment

June

credits

option

option

Time

1

Time for

—

a

—1:00

payments

shows

generators

1:00

1:00

Voluntary

30,

non-residential

As

1:00

Mandatory:

loads

increased iv

Control

i.c

emergency

during

the

(PowerShare

‘hackfeed”

monthly

ihe

For

2013.

oF

PM

PM

31,

PM

to

PM

overage

SG

average

from

using

curtai

their

2012

for

program

(SC)

in

and

notification

events.

July

June

July

the

based

June

loud

this

generators.

lable

load

capacity

oil—site

events.

Participants

(i.e.,

eligible

(North

1)EC

SC

12.201

reduction

curtailment

12,

program

1,2011

reduction

IS

SC

Voluntary)

1,2011

End

activations

load

End

on

Participants

Activations export

Activations

2011

generators

Statistics

(ustorners

source

82

the

and/or

time

to

Time

Participants

Carolina

1

Time

(PowerShare

87 —6:00PM

—

‘at

—6:00 earn

—

at

do

amount

5:00

in

power)

5:00

of

11i’

the

to

not

and

that

program

energy,

this

additional

events

generalor’’

generator’’

their

PM

(PowerShare

PM

PM

Only)

operate

a

were

enrolled

emergency

of

into

combined

also

Summer

standby

(PowerShare

load

based

(Minutes)

not

Mandatory), Duration

-

consisting

(Minutes)

Duration

over

the

over

credits. in

receive

Participants

240

300

300

240

for

(MW)

parallel

they

44.0

may

the

DEC

the

on

Capability

generators

emergency

testing

only

Generator),

even!

event

the

agree

energy

also

system.

of

with

period.

CallOption).

Red

option

period

an

amount

MW

Red

purposes

MW

agree

Four

to

emergency

he

uction*

the

45

55

upon

uction*

156

133

credits

and

curtail

Load

Load

an

contractually

will

enrolled

Participating

options:

DEC

of

economic

economic

request

1mm

capacity

receive

for

during

system

only

June

the

an

in of

•

*111;’

•

*11W

July

June

July

June

PowerShare

‘[he

tor

the

transfer

ertbrrnance

capacity

PowerShare 1

The

load

tbr

Load

12,2011

12,

1,

testing

Start

1,2011

load

testing

Start

following

201

l?eth,eiion tollowing

1?ednc/ion

2011—

December

December3l,2012

to

curtailed

1

Time

credits

Time purposes —

— purposes

—

their

1:00

1:00

1:00

during

Voluntary:

1:00PM

As

is

As

Generator:

is

table

table

the

the

on—site

of:

PM

monthly

PM

31,

of:

during

PM

lowerShare 5

average

PowerShare

average

from

PowerShare

PowerShare

from

shows

monthly

shows

2012

generator)

July

June

June

events.

.luly

.June

/00(1

June

Enrolled

load

based

PowerShare

PowerShare

Participants

12,2011—5:00

,‘e1uetion

1, test

12,2011

I,

reduction

1,

1,2011

End

2011

End

201

Generator

2011

Participants

Mandatory

on

Participants

Generator

hours.

Mandatory

during

customers

83

Time

1

Time

through the

—

169

9 through

—

—5:00

at

ai

6:00

6:00

in

the

Generator

Mandatory

the

amount

Participants

utility—initiated

generator’’

this

Activations

generator’

PM

PM

PM

Activations

June

Statistics

PM

will

June

Statistics

emergency

{

JDuration

Summer

of

30,

Summer

he

30,

program

(Minutes)

(Minutes)

program

I)uration

over

load

notilied over

2013.

also

2013.

240

300

240

300

(MW)

(MW)

366.4

13.4

the

emergency

the

Capability

they

Capability

receive

even!

only

activations

event

activations

of

agree

ji’ioc1

Reduction*

pending

period

MW

Red

option

MW

energy

events

339

334

13

uction*

17

to

Load

Load

that

that

will

emergency

curtail

credits

were

and

were

receive

their

(i.e.

not

fbr 1101 itIfl’

August

July

July

July June2,

June

and

emergency

are

participation

ability

reduce

PS

Economic

PowerSharek

Load

The

fbr

that

program, or

Voluntary is will

particular

22,

21,2011

20,

1,2011

economic

provided.

5/5,

testing

Start

3,

set

applicable

201

also

l?eduction

be

following

2011

201

201

a to

and

December

paid

PS

1

limit

participate

1 Time

—

no

1

receive —2:00PM

—

purposes

event. Events. —

—

only events.

—

10/5

maintain

I

1:00

the

1:00

1:00

capacity

option

1

is

events

2:00

As

CallOption:

:00

for

table

the

The

when

posted

and

and

PM

of:

PM

PM

3

Economic AM average

Customers

PM

credits

PowerShare

Credits

1.

CallOption

from

PowerShare

in

statistics

and

it

shows do

PS

2012

its

benefit

has

the

PoerShare’

energy

not

can

June

1 loud

load

August

5/5.

July

July

July

when

June

June

selected.

are

customer

PowerSharek

double

This

Events

log

reduction

will

is

values

1,

by

credit

paid 22,

20,

21,2011—7:00

All

offers

2,

1,2011

recognized

2011

on

the

3.

Voluntary

End

Participants

DSM

a

2011

then

201 201 Voluntary

2011

options

count

for

84 to

to

minimum

Voluntary.

customer

for

Participants

through

fails

below

Time

four 6

al

1

1

a

0,

the

have

—8:00PM —9:00 — —

program

website the

—

load

5,

Voluntary

4:00

7:00

the

7:00

participation

load

generator”

to

include

10

for

Activations

the

represent

curtailed.

Statistics

June

participants

PM

and

PM

PM

PM

reduce of

agrees,

this

PM

available

to option

offers

are

Summer

100

30,

15 view

program

a

program

over

limit

obligated

respectively.

(Minutes)

Duration

2013.

kW

load

at

participation

to

options

Since (MW)

a

a

the

360

300

300 360 N/A

360 480

for

the

in

posted

participate

participating

Capability

of

during event

and

in

PowerShare 3

curtailment,

activations

live Company’s

this

to

accordance

to

jc’riod

no

energy

is

curtail

customers:

Reduction*

Emergency

Emergency MW

capacity

a

in

in

voluntary

16

4

2 2

2 2

customer

the

that

Load

PowerShareR

price

and

load

request,

Mandatory

event with

incentive

were

charges

PS

tbr

Events

during

and/or

event

0/5,

that

and

the

the

not to

programs The

table •

.

July

and Ill

emergency

The economic

economic

customers

same

participate

PowerSharek

below

br Fhe

Load

the

27,2012

testing

program

Start following

Reduciion

manner

capability

incorporates

December

Time purposes.

purposes

load

with events.

—

will

is

CallOption 1:00

As as

is

table

not

curtailment of

the

very

experience the

of:

3

PM PowerSha

these available

average

1,

PowerShare

from

shows

l)ecember

Company’s

Participants

201

flexible

programs

June

2

.luly 200:

load

PowerShare’

Ihr

each

re®CallOption considerably

reduction

27,

1,

load

customer

This

31,

2011

End

Participants

other

will

year.

2012—

projected CallOption

85

and

2012

new,

Time

through remain

“at

1

CallOption

curtailment

This

participation CallOption 9:00

the

high

participation

for more

generator•

Activations

June

PM

obligated Statistics

option

the

involvement

Summer

requests

summer

30,

otters. (Minutes)

program

Duration

potential until

over

will

201

480

to

(MW) levels

ihe

0.2

3.

January

of flmnction

curtail Capability

however, for

eve,?,

CallOption 2013.

activations

of

for load

period.

ReductiozJ

up

MW

load

1,

demand

essentially

2014.

to

0.2

curtailment

customers

during

Load

200

is

that

targeted

hours response

were

up in

Who

to the

not

lhr

of

at 5 DSM Program Participation and Capability

1Participation as 2013 Estimated Summer DSM Program Name of 12/31/12 IRP Capability (MW) 15 63 117 SG 87 40 PowerShare Mandatory 169 375 PowerShare Generator 9 14 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 1 0 -- Level 200* 0 0 Power Manager 185,043 305 Total 185,378 851 R * PowerShare (illOption level 200 will he available for partici[xthon on I I 2014.

Rates using price signals • Residential Time-of-Use (including a Residential Water Heating rate) This category of rates for residential customers incorporates differential seasonal and time-of-day pricing that encourages customers to shift electricity usage from on-peak time periods to off-peak periods. In addition, there is a Residential Water Heating rate for offpeak water heating electricity use.

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

• Hourly Pricing for Incremental Load This category of rates for general service and industrial customers incorporates prices that reflect DEC’s estimation of hourly marginal costs. In addition, a portion of the cuStomer’s bill is calculated under their embedded-cost rate. Customers on this rate can choose to modit’ their usage depending on hourly prices.

The projected impacts from these programs are included in the assessment of generation needs.

86 Summary and A

programs included

in

Future expanding for

this

EE

The and EE to programs conditions effectiveness capacity

on

and tests: program. focused

Ihe

new

addition,

measure

changing August

a

pilots.

and

year’s

•

energy

Company

analysis

level

Participant

portlblio

Utility

This customer systematic assessment Energy

and

EF

The

societal

implement in

DSM

primarily

additions,

along

of and

playing analysis

existing

the

2013

maintenance-based

and/or

and

Estimates

DEC the

values

pilot

Prospective market

(JCT

Cost

of

over

2014

measures.

Program

with uses

risks

Management filing

DSM

energy

impacts.

in

Test.

is

with

is

approach

energy

field.

on a

Test

to

compares of

SC.

programs and

continually

the

of

IRP.

the

wide the conditions

and

designed

with

the of help generation

programs

EE

an

program,

efficiency further,

(UCT),

Pending following

DSMore

DSMore

the

Screening

benefits

calculation This Program

variety

Included

costs

DSMore

essentially

energy the and

to

impacts

to

utility

and

test

energy

customer to

seeking

reduce and

to

DSM

or

Rate

include

approval

needs.

and of

of

provides

model

provide

program ensure

and

compares

prices. management

in

Information

new is

Opportunities

weather

employing

benefits

of of

Impact the this

does

a

measures efficiency

demand

energy

to

specific financial these

additional

measurement

to

identi1’ same

that

new

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he Base Case Load Impacts of EF and DSM Programs EE Program Savings DSM Program Summer Peak MW Savings Total Summer Annual Summer Power Total Peak Year MWh Peak IS SG PowerShare Manager DSM MW Energy MW Savings 2013 435,988 40 117 40 389 305 851 891 2014 810,708 111 101 32 427 350 911 1,022 2015 1,271,350 184 96 29 459 399 983 1,167 2016 1,824,144 275 92 26 487 409 1,014 2017 2,436,079 382 87 24 515 411 1,037 2018 3,046,042 490 83 21 545 411 1,061_ 2019 3,654,035 600 83 2 — 545 — ,661 2020 4,260,057 708 83 2 — 545 — ,769 2021 4,864,109 819 83 2 545 11 — ,880 2022 5,466,189 929 83 2 545 ,990 2023 6,084,580 1,040 83 21 545 4 — 2,101 2024 6,682,978 1,110 83 545 4 1,061 2,171 2025 7,290,633 1,219 83 21 545 4 2,280 2026 7,801,137 1,318 83 21 545 4 1,061 2,379 2027 8,267,015 1,404 83 21 545 4 1,061 2,465 2028 8,683,743 1,477 83 21 545 4 1,061 2,538

[)EC’s approved FE plan is consistent with the requirement set Ihrth in the Clifliide Unit 6 CPCN Order to invest 1% of annual retail electricity revenues in FE and DSM programs, subject to the results of ongoing collaborative workshops and appropriate regulatory treatment.

However, pursuing FE and 1)SM initiatives is not expected to meet the incremental demand for electricity. [)EC still envisions the need to secure additional generation, as well as cost-effective renewable generation, hut the FE and DSM programs offered hy [)EC will address a significant portion of this need if such programs perform as expected.

EE Savings Variance since last IRP

The EE savings tbrecast of MWh energy is diiièrent from the forecast presented in the 2012 DEC IRP in the following ways:

• The 2013 IRP is based on an updated forecast of DEC’s 5 year planning horizon for the period of 2013-17.

• The 2013 IRP uses analysis performed by Forefront Economics, Inc. to estimate the long-range FE savings based on achievable potential rather than the straight line estimation used by E)EC in the 2012 IRP.

90 ‘[‘heimplementation of these two changes in methodology results in a base case MWh forecast that is higher than that presented in the 2012 [)EC’ IRP, however, the overall shape of the forecast changes froni a straight line expectation in 2012 to a curve that shows a gradual decrease in the amount of incremental achievable MWh beginning in about 2025.

High EE Savings Projection

[)EC also prepared a high Ll savings projection designed to meet the following Energy Efficiency Pertbrmance Targets for five years, as set forth in the December 8, 2011 Settlement Agreement between Environmental Defense Fund, the South Carolina Coastal (onservation League and Southern Alliance for Clean Energy, and Duke Energy Corporation, Progress Energy, Inc., and their public utility subsidiaries Duke Energy Carolinas LLC and Carolina Power & Light C’ompany, d/h/a Progress Energy Carolinas. Inc.

• An annual savings target of’ 1% of the previous year’s retail electricity sales beginning in 2015; and

• A cumulative savings target of 7% of retail electricity sales over the five year lime period of 2014 through 2018.

For the purposes of this IRP, the high FE savings prqjection is being treated as a resource planning sensitivity that will also serve as an aspirational target ft)r fljture FE plans and programs. The high FE savings projections are well beyond the level of savings attained by [)EC in the past and higher than the forecasted savings contained in the new market potential study. The effbrt to meet them will require a substantial expansion of DEC’s current Commission-approved FE portfolio. New programs and measures must he developed, approved by regulators, and implemented within the next few years. More importantly, significantly higher levels of customer participation must he generated. Additionally, flexibility will he required in operating existing programs in order to quickly adapt to changing market conditions, code and standard changes, consumer demands, and emerging technologies.

At this time there is too much uncertainty in the development of new technologies that will impact fttture programs and/or enhancements to existing programs, as well as in the ability to secure high levels of customer participation, to risk using the high FE savings projection in the base assumptions for developing the 2013 IRP. I lowever, the high FE savings forecast was included in the Environmental locus Scenario. DEC expects that as steps are made over time toward actually achieving higher levels of program participation and savings, then the FE savings forecast used for integrated resource planning purposes will continue to he revised in future lRPs to reflect the most realistic projection of EE savings.

9’ Programs Evaluated but Rejected

I)uke Energy Carolinas has not rejected any cost-ettective programs as a result of its EE and l)SM program screening.

Looking to the Future

• Grid Modernization (Smart Grid Impacts) I)uke Energy is pill-suing implementation of grid modernization throughout the enterprise with a vision ot creating a sustainable energy future fbr our customers and our business by being a leader of innovative approaches that will modernize the grid.

DEC is reviewing an Integrated Volt—VARControl (IVVC) project that will better manage the application and operation of voltage regulators (the Volt) and capacitors (the VAR) on the DEC distribution system. In general, the project tends to optimize the operation of these devices, resulting in a “t1atteniig” of the voltage profile across an entire circuit, starting at the substation and continuing out to the farthest endpoint on that circuit. This flattening of the voltage profile is accomplished by automating the substation level voltage regulation and capacitors, line capacitors and line voltage regulators while integrating them into a single control system. Ibis control system continuously monitors and operates the voltage regulators and capacitors to maintain the desired ‘flat” voltage profile. Once the system is operating with a relatively flat voltage profile across an entire circuit, the resulting circuit voltage at the substation can then he operated at a lower overall level. Lowering the circuit voltage at the substation results in an immediate reduction of system loading. Through application of IVVC and reduced system voltage, DEC is thereby reducing load and system demand.

The deployment of an IVVC program tbr DEC is anticipated to take approximately 5 years following project approval. This IVVC program is projected to i-educe future distribution system demand by 0.20% in 2015, 0.4% in 2016, 0.6% in 2017,0.8% in 2018 and 1.00% in 2019 and following years.

92 APPENDIX E: FUEL SUPPLY

[)uke Energy Carolinas’ current fuel usage consists primarily of coal and uranium. Oil and gas have traditionally been used fir peaking generation, hut natural gas has begun to 1ay a more important role in the fuel mix due to lower pricing and the addition of the Buck and Dan River Combined Cycle plants. These additions will further increase the importance of gas to the Company’s generation poiitolio, A brief overview and issues pertaining to each fuel type are discussed below.

Natural Gas Following a tumultuous year (2012) for North American gas producers, 2013 is signaling a return to market stability. Near term prices have recovered from their sub $2/MMBtu lows to settle into the $3.50 - $4.00 range. Inventories are hack in neutral territory, gas directed rig counts remain at 18 year lows and yet, the size of the low cost resource base continues to expand. Looking fbrward, the gas market is expected to remain relatively stable and the improving economic picture will allow the supply / demand balance to tighten and prices to continue to firm at sustainable levels. New gas demand from the power sector is likely to get a small boost between now and 2015 from coal retirements which are tied to the implementation of the Environmental Protection Agency (EPA) MATS rule covering mercury and acid gasses. This increase is expected to he followed by new demand in the industrial and LNG export sectors which both ramp up in the 201 6 — 2020 tirneframe.

The long term fundamental gas price outlook is little changed from the 2012 Ibrecast even though it includes higher overall demand. The North American gas resource picture is a story of unconventional gas production dominating the gas industry. Shale gas now accounts for about 38% of natural gas production today, rising to over hal I by 2019.

The US power sector still represents the largest area of potential new demand, hut growth is expected to be uneven. After absorbing about 8.8 hcfd of new gas demand tied to coal displacements in the power dispatch in 2012, higher gas prices have reversed the trend. Looking forward, direct price competition is expected between gas and coal on the margin. A 2015 bump in gas demand is expecled when EPA’s MATS rule goes into efThct and utilities retire a significant amount of coal (38 GW’s in this outlook).

Coal On average, the 2013 l)uke fundamental outlook fur coal prices is lower than the 2012 outlook, with the exception of Central Appalachian ((‘APP) sourced coal which is higher in the near-term primarily as a result of deterioration in mine productivity. Since 2008, Central Appalachian underground mine productivity (tons per man-hour) has declined by 28%, surfhce mine productivity by 23% this combination equates to roughly a $5 per ton increase in labor costs alone.

93 Coal consumed steam the

Nuclear while Exports in To in portfolio Washington

primarily thereafter. contracting Requirements requirements supplier,

deliveries

volatility. periods have

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or to • Small modular nuclear reactors (SMR) are generally defined as having capabilities of less than 300 MW. In 2012, U.S. Department of Energy (I)OE) solicited bids for companies to participate in a small modular reactor grant program intending to promote the accelerated commercialization of’ SMR tecimologies to help meet the nation’s economic energy security and climate change objectives.” The focus of the grant is the hrst-of-a-kmd engineering associated with NRC design certification and licensing effbrts in order to demonstrate the ability to achieve NRC design certification and licensing to support SMR plant deployment on a domestic site by 2022. The grant was awarded to Babcock & Wilcox (B&W) who will lead the effort in partnership with ‘[VA and Bechtel. It is estimated that this project may lead to the development of “plug and play” type nuclear reactor applications that are about one— third the size of current reactors. These are expected to become commercially available around 2022. Duke will he monitol’ing the progress of the SMR project for potential consideration and evaluation for future resource planning.

• Fuel Cells. although originally envisioned as being a competitor for combustion turbines and central power plants, are now targeted to mostly distributed power generation systems. The size of the distributed generation applications ranges from a few kW to tens of’MW in the long-term. Cost and perfiwmance issues have generally limited their application to niche markets and/or subsidized installations. While a medium level of research and development continues, this technology is not commercially available ft)r utility—scaleapplication.

• Poultry waste and swine waste digesters remain relatively expensive and are often faced with operational and/or permitting challenges. Research, development, and demonstration continue, hut these technologies remain generally too expensive or face obstacles that make them impractical energy choices outside of specific mandates calling ibr use of these technologies.

• Offshore wind, although demonstrated on a utility scale and commercially available, is not a widely applied technology and not easily permitted. This technology remains expensive and has yet to actually he constructed anywhere in the United States. Currently, the Cape Wind project in Massachusetts has been approved with assistance from the ièderal government hut has not begun construction. [he Company is a contributor to the l)OE—sponsorcd C’OWIC’S.

Economic Screening

[he C’ompany screens all technologies using relative dollar per kilowatt-year ($/kW-yr) versus capacity factor screening curves. The screening within each general class (Baseload,

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I0I APPENDIX state could generation description

Legislative regulations, Air Duke VERC, Duke As C:arolinas program, NO General by

‘[‘he 2012 in

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approximately

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charts

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ENVIRONMENTAL

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facilities.

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legislation,

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COMPLIANCE

Interstate

existing

Smokestacks

some Duke

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102

actions.

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with

jurisdiction

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ol’

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generation

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in Chart C-i DEC NO Emssions

Duke Energy Carolinas Coal-Fired Plants Annual Nitrogen Oxides Emissions (tons) 180.000

160.000

140.000 A DSSIDi-S.

120.000 I..ci.aI

100.000

80.000

60.000

40.000

20.000

0 1995199619971998199920002001 200220032004200520062007200820920020112012 Overall reduction of 89% from 1997 to 2012 attributed to controls to meet Federal Requirements and NC Clean Air Legislation.

Chart C-2 I)EC 2SO Emissions

Duke Energy Carolinas Coal-Fired Plants Annual Sulfur Dioxide Emissions (tons) 350.000

300,000

250.000

200.000

150.000

100.000

50.000

1995199619971998199920002001 2002200320042005200620072008200920102011 2012

95 % Reduction from 2000 to 2012 attributed to scrubbers installed to meet NC Clean Air Legislation.

103

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in I Mercury and Air Toxics Standard (‘M4TS)

In February 2008, the United States Court of Appeals for the 1)istrict of Columbia issued its opinion, vacating the Clean Air Mercury Rule (CAMR). EPA announced a proposed Utility Boiler Maximum Achievable Control Technology (MACI’) rule in March 2011 to replace the CAMR. The EPA published the final rule, known as the MATS, in the Federal Register on [:eL,rtiaiy 16, 2012, MATS regulates Hazardous Air Pollutants (HAP) and establishes unit—level emission limits or mercury, acid gases, and non—mercurymetals. and sets work practice standards fbr organics for coal and oil-lired electric generating units. Compliance with the emission limits will be required by April 16, 2015. Permitting authorities have the discretion to grant up to a 1-year compliance extension, on a case-by-case basis, to sources that are unable to install emission controls heibre the compliance deacllinc.

Numerous petitions for review of the final MATS rule have been filed with the United States Court of Appeals for the District of Columbia. Briefing in the case has been completed. Oral arguments have not been scheduled. A court decision in the case is not likely until the first quarter of 2014. Duke Energy Carolinas cannot predict the outcome of the litigation or how it might affect the MATS requirements as they apply to operations.

Based on the emission limits established by the MATS rule, compliance with the MA’FS rule has driven several tiriit retirements and will drive the retirement or fuel conversion of several more non- scrubbed coal-fired generating units in the Carolinas by April 2015. Compliance with MATS will also require various changes to units that have had emission controls added over the last several years to meet the emission requirements of the NC CSA.

National Ambient Air Quality Standards (NAAQS)

8 Hour Ozone Standard

In March 2008, EPA revised the 8 Flour Ozone Standard by lowering it from 84 to 75 parts per billion (ppb). In September of 2009, EPA announced a decision to reconsider the 75 pph standard in response to a court challenge from environmental groups and their own belief’ that a lower standard was us1ified. However, EPA announced in September 2011 that it would retain the 75 pph primary standard until it is reconsidered under the next 5-year review cycle. It could he mid- 2014 hethre the EPA proposes a revision to the 75 pph standard and mid—2015heibre it finalizes a new standard unless ongoing legal action results in a court ordered schedule requiring the Agency to act sooner.

On May 21, 2012 EPA finalized the area designations for the 2008 75 ppb 8-hour ozone standard. The Charlotte area, the only area in North Carolina designated nonattainment, is now classified as a “marginal” nonattainment area, which establishes l)ecemher 31, 2015 as its attainment date. For

105 marginal nonattainmentareas, states are not required to prepare an attainment demonstration. EPA in its final rule states that it perlbrmed an analysis that indicates that the majority of areas classified as marginal will be able to attain the 75 pph standard in 2015 due to fderal and state emission reduction programs already in place. If the Charlotte area’s air quality does not qualit’ it to be reclassified as attainment, the area can still qualify for the first of two possible one—yearextensions of the attainment date if it has no more than one exceedance of the standard in 201 5. Alternatively, should the Charlotte area not attain the standard by its attainment date and not qualify fbr all extension, it could be humped up to the next higher classification, which fbr Charlotte would he moderate. 1’hiswould require North Carolina to develop an attainment SFP to bring the Charlotte area into attainment with the standard by I.)ecember 31, 2018.

2SO Standards

On June 22, 2010 EPA established a 75 pph I-hour 2SO NAAQS and revoked the annual and 24- hour 2SO standards. EPA finalized initial nonattamment area designations in ‘113[)2013. No areas ill the Carolinas were designated nonattainment.

On February 6, 2013 the EPA released a document that updated its strategy for addressing all areas that it did not initially designate as nonattamment ill July 2013. ‘tile document indicated that EPA will allow states to use modeling or monitoring to evaluate the impact of large 2SO emitting sources relative to the 75 pph standard. The document also laid out a schedule k)r implementing the standard.

‘tile EPA plans on undertaking notice and comment rulemaking to codify the implementation requirements fhr the 75 pph standard. ‘[here is no schedule fbr EPA to propose or finalize the rulemaking, and the outcome of the rulemaking could be different from what EPA put forth in its February 6, 2013 document.

Particulate Mailer (PM) Staiidard

In September 2006, the EPA announced its decision to revise the 25PM NAAQS standard. ‘l’he daily standard was reduced from 65 3ug/in (micrograms per cubic meter) to 35 3ug/m The annual standard remained at 15 .3ug/m . EPA finalized designations ft)r the 2006 daily standard in October 2009, which did not include any nonattainment areas in the I)uke Energy Carolinas service territory. In February 2009, the D.C Circuit unanimously remanded to EPA the Agency’s decision to retain the annual 15 3ug/m primary s NAAQS and to equate the secondary PM NAAQS with the primary NAAQS. 2PM 2 5 EPA began undertaking new rulemaking to revise the standards consistent with the Court’s decision.

106 On designations

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This Gl-lGs.

coal

by

nonattainment

107 permitting emission

MWh

standard might

required

greenhouse

2011

that standard.

major

cycle

201 standard

June

to

what

Ilie

The NSPS

unit

rule

additional

PSD

8, of’

undertake

has lowered

facilities.

analysis

the

rule —

In

reduction

proposed

units.

1,

could stationary

with

guidelines

has to sets electricity

might

2013

authority.

for

May

directed

CAIR 2015.

permitting

for

are

develop

standards

gases.

directly

‘lhe

new the

the

meet

areas

new

not

the

Flie

and

2010,

SO2

air

constitute

a

and

Gl-lG initial

emission

in

electric

source

modification

known.

EPA

annual EPA

natural for

proposed generation.

The

the

Once the

the

quality

or

will

SO2

Since

the

driven

established requirements

the

existing

NOx NSPS

regulations proposed

application

attainment

Tailoring

to

plans

NC

and is

be

utility EPA

EPA

PM75

gas

re-propose

BACI’,

thresholds it

subject

data

emission required

emission

NSPS

CSA.

applies is NOx

and

electric

The

finalizes to that

finalized

steam not

standard standard

to

Rule

by

new

that date

finalize

of to

emissions

for

the

proposal

triggers

is known

It

make

only

EPA

Prevention

the to

BACT

is generating

an

to

reduction

generating reduction

will went

coal-fired CO2

in

potential

emission

unclear

what

submit

output-

75,000

rule

to

is

2020.

to

final

apply

in il area

PSD

with

new will

into

was

12

for

to

or by

is its carbon

establishing prospects It Water CWA

modifications Federal EPA The entrainment approach

withdrawn

The lakes, facilities November

plans,

Within intakes Steam requirements.

guidelines. In Administrator based (ELGs).

the EPA options regulatory

streams. proposed

is

September

proposed

highly

EPA

most

published

316(b)

by

tax

reservoirs,

Quality

etc,

on Electric

regulations

the

to

vary

with

the

establishes

lhr

The

including has will

recent

the

revisions

for comply

for

4, a

proposed options

unlikely

and

extended

I’he

cooling

carbon

enactment

in fbr

a

agreed

rule

2013. proposal

he

cooling

capability its

signed

some

and

Effluent design

stringency 2009,

steam existing

advances

passed

EPA

proposed

estuaries,

establishes

in

with

for

wastewater

By-product

tax

are aquatic

that

rule,

to

facilities

Section

IF

Water

date

the

purposes.

settlement intake

the

electric EPA

was

are

issue

by the

Guidelines o1

focused the

Facilities

of

legislation

proposed

EPA

of’

and rule,

one

rule the

highly

published any

oceans,

rule

pi-otection

Intake the

impingement

flow

announced

September

a

3

mortality

would

cost, effluent

113th 16(b)

on prelèrred final did

from

of

federal

best

Issues

is

primarily

agreement

to uncertain.

of’2

April

which

not

revisions Structures finalized

and

or

minimize

rule

mandating

of Congress

air

technology he

in

million

requirements

limitation provide

other

reduction the

propose 20, the

legislation

20,

pollution

due

by

plans

approach four

reqLnrements

on

Clean

2011. l’ederal

201

May

now

as

to

in

U.S.

are

impingement

gallons coal which

a

3.

the

reductions to

proposed,

mid—late

revisions O8

compliance

guidelines

available.

22, calls requirements

Water

listed

control

I.

waters

and

generating revise mandating

Steam

Register

nder

and

began

2014.

per

tbr

as

three

Act could

new

the

2014.

or

day

equipment

that

Electric

preferred initial the

the

in on

and

are

on

develop

On The may

current

deadline

on-site

alternatives.

(mgd)

GHG

January

EPA units,

reductions he

due

June technology—based, steam utilize

entrainment

April

If

EPA submittals,

necessitate

required

Effluent

to

required,

to

by

revision

or

7, emissions facility new

but

and

for

both

has at

electi-ic 3,

finalize

2013

19.

more

EPA.

2013.

some

standards

ash least

meeting

in

proposed

2013,

as

fish

Limitations

The

of

additions

with

cooling station

of

from

0110 modifications

transport

The

early

aquatic

25%

the

revisions eflluent or

the

Beyond

impingement

EPA’s

comments

the

in

the

rivers, establishing

eight

316(b)

consent

tbr

emissions

eight

details,

as that

of’

water

EPA

entrainment

for

organisms.

seven

water.

Guidelines

late

the

2014

preferred

regulatory

limitation

limits

would

streams,

existing

different

rule

intake

decree,

Acting

to

water

due 201

study

waste

the

and

or

The the

are

by

a

6.

be

to applicable to all steam electric generating units, including natural gas and nuclear—fueledgenerating fticilities. After the final rulemaking, effluent limitation guideline requirements will he included in a stations National Pollutant I)ischarge Elimination System (NPDFS) permit renewals. Portions of the rule would he implemented immediately after the efièctive date of the rule upon the renewal of’ wastewater discharge permits, while other portions of’ the rule will he implemented upon the renewal of the wastewater discharge permits after July, 2017. EPA expects that all facilities will he in compliance ith the rule by July 2022. ‘Ilie deadline to comply will depend upon each station’s permit renewal schedule. coal combustion Residuals

Following Tennessee Valley Authoritys (‘l’VA) Kingston ash (like failure in [)ecemher 2008, EPA began to assess the integrity of’ash dikes nationwide and to begin developing a rule to manage coal combustion residuals (CCR5). CCRs primarily include fly ash, bottom ash and Flue Gas Desulfurization (FOE)) byproducts (gypsum). Since the 2008 TVA dike failure, numerous ash dike inspections have been completed by EPA and an enormous amount of’input has been received by EPA as it developed proposed regulations. In June 2010, EPA published its proposed rule regarding CCRs. The proposed rule otièrs two options: 1) a hazardous waste classification under Resource Conservation Recoveiy Act (RCRA) Subtitle C; and 2) a non-hazardous waste classitication under RCRA Subtitle D, along with dam safety and alternative rules. l3oth options would require strict new requirements regarding the handling, disposal and potential re—useability of CCRs. The proposal will likely result in more conversions to dry handling of ash, more landfills, the closing 01’ lining of existing ash ponds and the addition of new wastewater treatment systems. Final regulations are not expected to he issued by EPA until 2014 or later. EPA’s regulatory classification of CCRs as hazardous or non-hazardous will he critical in developing plans for handling CCRs. Ilowever, under either option of the proposed rule, the impact to I)uke Energy Carolinas is likely to be significant. I3ased on a 2014 final rule date, compliance with new regulations is generally expected to begin around 2019.

109 APPFNDIX H: NON-UTILITY CENFRATION AND WHOLESALE

ibis appendix contains holesale sales contracts, firm wholesale purchased power contracts and non—utilitygeneration contracts.

110 Table 11.-i Wholesale Sales Contracts

Wholesale Contracts Commitment (MW)

2016 2017 2018 2019 2020 2021 2022 Customer Product Term 2013 2014 2015 177 180 212 215 217 220 Concord Partial Requirements 2009-2018 167 169 172 174 12 12 12 12 12 13 13 Dallas Partial Requirements 2009-2028 11 11 11 2 2 2 2 2 2 2 1)ue West Partial Requirements 2009-2018 2 2 2 19 19 19 20 20 20 21 21 Forest City Partial Requirements 2009-2028 18 18 55 56 57 58 58 59 60 Greenwood Full Requirements 2010-2018 53 53 54 9 9 9 9 9 9 10 10 I liohlands Full Requirements 2010-2029 9 9 22 22 22 30 30 30 31 Kings Mountain Partial Requirements 2009-20! 8 21 21 21 51 52 53 54 75 76 77 78 I ockhart Partial Requirements 2009-201 8 50 50 2 2 2 3 3 3 3 Prosperit Partial Requirtments 2009-2028 2 2 2 6 6 6 6 6 6 6 6 Western Carolina Full Requirements 2010-2021 6 6

233 237 241 245 249 253 257 261 Blue Ridge FMC Full Requirements 2010-2031 225 229 509 649 793 900 918 936 953 Central Partial Requirements 2013-2030 120 244 374 23 24 24 24 25 25 25 26 I Iavwood I MC Full Requirements 2009-2021 23 23 72 72 72 72 72 72 72 72 NCFMC Fixed load Shape 2009-2038 72 72 116 116 116 116 116 116 116 NCEMC Baestand 1985-2043 95 116 116 89 90 92 93 94 96 97 99 Piedmont EMC Full Requirements 2010-2031 87 88 47 47 47 47 47 47 47 47 PMPA Baekstand 2014-2020 0 47 204 208 212 217 221 226 230 235 Rutherford FMC Partial Requirements 2010-2031 185 189 Table H-2 Firm Wholesale Purchased Power Contracts

Volume of Primary Summer Purchases Purchased Fuel Calacity Capacity (MWh) Power Contract jy (MW) Designation Location I’errn Jul 12-Jun 13

Cherokee County Gas 86 Peaking (iafThey SC 12/31/2020 650 627 Cogeneration Partners,_LLC_I

SEPA Ilydro 8 Peaking 12/31/2021 12,883 system

Note: The capacities shown are deIi ered to the [)EC’system and may differ from the contracted amount. Renewahies purchases are listed in the NC REPS Compliance Plan in the Attachment to this IRP.

112 Table ‘Facility ‘Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility 4 5 6 2 1 9 8 3 11 7 10 Facility 12 14 13 21 20 17 16 15 19 18 25 24 23 22 29 32 31 27 26 34 28

41 35 30 H-3 33 40 39 42 37 36 44 43 38 46 45 48 47 50 49 51 54 53 56 55 52 Name

Non-Utility City/County NORTH

Generation Mecklenburg Mecklenburg Meclclenburg Mecklenburg Mount Mecklenburg Rockingham Durham- Henderson Henderson Henderson Henderson Rutherford Henderson Henderson Burlington Cleveland Alamance Alamance Cherokee Cleveland Cleveland Charlotte Alamance Alamance Alamance Alamance Charlotte Catawba Catawba Catawba Catawba Cabarrus Guilford Guilford Durham Orange Orange Guilford Orange Forsyth CAROUNA Lincoln Gaston Durham Orange Orange Orange Gaston Orange Iredell Iredell Macon Swain Holly Surry Polk NE State — NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC GENERATORS NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC

North Primary

Carolina Hydroelectric Hydroelectric Hydroelectric 113 Fuel (As of Type Other* Other* Other* Other* Biogas July Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Wind Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar 20131 Capacity (AC 20000.00 1750.00 4800.00 3500.00 5000.00 1600.00 4000.00 640,00 240.00 324.00 124.00 75.00 10.25 95.00 10.00 10.00 10.00 10.00 28.80 30.00 kW) 30.00 40.85 20.43 864 2.80 7.10 4.00 5.00 5.00 2.10 1.72 9.60 4.00 5.25 2.58 6.00 9.46 4.52 3.60 4.00 1.90 3.00 4.00 3.25 3.85 9.00 0.74 5.16 2.21 9.80 6.08 3.00 4.00 2.45 NA NA Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Designation 8aseload Baseload Baseload Baseload Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility

Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility94 Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility

57 53 59 61 60 64 62 65 63 67 66 Facility 68 69 72 70 71 75 76 74 73 78 80 79 77 81 82 83 84 86 87 85 89 91 88 92 90 95 93 97 96 98 99

100 102 103 101 104 108 107 103 106 110 112 109 111

Name

City/County

BessemerCitv

Mecklenburg

Mecklenburg

Mecklenburg

Mecklenburg Mecklenburg

Tobaccoville

Henderson

Mount

Greensboro Greensboro

Alamance

Alamance

Cleveland

Alamance Mount Mount Burlington Charlotte

HawRiver

Catawba

Charlotte Charlotte Durham

Ourham

Jackson

Durham Belmont Belmont Belmont

Orange Gastonia Orange

Orange Orange

Forsyth Durham Orange Orange

Orange

Mebane

Orange

Iredell

Gaston

Graham

Stokes

Hickory

Hickory

Swain

Surry Union Union

Elkin

Eden

Holly

RTP

Airy Airy

State

NC NC NC

NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC

NC NC NC NC NC

Primary

Hydroelectric

Fuel

114

Landfill

Type

Other5

Other5

Other5 Other5 Other5 Other5 Other* Other* Other* Other*

Others

Other* Other* Other* Others Others Other* Other* Others Other Solar Other* Solar Other Solar Other* Solar Solar Solar Solar Solar Solar Solar Solar

Solar Solar Solar Solar Solar Solar Solar Solar Solar

Solar Solar Solar

Solar Solar Solar Solar Solar

Solar

Solar Solar

Gas

Capacity

(AC

1250.00

4000.00

440.00

1300.00

400.00 2250.00

1200.00 1590.00 1700.00 2000.00

1500.00 1750.00

500.00 350.00 100.00 440.00 350.00 550.00 600.00 260.82

800.00 100.00 16.40 859.00 800.00

600.00 800.00 kW) 750.00 15.00 210.00

378 3.00 700 6.45

5.00 2.00 6.00 5.00

4.00 3.00 4.16 3.00 4.88 0.74

1.85 3.00 4.94 2.40

3.00 7.50 8.00 N/A 2.63 3.00 6.00

8.00

Intermediate/Peak

Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak Designation Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak

Saseload

Baseload Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility

Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility

113 114 Facility 116 115 117 118 119 121 120 122 123 125 124 126 128 127 129 130 131 133 132 134 135

136 137 138 140 139 141 142 143

144 145 146 14.8 147 149 150

151 152 153 155 154 156 158 157 159 160 162 161 163 164 167 168 165 166

Name

City/County

Mecklenburg

Rockingham Mecklenburg

Transylvania

Mecklenburg

Mecklenburg

Rutherford

Henderson

Henderson

Henderson Cleveland

Henderson

Charlotte

Cleveland

Cleveland

Cabarrus

Lexington Lexington Guilford

Catawba

Durham Caldwell Durham Davidson

Guilford Durham Durham

Durham Forsyth Orange orange

Forsyth Orange

Guilford Orange

Jackson

Forsyth Gaston Rowan Durham Durham Orange

Orange

Stokes Rowan Forsyth Iredell Stokes

Rowan Rowan Davie

Wake Wake

Rowan Surry

Union

State

NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC NC

Primary

Hydroelectric

Fuel 115

Landfill Landfill

Landfill

Type

Other*

Others Other*

Wind

Solar Solar

Solar

Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Wind Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Wind Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar Solar

Solar Solar Solar Solar Solar Solar Gas Gas

Gas

Capacity

(AC

11500.00

1600.00 1600.00

420.00

169.00 1600.00

30.00

300.00 750.00 10.00

10.00

kW)

4.00 0.86

3.00

94.08

3.01 9.90

4.00 5.76 2.82 72.00 7.60 30.00 6.08 30.00 4.94 3.44 2.28 2.58 1.72 3.60

4.00 3.00 4.58 5.16 1.44 6.02 4.30

3.60 1.20 6.00 5.16 0.70 2.58 1.12 2.28 7.60

6.00 5.46

3.50 3.00 1.00 2.50 0.70

4.00 2.50

Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Designation

Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak Intermediate/Peak

Baseload Baseload

Baseload

Baseload FacilityName City/County State PrimaryFuelType Capacity(ACkW) Designation

Facility 169 Jackson NC Solar 3.60 Intermediate/Peak Facility 170 GuHford NC Solar 6.72 Intermediate/Peak Facility 171 Cabarrus NC Solar 3.44 Intermediate/Peak Facility 172 Jackson NC Solar 4.41 Intermediate/Peak Facility 173 Wilkes NC Solar 2.76 Intermediate/Peak Facility 174 Forsyth NC Solar 2.23 Intermediate/Peak Facility 175 Mecklenburg NC Solar 2.15 Intermediate/Peak

Facility 176 Rockingharn NC - Solar 5000.00 Intermediate/Peak Facility 177 Orange NC Solar 3.87 Intermediate/Peak Facility 178 Mecklenburg NC Solar 5.00 Intermediate/Peak Facility 179 Cleveland NC Solar 4000.00 Intermediate/Peak Facility 180 NC Solar 4.30 Intermediate/Peak Facility 181 Mecklenburg NC Solar 4.00 Intermediate/Peak Facility 182 Guilford NC Solar 2.58 Intermediate/Peak Facility 183 Iredell NC Solar 6.02 Intermediate/Peak Facility 184 Macon NC Solar 4.50 Intermediate/Peak Facility 185 Alexander NC Solar 0.70 Intermediate/Peak Facility 186 Orange NC Solar 3.00 Intermediate/Peak Facility 187 Rockingham NC Solar 1.60 Intermediate/Peak Facility 188 Burke NC Solar 3.00 Intermediate/Peak Facility 189 Alamance NC Solar 3.00 Intermediate/Peak Facility 190 Catawba NC Solar 2.50 Intermediate/Peak Facility 191 Polk NC Solar 3.60 Intermediate/Peak Facility 192 Rockingham NC Solar 3.87 Intermediate/Peak Facility 193 Guilford NC Solar 3.00 Intermediate/Peak Facility 194 Forsyth NC Solar 10.56 Intermediate/Peak Facility 195 Durham NC Other* 5500.00 Intermediate/Peak Facility 196 Durham NC Other* 13400.00 Intermediate/Peak Facility 197 Durham NC Other* 2250.00 Intermediate/Peak Facility 198 Orange NC Solar 10.68 Intermediate/Peak Facility 199 Davidson NC Engine Dynamometer N/A Intermediate/Peak Facility200 Cherokee NC Solar 13.72 Intermediate/Peak Facility201 NC Solar 5.16 Intermediate/Peak Facility202 Orange NC Solar 4.00 Intermediate/Peak Facility203 Macon NC Solar 8.60 Intermediate/Peak Facility204 Orange NC Solar 6.00 Intermediate/Peak Facility205 Mecklenburg NC Solar 3.00 Intermediate/Peak Facility 206 Mecklenburg NC Solar 4.00 Intermediate/Peak Facility 207 Orange NC Solar 3.00 Intermediate/Peak Facility 208 Orange NC Solar 3.00 Intermediate/Peak Facility 209 Durham NC Solar 4.00 Intermediate/Peak Facility 210 Mecklenburg NC Solar 4.58 Intermediate/Peak Facility 211 Alamance NC Solar 5.00 Intermediate/Peak Facility 212 Guilford NC Solar 4.80 Intermediate/Peak Facility 213 McDowell NC Solar 18.00 Intermediate/Peal’ Facility 214 Caldwell NC Solar 1.40 Intermediate/Peak Facility 215 Durham NC Solar 75.00 Intermediate/Peak Facility 216 Durham NC Solar 52.90 Intermediate/Peal’ Facility 217 NC Solar 50.00 Intermediate/Peak Facility 218 Durham NC Solar 30.00 Intermediate/Peak Facility 219 Monroe NC Other* 400.00 Intermediate/Peak Facility 220 Union NC Solar 4.00 Intermediate/Peak Facility 221 Durham NC Solar 2.16 Intermediate/Peak Facility 222 Guilford NC Solar 5.00 Intermediate/Peak Facility 223 Durham NC Solar 5.00 Intermediate/Peak Facility 224 Wake NC Solar 2.82 Intermediate/Peak

116 Facility Name City/County State Primary Fuel Type Capacity (ACkW) Designation

Facility 225 Henderson NC Solar - 4.90 Intermediate/Peak Facty 226 Mecklenburg NC Solar 2.85 Intermediate/Peak Facility 227 Charlotte NC 0ther 10000.00 Intermediate/Peak Facility 228 Guilford NC Solar 14.40 Intermediate/Peak Facilty 229 Forsyth NC So ar 2.38 Intermediate/Peak Facity 230 McDowell NC Solar 4.00 Intermediate/Peak Facility 231 Alamance NC Solar 2.70 Intermediate/Peak Facility 232 Charlotte NC Other* 300.00 Intermediate/Peak Facility 233 Burke NC Solar 24.00 Intermediate/Peak Facility 234 Winston-Salem NC Other* 1800.00 Intermediate/Peak Facility 235 Forsyth NC Solar 2.30 Intermediate/Peak Faclity 236 Catawba NC Solar 4.50 Intermediate/Peak Facility 237 Mecklenburg NC Solar 11.77 Intermediate/Peak Facility 238 Orange NC Solar 5.00 Intermediate/Peak Faculty 239 Orange NC Solar 5.00 Intermediate/Peak Facility 240 Rowan NC Solar 82.00 Intermediate/Peak Facility 241 Mecklenburg NC Solar 8.00 Intermediate/Peak Facility 242 Henderson NC Solar 5.00 Intermediate/Peak Facility 243 Guilford NC Solar 1.75 Intermediate/Peak Facility 244 Transylvania NC Solar 2.80 Intermediate/Peak Facility 245 Polk NC Solar 3.00 Intermediate/Peak FacIlity 246 Surrv NC Solar 10.00 Intermediate/Peak Facility 247 Jackson NC Solar 2.58 Intermediate/Peak Facility 24.8 Cabarrus NC Landfill Gas 5000.00 Baseload Facility 249 Gaston NC Landfill Gas 4800.00 Baseload Facility 250 Guilford NC Solar 2.16 Intermediate/Peak Facility 251 Durham NC Solar 700.00 Intermediate/Peak Facility 252 Greensboro NC Other* 125.00 Intermediate/Peak Facility 253 Guilford NC Solar 0.86 Intermediate/Peak Facility 254 Orange NC Solar 6.00 Intermediate/Peak Facility 255 Burke NC Solar 6.00 Intermediate/Peak Facility 256 Henderson NC Solar 2.82 Intermediate/Peak Faclity 257 Cabarrus NC Solar 4.30 Intermediate/Peak Facility 258 Polk NC Solar 2.14 Intermediate/Peak Facility 259 Mecklenburg NC Solar 1.96 Intermediate/Peak Facility 260 Wilkes NC Solar 2.58 Intermediate/Peak Facility 261 Swain NC Solar 7.00 Intermediate/Peak Facility 262 McDowell NC Solar 2.50 Intermediate/Peak Facility 263 Guilford NC Solar 4.16 Intermediate/Peak Facility 264 Orange NC Solar 1.64 Intermediate/Peak Facility 255 Durham NC Solar 307.43 Intermediate/Peak Facility 266 Catawba NC Solar 1.40 Intermediate/Peak IFacility 267 Mecklenburg NC Soar 1.72 Intermediate/Peak Facility 268 Polk NC Solar 2.15 Intermediate/Peak Facility 269 Guilford NC Solar 50.00 Intermediate/Peak Facility 270 Macon NC Solar 4.30 Intermediate/Peak Facility 271 Lincoln NC Solar 0.70 Intermediate/Peak Facility 272 Cabarrus NC Solar 3.01 Intermediate/Peak Facility 273 Forsyth NC Solar 8.00 Intermediate/Peak Facility 274 Rutherford NC Solar 2.58 Intermediate/Peak Facility 275 Orange NC Solar 4.20 Intermediate/Peak Facility 276 Orange NC Solar 3.15 Intermediate/Peak Facility 277 Alexander NC Hydroelectric 365.00 Baseload Facility 278 Forsyth NC Solar 14.80 Intermediate/Peak Facility 279 Gaston NC Hydroelectric 820.00 Baseload Facility 280 Guilford NC Solar 7.50 Intermediate/Peak

117 Facility Name City/County State Primary Fuel Type Capacity (ACkW) Designation

Facility 281 Wilkes NC Solar 4.00 Intermediate/Peak Facility 282 Cabarrus NC Solar 5.20 Intermediate/Peak Facility 283 Alamance NC Hydroelectric 1500.00 Baseload Facility 284 Alamance NC Solar 2.00 Intermediate/Peak Facility 285 Durham NC Solar 3.01 Intermediate/Peak Facility 286 Orange NC Solar 3.30 Intermediate/Peak Facility 287 Orange NC Solar 7.00 Intermediate/Peak Facility 288 Mecklenburg NC Engine Dynamometer N/A Intermediate/Peak Facility 289 Guilford NC Solar 108.00 Intermediate/Peak Facility 290 Mecklenburg NC Solar 2.15 Intermediate/Peak Facility 291 Davidson NC Solar 1.29 Intermediate/Peak Facility 292 Durham NC Solar 3.00 Intermediate/Peak Facility 293 Alamance NC Solar 4.00 Intermediate/Peak Facility 294 Lincoln NC Solar 2.15 Intermediate/Peak Facility 295 Orange NC Solar 3.00 Intermediate/Peak Facility 296 Research Triangle Park NC Other* 10900.00 Intermediate/Peak Facility 297 Mecklenburp NC Solar 790.00 Intermediate/Peak Facility 298 Mecklenburg NC Solar 3.60 Intermediate/Peak Facility 299 Hickory NC Other* 1040.00 Intermediate/Peak Facility 300 Rockingham NC Hydroelectric 500.00 Baseload Facility 301 Lincoln NC Solar 10.00 Intermediate/Peak Facility 302 Henderson NC Solar 6.00 Intermediate/Peak Facility 303 Henderson NC Solar 6.00 Intermediate/Peak Facility 304 Orange NC Solar 9.17 Intermediate/Peak Facility 305 Orange NC Solar 5.00 Intermediate/Peak Facility 306 Mecklenburg NC Solar 5.00 Intermediate/Peak Facility 307 Polk NC Solar 5.16 Intermediate/Peak Facility 308 Surrv NC Solar 12.26 Intermediate/Peak Facility 309 Mecklenburg NC Solar 4.00 Intermediate/Peak Facility 310 Durham NC Solar 3.60 Intermediate/Peak Facility 311 Mecklenburg NC Solar 4.00 Intermediate/Peak Facility 312 Guilford NC Solar 2.50 Intermediate/Peak Facility 313 Macon NC Solar 3.00 Intermediate/Peak Facility 314 Mecklenburg NC Solar 1.75 Intermediate/Peak Facility 315 Stokes NC Solar 2.58 Intermediate/Peak Facility 316 Polk NC Solar 6.65 Intermediate/Peak Facility 317 Alamance NC Solar 2.00 Intermediate/Peak Facility 318 Alamance NC Solar 4.90 Intermediate/Peak Facility 319 Durham NC Solar 2.21 Intermediate/Peak Facility 320 Mecklenburg NC Solar 1.40 Intermediate/Peak Facility 321 Rockingham NC Solar 0.76 Intermediate/Peak Facility 322 Rockingham NC Solar 90.00 Intermediate/Peak Facility 323 Jackson NC Solar 2.58 Intermediate/Peak Facility 324 Rutherford NC Solar 4.18 Intermediate/Peak Facility 325 Durham- NE NC Solar 2.21 Intermediate/Peak Facility 326 Iredell NC Solar 7.96 Intermediate/Peak Facility 327 Wilkes NC Solar 4.20 Intermediate/Peak Facility 328 Transylvania NC Solar 0.70 Intermediate/Peak Facility 329 Henderson NC Solar 4.00 Intermediate/Peak Facility 330 Durham NC Solar 2.48 Intermediate/Peak Facility 331 Durham NC Solar 1.25 Intermediate/Peak Facility 332 NC Solar 3.23 Intermediate/Peak Facility 333 Orange NC Solar 6.45 Intermediate/Peak Facility 334 NC Solar 3.60 Intermediate/Peak Facility 335 Alamance NC Solar 2.00 Intermediate/Peak Facility 336 Jackson NC Solar 3.00 Intermediate/Peak

118 Facility Name City/County State Primary Fuel Type Capacity (ACkW) Designation

Facility 337 Orange NC Solar 4.00 Intermediate/Peak Facility 338 Durham NC Solar 3.00 Intermedate/Peak Facility 339 NC Solar 2.58 Intermediate/Peak Facility 340 Alamance NC Solar 324 Intermediate/Peak Facility 341 Rowan NC Solar 4.00 lntermedate/Peak Facility 342 Cherokee NC Solar 7.60 Intermediate/Peak Facility 343 Forsyth NC Solar 3.99 Intermediate/Peak Facility 344 Wake NC Solar 2.50 Intermediate/Peak Facility 345 Cabarrus NC Solar 9.80 Intermediate/Peak Facility 346 Henderson NC Solar 4.00 Intermediate/Peak Facility 347 Guilford NC Solar 4.00 Intermediate/Peak Facility 348 Orange NC Solar 9,80 Intermediate/Peak Fac ity 349 Orange NC Solar 4.00 Intermediate/Peak Facilty 350 Yadkin NC Solar 4.00 Intermediate/Peak Facility 351 Cleveland NC Wind 1.20 Intermediate/Peak Facility 352 Durham NC Solar 3.60 Intermediate/Peak Facility 353 Mecklenburg NC Solar 3.04 Intermediate/Peak Facility 354 Durham NC Solar 3.44 Intermediate/Peal’ Facility 355 Alamance NC Solar 2.00 Intermediate/Peak Facility 356 Durham NC Solar 2.82 Intermediate/Peak Facility 357 Randolph NC Solar 2.00 Intermediate/Peak Facility 358 Gui’ford NC Solar 2.00 Intermediate/Peak Facility 359 Forsyth NC Solar 2.85 Intermediate/Peak Facility 360 Henderson NC Solar 6.45 Intermediate/Peak Facility 361 Forsyth NC Solar 2.85 Intermediate/Peak Facility 362 Henderson NC Solar 10.00 Intermediate/Peak Facility 363 Orange NC Solar 7.80 Intermediate/Peak Facility 364 Polk NC Solar 4.32 Intermediate/Peak Facility 365 Henderson NC Solar 7.31 Intermediate/Peak Facility 366 Union NC Solar 3.00 Intermediate/Peak Facility 367 Henderson NC Solar 2.58 Intermediate/Peak Facility 368 Iredell NC Solar 3.3 Intermediate/Peak Facility 369 Forsyth NC Solar 6.ct Intermediate/Peak Facility 370 Cabarrus NC Solar 4.30 Intermediate/Peak Facility 371 Cabarrus NC Solar 9.00 Intermediate/Peak Facility 372 Wilkes NC Solar 4.73 Intermediate/Peak Facility 373 Catawba NC Solar 15.20 Intermediate/Peak Facility 374 Catawba NC Solar 6.00 Intermediate/Peak Facility 375 Durham NC Solar 6.00 Intermediate/Peak Facility 376 McDowell NC Solar 0.76 Intermediate/Peak Facility377 Forsyth NC Solar 5.00 Intermediate/Peak Facility 378 Rutherfordton NC Solar 0.86 Intermediate/Peak Faciity 379 Stokes NC Solar 4.30 Intermediate/Peak Fachity 380 Mecklenburg NC Solar 5.00 Intermediate/Peak Facility 381 Orange NC Solar 1.20 Intermediate/Peak Facility 382 Henderson NC Solar 2.28 Intermediate/Peak Facility 383 Rockingham NC Solar 4.30 Intermediate/Peak Facility 384 Burke NC Solar 2.00 Intermediate/Peak Facility 383 orange NC Solar 2.58 Intermediate/Peak Facility 386 McDowell NC Solar 3.00 Intermediate/Peak Facility 387 Stokes NC Solar 5. Intermediate/Peak Facility 388 Durham NC Solar 3.25 Intermediate/Peal’ Facility 389 Orange NC Solar 2.00 Intermediate/Peak Facility 390 Macon NC Solar 1.44 Intermediate/Peak Facility 391 Macon NC Wind 1.00 Intermediate/Peak Facility 392 lredell NC Solar 4.00 Intermediate/Peak

119 Facility Name City/County State Primary Fuel Type Capacity (ACkW) Designation

Facility 393 Surry NC Solar 4.60 !nterrnedate/Peak Facility 394 Hickory NC Other 500.00 Intermediate/Peak Facility 395 Mecklenburg NC Solar 9.00 Intermediate/Peak Facility 396 Charlotte NC Other* 200.00 Intermediate/Peak Facility 397 Durham NC Other* 1000.00 Intermediate/Peak Facility 398 Cherokee NC Solar 3.01 Intermediate/Peak Facility 399 McDowell NC Solar 3.57 Intermediate/Peak Facility400 Burke NC Solar 2.58 Intermediate/Peak Facility 401 Durham NC Solar 2.50 Intermediate/Peak Facility 402 Durham NC Solar 7.00 Intermediate/Peak Facility 403 Guilford NC Solar 3.68 Intermediate/Peak Facility4o4 Rowan NC Solar 2.00 Intermediate/Peak Facility4os Durham NC Solar 4.00 Intermediate/Peak Faci!ity4O6 Forsyth NC Solar 4.20 Intermediate/Peak Facility 407 Guilford NC Solar 35.48 Intermediate/Peak Facility 408 Alexander NC Solar 1.94 Intermediate/Peak Facility 409 Wake NC Solar 6.87 Intermediate/Peak Facility 410 Forsyth NC Solar 6.00 Intermediate/Peak Facility 411 Gullford NC Solar 4.91 Intermediate/Peak Facility 412 Mecklenburg NC Solar 3.50 Intermediate/Peak Facility 413 Henderson NC Hydroelectric 6.00 Baseloari Facility 414 Wilkesboro NC Other* 600.00 Intermediate/Peak Facility 415 Durham NC Solar 3.84 Intermediate/Peak Facility 416 Henderson NC Solar 2.50 Intermediate/Peak Facility 417 Forsyth NC Solar 2.58 Intermediate/Peak Facility 418 Cleveland NC Solar 135.00 Intermediate/Peak Facility4l9 Durham NC Solar 2.15 Intermediate/Peak Facility 420 Orange NC Solar 3.60 Intermediate/Peak Facility 421 Alamance NC Solar 2.10 Intermediate/Peak Facility 422 Mecklenburg NC Solar 6.75 Intermediate/Peak Facility 423 Orange NC Solar 5.00 Intermediate/Peek Facility 424 Orange NC Solar 2.40 Intermediate/Peak Facility 425 Orange NC Solar 5.56 Intermediate/Peak Facility 426 Rowan NC Solar 1.70 Intermediate/Pee Facility 427 Union NC Solar 2.94 Intermediate/Peak Facility 428 Guilforcl NC Solar 3.00 Intermediate/Peak Facility 429 Davie NC Solar 7.85 Intermediate/Peak Facility 430 Orange NC Solar 4.00 Intermediate/Peak Facility 431 Durham NC Solar 5.16 Intermediate/Peak Facility 432 Guilford NC Solar 4.00 Intermediate/Peak Facility 433 Durham NC Solar 3.00 Intermediate/Peak Facility 434 Davidson NC Solar 3.45 Intermediate/Peak Facility 435 Mecklenburg NC Solar 2.58 Intermediate/Pea Facility 436 Orange NC Solar 4.00 Intermediate/Pea Facility 437 Cleveland NC Solar 4.70 Intermediate/Pea Facility438 Mecklenburg NC Solar 3.50 Intermediate/Peak Facility 439 Mecklenburg NC Solar 4.00 Intermediate/Peak Facility 440 Iredell NC Solar 60.00 Intermediate/Peak Facility 441 Wake NC Solar 2.21 Intermediate/Peak Facility 442 Randolph NC Solar 2.58 Intermediate/Peak Facility 443 Alamance NC Solar 2.40 Intermediate/Peak Facility 444 Forsyth NC Solar 3.15 Intermediate/Peak Facility 445 Henderson NC Solar 2.70 Intermediate/Peak Facility 446 Wake NC Solar 2.21 Intermediate/Peak Facility 447 Orange NC Solar 5.16 Intermediate/Peak Facility 448 Mecklenburg NC Solar 3.15 Intermediate/Peak

120 Facility Name City/County State Primary Fuel Type Capacity (ACkW) Designation

Facility44g Mecklenburg NC Solar 3.44 Intermediate/Peak Facility 450 Mecklenburg NC Solar 0.70 Intermediate/Peak Facility45l Surry NC Solar 1000.00 Intermediate/Peak Facility 452 Rockingham NC Hydroelectric 1275.00 Baseload Facility 453 Rockingham NC Hydroelectric 951.00 Baseload Facility 454 Marion NC Other* 650.00 Intermediate/Peak Facility455 Hickory NC Olher* 500.00 Intermediate/Peak Facility 456 Catawba NC Solar 8.17 Intermediate/Peak Facilty 457 Mecklenburg NC Solar 49.00 Intermediate/Peak bFaciiity4s8 Charlotte NC Other* 2200.00 Intermediate/Peak Facility 459 Mecklenburg NC Solar 12.00 Intermediate/Peak Facility 460 Hendersonville NC Other* 1000.00 Intermediate/Peak Facility 461 Cabarrus NC Solar 4.00 Intermediate/Peak Facility 462 Concord NC Other* 2950.00 Intermediate/Peak Facility 463 Rutherford NC Solar 1.96 Intermediate/Peak Facility 464 Mecklenburg NC Solar 5.76 Intermediate/Peak Facility 465 Orange NC Solar 1.32 Intermediate/Peak Facility 466 Yadkin NC Solar 7.80 Intermediate/Peak Facility 467 Yadkin NC Solar 7.10 Intermediate/Peak Facility 468 Mecklenburg NC Solar 1.89 Intermediate/Peak Facility 469 Jackson NC Solar 2.76 Intermediate/Peak Facility47o Yadkin NC Solar 6.00 Intermediate/Peak Facility47l Rutherford NC Solar 1.94 Intermediate/Peak Facility 472 Iredell NC Solar 2.80 Intermediate/Peak Facility 473 Davidson NC Solar 4.32 Intermediate/Peak Facility474 Durham NC Solar 3.23 Intermediate/Peak Facility475 Gaston NC Hydroelectric 1800.00 Baseload Facility476 Davie NC Solar 5000(X) Intermediate/Peak Facility 477 Durham NC Solar 3.00 Intermediate/Peak Facility 478 Stokes NC Solar 4.00 Intermediate/Peak Facility479 Greensboro NC Other 700.00 Intermediate/Peak Facility 480 Greensboro NC Other* 2500.00 intermediate/Peak Facility4sl Greensboro NC Other* 1280.00 Intermediate/Peak Facility 482 Durham NC Landfill Gas 3180.00 Baseload Facility483 Mecklenburg NC Solar 4.80 Intermediate/Peak Facility 484 Durham NC Solar 2.58 Intermediate/Peak Facility 485 Mecklenburg NC Solar 4.00 Intermediate/Peak Facility 486 Catawba NC Solar 5.00 Intermediate/Peak Facility 487 Gaston NC Solar 635.00 Intermediate/Peak Facility48R Mecklenburg NC Solar 30.00 Intermediate/Peak Facility 489 Winston-Salem NC Other* 400.00 Intermediate/Peak Facility 490 Durham NC Solar 28.00 Intermediate/Peak Facility 491 Concord NC Other* 680.00 Intermediate/Peak Facility 492 Butner NC Other* 1250.00 Intermediate/Peak Facility 493 Morganton NC Other* 200.00 Intermediate/Peak Facility 494 Catawba NC Solar 135,00 Intermediate/Peak Facility 495 Orange NC Solar 3.60 Intermediate/Peak Facility 496 Union NC Solar 2.63 Intermediate/Peak Facility497 Cabarrus NC Solar 4.00 Intermediate/Peak Facility 498 Rowan NC Solar 10.00 Intermediate/Peak Facility 499 Polk NC Hydroelectric 5500.00 Baseload Facility 500 Alamance NC Solar 221.76 Intermediate/Peak Facility 501 Orange NC Solar 18.48 Intermediate/Peak Facility 502 Orange NC Solar 18.48 Intermediate/Peak Facility 503 Davidson NC Solar 1500.00 Intermediate/Peak Facility 504 Mecklenburg NC Solar 8.40 Intermediate/Peak

121 Facility Name City/County State Primary Fuel Type Capacity (Ac kW) Designation

Facility 505 Carrboro NC Other* 500.00 Intermediate/Peak Facility 506 Chapel Hill NC Other* 1135.00 nterieda:e/Peak Facility 507 Chapel Hill NC Other* 500.00 .ntermediate/Peak Facility 508 Chapel Hill NC Other* 2000.00 Intermediate/Peak Facility 509 Orange NC Solar 5.30 Intermediate/Peak Facility 510 Orange NC Solar 6.00 Intermediate/Peak Facility 511 Hendersonville NC Other* 500.00 Intermediate/Peak Facility 512 Fletcher NC Other* 1000.00 Intermediate/Peak Facility 513 McDowell NC Solar 4.68 Intermediate/Peak Facility 514 Guilford NC Solar 3.01 Intermediate/Peak Facility 515 Macon NC Solar 1.92 Intermediate/Peak Facility 516 Orange NC Solar 3.78 Intermediate/Peak Facility 517 Rowan NC Solar 7.20 Intermediate/Peak Facility 518 Rowan NC Solar 5.60 Intermediate/Peak Facility 519 Alarriance NC Solar 2.00 Intermediate/Peak Facility 520 Cabarrus NC Engine Dynamometer N/A Intermediate/Peak Facility 521 Durham NC Solar 4.30 Intermediate/Peak Facility 522 Guilford NC Solar 2.70 Intermediate/Peak Facility 523 Alamance NC Solar 3.00 Intermediate/Peak Facility 524 Forsyth NC Solar 6.00 Intermediate/Peak Facility 525 Durham NC Solar 3.36 Intermediate/Peak Facility 526 Rutherford NC Solar 5.00 Intermediate/Peak Facility 527 Rutherford NC Solar 3.68 Intermediate/Peak Facility 528 Transylvania NC Solar 3.00 Intermediate/Peak Facility 529 Rowan NC Solar 2.58 Intermediate/Peak Facility 530 Cleveland NC Hydroelectric 600.00 Baseload Facility 531 Winston-Salem NC Other* 750.00 Intermediate/Peak Facility 532 Guilford NC Solar 1.80 Intermediate/Peak Facility 533 Jackson NC Solar 9.00 Intermediate/Peak Facility 534 Mebane NC Other* 400.00 Intermediate/Peak Facility 535 Matthews NC Other* 1450.00 Intermediate/Peak Facility 536 Huntersville NC Others 3200.00 Intermediate/Peak Facility 537 Mecklenburg NC Solar 33.12 Intermediate/Peak Facility 538 Mecklenburg NC Solar 52.47 Intermediate/Peak Facility 539 Jackson NC Solar 4.00 Intermediate/Peak Facility 540 Mecklenburg NC Solar 8.80 Intermediate/Peak Facility 541 Orange NC Solar 4.00 Intermediate/Peak Facility 542 Mecklenburg NC Solar 2.70 Intermediate/Peak Facility 543 Durham NC Solar 7.00 Intermediate/Peak Facility 544 Mecklenburg NC Solar 7.60 Intermediate/Peak Facility 545 Mecklenburg NC Solar 4.10 Intermediate/Peak Facility 546 Orange NC Solar 1.20 Intermediate/Peak Facility 547 Davie NC Solar 9.88 Intermediate/Peak Facility 548 Mecklenburg NC Solar 2.00 Intermediate/Peak Facility 549 Polk NC Solar 5.18 Intermediate/Peak Facility 550 Orange NC Solar 3.00 Intermediate/Peak Facility 551 Orange NC Solar 1.71 Intermediate/Peak Facility 552 Durham NC Solar 1.20 Intermediate/Peak Facility 553 Polk NC Solar 1.72 Intermediate/Peak Facility 554 Mecklenburg NC Solar 18.06 Intermediate/Peak Facility 555 Henderson NC Solar 250 Intermediate/Peak Facility 556 RTP NC Other* 350.00 Intermediate/Peak Facility 557 Forsyth NC Solar 1.94 Intermediate/Peak Facility 558 Randolph NC Solar 2.30 Intermediate/Peak Facility 559 Durham NC Solar 4.00 Intermediate/Peak Facility 500 Stanly NC Solar 5.17 Intermediate/Peak

122 Facility Name City/County State Primary Fuel Type Capacity (ACkW) Designation

Facility561 Gaston NC Solar 4.00 Intermediate/Peak Fac6ity 562 Forsyth NC Solar 430 Intermediate/Peak Facility563 Catawba NC Solar 300 Intermediate/Peak Facility564 Wilkes NC Solar 3.68 Intermediate/Peak Facility365 Rural Hall NC Other* 105000 Intermediate/Peak Facility566 Mecklenburg NC Solar 4.70 Intermediate/Peak Facility567 Jackson NC Solar 9.90 Intermediate/Peak Facility568 Franklin NC Solar 5.00 Intermediate/Peak Facility569 Mecklenburg NC Solar 2.50 Intermediate/Peak Facility570 Henderson NC Solar 4.00 Intermediate/Peak Facility 571 orange NC Solar ISO Intermediate/Peak Facility572 Guilford NC Solar 1.10 Intermediate/Peak Facility573 Guilford NC Solar 4.00 Intermediate/Peak Facility 574 Mecklenburg NC Solar 500 Intermediate/Peak Facility 575 Henderson NC Solar 0.76 Intermediate/Peak Facility576 Union NC Solar 1.00 Intermediate/Peak Facility577 Mecklenburg NC Solar 2.58 Intermediate/Peak Facility578 Alamance NC Solar 5.50 Intermediate/Peak Facility579 Stanly NC Solar 5.16 Intermediate/Peak Facility580 Union NC Solar 7.00 Intermediate/Peak Facility 581 Union NC Solar 2.48 Intermediate/Peak Facility582 Macon NC Solar 5.94 Intermediate/Peak Facility583 Randolph NC Solar 4.00 Intermediate/Peak Facility 584 Rowan NC Solar 6.45 Intermediate/Peak Facility 585 Durham NC Solar 4.62 Intermediate/Peak Facility586 Wilkes NC Hydroelectric 200.00 Baseload Facility587 Iredell NC Solar 3.00 Intermediate/Peak Facility 588 Iredell NC Engine Dynamometer N/A Intermediate/Peak Facility589 Henderson NC Solar 9.00 Intermediate/Peak Facility 590 Iredell NC Solar 2.94 Intermediate/Peak Facility591 Transylvania NC Solar 3.00 Intermediate/Peak Facility592 Henderson NC Solar 3.44 Intermediate/Peak Facility 593 Forsyth NC LandfillGas 4750.00 Baseload Facility 594 Durham NC Solar 5.00 Intermediate/Peak Facility 595 Mecklenburg NC Solar 4.73 Intermediate/Peak Facility 596 Mecklenburg NC Solar 10.80 Intermediate/Peak Facility 597 Alamance NC Solar 3.44 Intermediate/Peak Facility 598 Alamance NC Solar 2.40 Intermediate/Peak Facility 599 Rutherford NC Solar 3.60 Intermediate/Peak Facility 600 Alamance NC Solar 24.00 Intermediate/Peak Facility 601 Orange NC Solar 2.58 Intermediate/Peak Facility602 Caswell NC Solar 2.82 Intermediate/Peak Facility 603 Mecklenburg NC Solar 20.00 Intermediate/Peak Facility 604 Orange NC Solar 2.40 Intermediate/Peak Facility605 Guilford NC Solar 5.46 Intermediate/Peak Facility 606 Catawba NC Solar 2.58 Intermediate/Peak Facility607 McDowell NC Solar 1.02 Intermediate/Peak Facility 608 Durham NC Solar 3.50 Intermediate/Peak Facility 609 Cabarrus NC Solar 3.00 Intermediate/Peak Facility 610 Orange NC Solar 2.00 Intermediate/Peak Facility 611 Durham NC Solar 4.00 Intermediate/Peak Facility 612 Henderson NC Solar 5.00 Intermediate/Peak Facility 613 Alexander NC Solar 2.58 Intermediate/Peak Facility 614 Mcdowell NC Solar 3.00 Intermediate/Peak Facility615 Guilford NC Solar 2.58 Intermediate/Peak Facility 616 Cabarrus NC Solar 4500.00 Intermediate/Peak

123 Facility Name City/County State Primary Fuel Type Capacity (AC kW) Designation

Facility517 Durham NC Solar 101.20 Intermediate/Peak Facility618 Guilford NC Solar 12.00 Intermediate/Peak Facility619 Forsyth NC Solar 10.00 Intermediate/Peak Facility620 Butner NC Other* 750.00 Intermediate/Peak Facility521 Davie NC Hydroelectric 1500.00 Baseload Facility622 Surry NC Solar 9.87 lnterrriediate/Peak Facility623 Forsyth NC Solar 4.00 Intermediate/Peak Facility624 Surry NC Solar 5.00 Intermediate/Peak Facility625 Orange NC Solar 8.60 Intermediate/Peak Facility626 Durham NC Solar 3.66 Intermediate/Peak Facility627 Durham NC Solar 2.04 Intermediate/Peak Facility628 Burke NC Solar 3.04 Intermediate/Peak Facility629 Iredell NC Solar 1.51 Intermediate/Peak Facility630 Rockingham NC Solar 4.73 Intermediate/Peak Facility631 Lincoln NC Hydroelectric 750.00 Baseload Facility632 Catawba NC Solar 4.41 Intermediate/Peak Facility633 Chatham NC Solar 3.84 Intermediate/Peak Facility634 Mecklenburg NC Solar 2.00 Intermediate/Peak Facility635 Orange NC Solar 5.00 Intermediate/Peak Facility635 Orange NC Solar 5.17 Intermediate/Peak Facility637 Alamance NC Solar 2.85 Intermediate/Peak Facility638 Orange NC Solar 9.00 Intermediate/Peak Facility639 Durham NC Solar 1.50 Intermediate/Peak Facility640 Transylvania NC Solar 3.36 Intermediate/Peak Facility641 RTP NC Other* 1825.00 Intermediate/Peak Facility642 Rockingham NC Solar 9.00 Intermediate/Peak Facility643 Forsyth NC Solar 6.00 Intermediate/Peak Facility644 Guilford NC Solar 21.40 Intermediate/Peak Facility645 Davidson NC Solar 15500.00 Intermediate/Peak Facility646 Transylvania NC Solar 6.00 Intermediate/Peak Facility647 Macon NC Solar 6.00 Intermediate/Peak Facility648 Orange NC Solar 9.24 Intermediate/Peak Facility649 Chatham NC Solar 4.41 Intermediate/Peak Facility650 Wake NC Solar 2.21 Intermediate/Peak Facility651 Catawba NC Solar 4.76 Intermediate/Peak Facility652 Orange NC Solar 4.00 Intermediate/Peak Facility653 Gaston NC Solar 1.14 Intermediate/Peak Facility654 Rockingham NC Solar 2.80 Intermediate/Peak Facility655 Swain NC Solar 5.00 Intermediate/Peak Facility656 Durham NC Solar 2.80 Intermediate/Peak Facility657 Durham NC Solar 5.00 Intermediate/Peak Facility658 Greensboro NC Other 750.00 Intermediate/Peak Facility659 Greensboro NC Other* 250.00 Intermediate/Peak Facility660 Alamance NC Solar 8.60 Intermediate/Peak Facility561 Guilford NC Solar 2.15 Intermediate/Peak Facility662 Randolph NC Solar 20.00 Intermediate/Peak Facility663 Randolph NC Solar 52.00 Intermediate/Peak Facility664 Guilford NC Solar 5.00 Intermediate/Peak Facility 665 Guilford NC Solar 175,00 Intermediate/Peak Facility666 Orange NC Solar 0.74 Intermediate/Peak Facility667 Henderson NC Solar &Wind 5,00 Intermediate/Peak Facility668 Mecklenburg NC Solar 4.60 Intermediate/Peak Facility 669 Mecklenburg NC Solar 250.00 Intermediate/Peak Facility670 Catawbe NC Solar 4.70 Intermediate/Peak Facility671 Catawba NC Solar 4.70 Intermediate/Peak Facility672 Orange NC Solar 4,00 Intermediate/Peak

124 Facility Name City/County State Primary Fuel Type Capacity (ACkW) Designation

Facility 673 Durham NC Solar 2.28 Intermediate/Peak Facility 674 Polk NC Solar 6.IXI Intermediate/Peak Facility 675 Alamance NC Solar 1.90 Intermediate/Peak Facility 676 NC Solar 4.58 Intermediate/Peak Facility 677 Mecklenburg NC Solar 2.58 Intermediate/Peak Facility 678 Henderson NC Solar 1.94 Intermediate/Peak Facility 679 Union NC Solar 4.30 Intermediate/Peak Facility 680 Randolph NC Solar 3.98 Intermediate/Peak Facility 681 Cabarrus NC Solar 4.05 Intermediate/Peak Facility 682 Cabarrus NC Solar 4.00 Intermediate/Peak Facility 683 Swain NC Solar 2.52 Intermediate/Peak Facility 684 Rutherfordton NC Solar 2.80 Intermediate/Peak Facility 685 Orange NC Solar 5.00 Intermediate/Peak Facility 686 Mecklenburg NC Solar 4.95 Intermediate/Peak Facility 687 Durham NC Solar 4.95 Intermediate/Peak Facility 688 Orange NC Solar 1.48 Intermediate/Peak Facility 689 Randolph NC Solar 4.00 Intermediate/Peak Facility 690 Orange NC Solar 9.00 Intermediate/Peak Facility 691 Orange NC Solar 9.00 Intermediate/Peak Facility 692 Gullford NC Solar 3.01 Intermediate/Peak Facility 693 Mecklenburg NC Solar 3.29 Intermediate/Peak Facility 694 Burke NC Solar 2.58 Intermediate/Peak Facility 695 Lincoln NC Solar 9.00 Intermediate/Peak Facility 696 Orange NC Solar 3.80 Intermediate/Peak Facility 697 Rutherford NC Hydroelectric 3600.00 Baseload Facility 698 North Wilkesboro NC 5Other 1250.00 Intermediate/Peak Facility 699 Jackson NC Solar 5.00 Intermediate/Peak Facility 700 Valdese NC 5Other 600.00 Intermediate/Peak Facility 701 Wilkesboro NC 5Other 750.00 Intermediate/Peak Facility 702 Yadkinville NC 5Other 1200.00 Intermediate/Peak Facility 703 Reidsville NC 5Other 750.00 Intermediate/Peak çlity 704 Mooresville NC Other 750.00 Intermediate/Peak Facility 705 Brevard NC 5Other 1000.00 Intermediate/Peak Facility 706 Guilford NC Solar 30.00 Intermediate/Peak Facility 707 Cherokee NC 5Other 12500.00 Intermediate/Peak Facility 708 Mecklenburg NC Solar 18.00 Intermediate/Peak Facility 709 Durham NC Solar 4.00 Intermediate/Peak Facility 710 Catawba NC Solar 5000.00 Intermediate/Peak 155.00 Intermediate/Peak Facility 711 - North Wilkesboro NC Other Facility 712 Mecklenburg NC Solar 4.80 Intermediate/Peak Facility 713 Union NC Solar 6.02 Intermediate/Peak Facility 714 Orange NC Solar 20.00 Intermediate/Peak Facility 715 NC Landfill Gas 1059.00 Baseload Facility 716 Durham NC Solar 112.00 Intermediate/Peak Facility 717 Durham NC Solar 51.00 Intermediate/Peak Facility 718 Durham NC Solar 4.00 Intermediate/Peak Facility 719 Chatham NC Solar 2.70 Intermediate/Peak Facility 720 Salisbury NC 5Other 1500.00 Intermediate/Peak Facility 721 Mecklenburg NC Solar 5.70 Intermediate/Peak Facility 722 Mecklenburg NC Solar 4.00 Intermediate/Peak Facility 723 Forsyth NC Solar 1.92 Intermediate/Peak Facility 724 MeckIenbur NC Solar 27.47 Intermediate/Peak Facility 725 Orange NC Solar 14.51 Intermediate/Peak Facility 726 Winston-Salem NC Others 3750.00 Intermediate/Peak Facility 727 Winston-Salem NC Other 3000.00 Intermediate/Peak Facility 728 Winston-Salem NC Other* 3000.00 Intermediate/Peak

125 Facility Name City/County State Primary Fuel Type Capacity (ACkW) Designation

Facility 729 Winston-Salem NC Other* 500.00 Intermediate/Peak Facility 730 Rowan NC Solar 150.00 Intermediate/Peak Facility 731 Rockingham NC Solar 2.00 Intermediate/Peak Facility 732 Iredell NC Solar 1.40 Intermediate/Peak Facility 733 Cherokee NC Solar 8.20 Intermediate/Peak Facility 734 Orange NC Solar 4.32 Intermediate/Peak Facility 735 Watauga NC Landfill Gas 186.00 Baseload Facility 736 Davie NC Solar 0.70 Intermediate/Peak Facility 737 Winston-Salem NC Other* 2000.00 Intermediate/Peak Facility 738 Wilkes NC Solar 2.85 Intermediate/Peak Facility 739 Elkin NC Other* 500.00 Intermediate/Peak Facility 740 Polk NC Solar 5.00 Intermediate/Peak Facility 741 Transylvania NC Solar 0.65 Intermediate/Peak Facility 742 Wilkes NC Wind 2.40 Intermediate/Peak Facility 743 Wilkes NC Landfill Gas 70.00 Baseload Facility 744 Guilford NC Solar 4.52 Intermediate/Peak Facility 745 Cleveland NC Solar 2.50 Intermediate/Peak Facility 746 Orange NC Solar 2.30 Intermediate/Peak Facility 747 Orange NC Solar 5.00 Intermediate/Peak Facility 748 Mecklenburg NC Solar 2.41 Intermediate/Peak Facility 749 Macon NC Solar 3.00 Intermediate/Peak Facility 750 Forsyth NC Solar 2.94 Intermediate/Peak Facility 751 Orange NC Solar 2.00 Intermediate/Peak Facility 752 Guilford NC Solar 4.80 Intermediate/Peak Facility 753 Durham NC Solar 3.00 Intermediate/Peak Facility 754 Jackson NC Solar 6.00 Intermediate/Peak Facility 755 Orange NC Solar 4.00 Intermediate/Peak Facility 756 Guilford NC Solar 3.00 Intermediate/Peak Facility 757 Forsyth NC Solar 3.30 Intermediate/Peak Facility 758 Forsyth NC Landfill Gas 2400.00 Baseload Facility 759 Mecklenburg NC Solar 4.00 Intermediate/Peak Facility 760 Union NC Solar 6.00 Intermediate/Peak Facility 761 Davidson NC Solar 82.00 Intermediate/Peak Facility 762 Transylvania NC Solar 4.00 Intermediate/Peak

Note: Data pros ided in lahie [1-3reflects nameplate capacity for the facility.

126 Table H-4 Non-Utility Generation- South Caroliiia SOUTHCAROLINAGENERATORS

Facility Name City/County State Primary Fuel Type Capacity (kW) Designation

Facility 763 Cherokee SC Natural Gas 100000.00 Intermediate/Peak Facility764 Greenville SC Solar 21.00 Intermediate/Peak Facility 755 Spartanburg SC Solar 15.00 Intermediate/Peak Facility 766 SC Solar 0.76 Intermediate/Peak Facility 767 Anderson SC Solar 10.00 Intermediate/Peak Facility 768 Greenville SC Hydroelectric 600.00 Baseload Facility 769 Laurens SC Hydroelectric 6300.00 Baseload Facility 770 Greenville SC Solar 1.94 Intermediate/Peak Facility 771 Pickens SC Solar 2.35 Intermediate/Peak Facility 772 Spartanburg SC Solar 94.08 Intermediate/Peak Facility 773 Spartanburg SC Solar 0.76 Intermediate/Peak Facility 774 Greenville SC Solar 2.15 Intermediate/Peak Facility 775 Spartanburg SC Solar 5.52 Intermediate/Peak Facility 776 Greenville SC Solar 1.68 Intermediate/Peak Facility 777 York SC Solar 2.80 Intermediate/Peak Facility 778 Lancaster SC Solar 5.00 Intermediate/Peak Facility 779 Pickens SC Solar 11.00 Intermediate/Peak Facility 780 Oconee SC Solar 3.60 Intermediate/Peak Facility 781 Greenville SC Solar 1.80 Intermediate/Peak Facility 782 Piclcens SC Solar 42.00 Intermediate/Peak Facility 783 Laurens SC Solar 6.00 Intermediate/Peak Facility 784 Greenville SC Solar 5.00 Intermediate/Peak Facility 785 Greenwood SC Others 1500.00 Intermediate/Peak Facility 786 Spartanburg SC Hydroelectric 1250.00 Baseload Facility 787 Pickens SC Solar 4.50 Intermediate/Peak Facility 788 Laurens SC Solar 0.76 Intermediate/Peak Facility 789 Greenville SC Solar 2.28 Intermediate/Peak Facility 790 Spartanburg SC Solar 3.01 Intermediate/Peak acuity 791 Greenwood SC Solar 2.76 Intermediate/Peak Facility 792 Spartanburg SC Solar 0.74 Intermediate/Peak Facility 793 Greenville SC Solar 2.53 Intermediate/Peak Facility 794 Spartanburg SC Solar 2.80 Intermediate/Peak Facility 795 SC Solar N/A Intermediate/Peak Facility 796 York SC Solar 2.85 Intermediate/Pea Facility 797 Pickens SC Solar 9.00 Intermediate/Pea Facility 798 Greenville SC Solar 0.76 Intermediate/Pea Facility 799 Oconee SC Solar 10.08 Intermediate/Pea Facility 800 Spartanburg SC Engine Dynamometer N/A Intermediate/Pea FacilitySOl Greenville SC Solar 29.83 Intermediate/Pea Facility 802 Greenville SC Solar 1(X).CXJ Intermediate/Pea Facility8o3 Greenville SC Solar 4.30 Intermediate/Pea Facility 804 Spartanburg SC Solar 2.15 Intermediate/Pea Facility 805 Laurens SC Solar 5.64 Intermediate/Pea Facility 806 Spartanburg SC Solar 3.00 Intermediate/Pea Facility 807 Spartanburg SC Landfill Gas 3200.00 Baseload Facility 808 Greenville SC Solar 30,10 Intermediate/Peak Facility 809 SC Solar 5.16 Intermediate/Peak Facility 810 Spartanburg SC Hydroelectric 1600.00 Baseload Facility811 Greenville SC Solar 49.00 Intermediate/Peak Facility 812 Oconee SC Solar 56.70 Intermediate/Peak Facility 813 Greenville SC Solar 4.30 Intermediate/Pea Facility 814 York SC Solar 2.10 Intermediate/Pea Facility 815 Spartanburg SC Solar 0.76 Intermediate/Pea Facility 816 Spartanburg SC Solar 0.19 Intermediate/Peak Facility8l7 Oconee SC Solar 4.00 Intermediate/Peak Facility 818 Laurens SC Solar 1.94 Intermediate/Pea Facility 819 Pickens SC Solar 1.05 Intermediate/Pea

127 Facility Facility Facility Facility Facility Facility

Facility827 Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility Facility

Facility Facility Facility Facility Facility Facility

Facility Facility Facility Facility Facility Facility Facility Facility

Facility Facility Facility Facility Facility

Facility Facility Facility Facility Facility Facility

Facility

Facility Facility Facility Facility Facility

Facility Facility Facility Facility Facility Facility

Facility

821 820 822 823 Facility 824 825

826 828 829 831 830

833 832 834 835 836 837

839 838 840

842 841 843

844 845 846

848 847 849 850

851 852 853 854 855 856

857 858 859 860 861 862 863 864 865 866

868 867 869

870 871 872 873 874 875 876

Name

City/County

Spartanbur Spartanburg

Spartanburg Spartanburg

Spartanburg

Spartanburg

Spartanburg Greenville Greenville

Greenville Greenville Greenville

Greenville

Greenwood Greenville Spartanburg

Greenville

Spartanburg Greenville Spartanburg Anderson Spartanburg Spartanburg Spartanburg Greenville

Spartanburg Greenville

Greenville

Greenville Anderson Greenville

Greenville Anderson

Greenville Anderson

Greenville Anderson

Piclcens Pickens

Greenville Pickens Oconee Greenville Anderson Pickens

Greenville Greenville

Laurens Clinton

Laurens

Kershaw

Pickens

Chester

York

York

York

York

State

SC SC SC SC SC

SC SC SC SC

SC SC SC

SC SC SC SC SC

SC SC SC SC SC SC SC

SC

SC SC SC SC SC

SC SC SC SC SC SC

SC SC SC SC SC SC SC

SC SC SC SC SC SC

SC SC SC

SC SC SC SC SC

Primary

Fuel

Hydroelectric Hydroelectric Hydroelectric

Hydroelectric Hydroelectric

128 Landfill

Hydroelectric

Type

Other*

Solar Solar Solar Solar Solar

Solar Solar Solar Solar Solar Solar Solar Solar

Solar Solar

0ther Solar Solar Solar Other* Solar Solar Solar Other* Solar

Solar

Solar Solar Solar

Solar Solar

Solar

Solar Gas Solar Solar Solar Solar Solar Solar

Wind Solar Solar

Solar

Solar

Solar

Solar Solar

Solar Solar -

Capacity

(kWJ

1600.00

447.00 3500.00

2400.00 1500.00

2020.00 3300.00

15.60

1875.00

2432.00

541 4.84 1000.00 8.00

4.20 2.62

4.133 2.99

3.36 5.89 2.94

14.00 4.73 1.94

3.44 S00.O0

1.30

0.86 3.85 8.60

3.82 2.85

3.78 6.00

6.14 1.04 0.74

19.40 3.01 7.52

6.58

2.38

6.72 1.47

3.01 2.50

2.38

4.68 2.47 0.70

2.20 1.20

8.00

0.76 4.20

4.00 3.00

Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Designation

Intermediate/Peak

Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak

Intermediate/Peak

Intermediate/Peak

Intermediate/Peak

Intermediate/Peak

Intermediate/Peak Intermediate/Peak intermediate/Peak

Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak

Intermediate/Peak Intermediate/Peak Intermediate/Peak

intermediate/Peak

intermediate/Peak Intermediate/Peak Intermediate/Peak

Intermediate/Peak

Baseload

Baseload

Baseload Baseload

Baseload

Baseload

Baseload Facility Name City/County State Primary Fuel Type Capacity (kW) Designation

Facilty 877 Greenville SC Soar 5.26 Intermedate/Peak Facility 878 York SC Solar 2.50 Intermediate/Peak Faclity 879 York SC Solar 7.00 Intermediate/Peak Facility8so Spartanburg SC Solar 1.52 Intermedate/Peak Fac:11ty881 York SC Solar 8.09 Intermediate/Peak Facility 882 Greenville SC Solar 1.80 Intermediate/Peak Facility 883 Anderson SC Solar 2.14 Intermediate/Peak Facility 884 Greenville SC Solar 6.00 Intermediate/Peak Facility 885 Greenville SC Solar 4.00 Intermediate/Peak Facility 885 Greenville SC Solar 2.10 Intermediate/Peak Facility 887 Anderson SC Solar 3.60 Intermediate/Peak

Note: Data proided iii Fable[1-4reflects nameplate capacity for the facility.

129 APPENDIX transmission This

the provides Table Table

Table

Rule

YEAR

Please

2014

transmission

(p)

be

no utility

appendix

fbr 1—2

R8-62: [-1:

1-2:

incorporated later

refer

Plans

infbrmation

the

lists

(I) and

five

or

than

system.

I:

construction

to

person

Antioch

for

Certilicates 425.

lists

years.

Duke/Progress the

DEC

the

For

line

September

the

line

the except

Company’s

existing

pursuant projects

covered in

Transmission

The

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TRANSMISSION

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transmission

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electric that

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environmental

PROJECT

made

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FERC that

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DEC

of

information

the

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transmission

transmission

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planned

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line

compatibility

to

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reported

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130

pgrades

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to

Utility

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construct

meet OR

the

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pages

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UNDER

and

on

and

reliability

NCUC

Rule

as

FERC

discusses

into

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422 carolina

Carolina.

part

related)

R8—60.

CONSTRUCTION

1680 two

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of

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April,

(2)

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its

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CAPACITY

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merger

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This pages

2013.

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an appendix

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424, There

DEC

Duke transmission interconnections and

transmission identil’ plans and

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methods

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ElectriCitics

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maintain or

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mechanisms

point(s);

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for

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adequacy

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date;

models

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detailed

width;

expansion

and

Transmission

the

to

of at

provide

NERC

South

Commission reliability

available system any participation

tbllowing:

lines

and

131

including

used cost-effective

annual

and

South

161

Carolina.

the

requirements.

Reliability thermal

in

reliability.

by

reliability kV

North

generating

following

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Carolina

regional

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addition,

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reliability

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Corrective

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The

transmission

In

and

transmission

compliance

&

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annual

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lines.

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screening

in

annual above)

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system

are

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planning

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load

basis DECs shall

results

DEC

and

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for

to

is the evaluates optimization a

expected identif’ Planning studied performs interrelated requests the manage standards of SERC regional SERC Standards, reliability DEC iransmission

computer Standards Regional portfolio this

DEC audit participates audits conducted audit

in • transactions • neighboring •

the projects for and Assess use studies Ensure Ensure Guidelines problem—solution accordance groups’ simulation and — reliability requires of for [)EC

to need impact process Power included DEC projects inter—balancing of planning the the to the received to

for interconnected for that a provide the in resource purpose upcoming every NERC

on ensure DEC for transmission systems; a Delivery future enables

groups tests and improvement which with planned number Transmission interconnected transfer purposes and three “No the for data to

the transfer Reliability is

transmission planning alternatives provides requests to: evaluate Power authority peak and high demonstrate FERC Findings” optimization years Large of capability, supporting future system

of system. regional transtCr

season capability of economic Delivery for process. and Planning the Open Standards

for

transmission transfer transfer system’s area compliance and compliance

system from Small greatest

The as transmission and reliability the levels that transfer Access their process. well to is access the DEC Standards Power five- Company’s capability. capability Generator

expansion produce acceptable compliance its 132 to capability benefit respective audit as verify with with currently system Transmission transmission and capability compliance groups

to Delivery The team. resources service a NERC’ NERU ten-year for TPL—002—0.a interconnection satisfuctory and multi—year

and to annual Generator Power

improvements

to the audit

priority, to evaluates meet

upgrades coordinate and optimization compliance dollars and Reliability Reliability handle with and periods. of planning Tariff compliance reliability interconnection Delivery DEC generator scope,

work system the transfer and interconnection invested. all

and large (OAIT). Company’s analysis Procedures

‘l’he in transmission Standards. plan TPL— Standards. do with practices process

cost,

are May reliability; needs optimization capability. not

groups

firm interconnection filing and

used 003-Oa. NERC’

and 2011.

of adversely reliability. and The budget is and

as Transmission regional,

in certifications.

liming. meet also Specifically, requests also reservation the customers’

inputs

The Company Reliability

non-firm For process perform

0A1’T. to used NERC scope affect

fund both sub into The

l’he

are are

to Applicationof the practicesand proceduresdescribedabove have ensured DEC’s transmission systemis expectedto continueto providereliableserviceto its nativeload and firmtransmission customers.

133 ALLFNDlX Customers ordered development

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DUKE CAROLINAS ENERGY®

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136

15,

Energy

2013 REPS)

Carolinas

Plan

Portfolio

& ill. II. I.

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EXHIBIT

EX1I1BITB

Introduction REPS REPS

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aid Requirement

Compliance

Total REPS Annual of

Table

Costs,

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Renewable

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Customer

NC

Compliance

of

Cost

REPS

Retail

Contents 137

Resources

Plan

Avoided

Cap

Resources

Resources

Rider

Resources

Accounts

and

Comparison

Plan

Wholesale

and

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Fuel

Rates

Cost

of

Sales

Total

impact

and

139 138

140 140 141

141

142 145

148 145 145 146

147

151 I.

Commission) Plan) Energy Duke provides Company’s

In for

in

As

requires equivalent municipalities calendar

through Duke

Specifically, operations Company’s ability introduction yield

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INTRODUCTION

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of Carolinas,

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to Carolinas

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33.8 renewable

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membership

138

energy

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future.

Section and

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to:

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Year Year

NC

Company

Planning

crafled

evaluated,

cost

Sub

contracted

risks

to

Quali/i’ing

REPS cost

Rate

of

meet and

rates

I

AND

36. Company’s

and

that a

rates

plans

Period.

to prudent,

Capacity

OF

requirements.

its

represent

uncertainties procured,

approved across

comply

PROJECTED

it

for

Facilities,

NC

RENEWABLE represent

will

described

OF

or

Based

REPS

reasonable all

(Current)

meet

REPS General

and

with

5480 otherwise

6.630 6.280 5,630 2013

the

and/or facets

in

the on issued exist

Energy

annualized the

this

herein

its The requirements

COMPLIANCE

the

NC AVOII)ED of

annualized

developed

Commission’s

Requirement

General

across

plan Company

known its

RESOURCES

in procured

represent

REPS

Rates

145

compliance

Docket

with

avoided (Projected) the

Requirement

iniormation

4.940 obligation 5.480 5.150 2014 5.800

(cents within

a a various

avoided

continues

COST

sufficient

a

diversified

variety No.

reasonable

Plan

Order

PLAN

cost

per

requirements.

the

E-l00,

types

RATES

cost

over

of

rates

kWh)

compliance

to available

Establishing

during

resources

types

balance

carefully

of

rates

Sub the

(Projected)

and

proposed

resources

4940 5.150

5.480 2015 5.800

Planning

of

127

prudent the

in

at

Duke

of

renewable

the

monitor to Schedule Planning

Planning

(July

renewable

Standard

by

time

meet

and

Period.

Energy

plan

the

27,

the

of

opportunities

for its

Period.

Company

PP-N and Period

2011).

this

associated

Rates

Carolinas

resources

meeting General

energy

tiling,

(NC),

and

The and

As

in The Table

[neral Table

Note:

2015 represent

Wholesale Retail Total

Note: projected

Residential

Industrial

tables

The The

MWh

MWh

3:

4:

B.

the

MWh

Accts

MWh

number

Accts

MWh

Sales

actual

Sales

below

Accts

sales

sales

Sales

of

WHOLESALE

CUSTOMER PROJECTED

Retail

for

iumher Retail

reported

accounts

reflect

2013

of

and 2012

Sales

above

and

accounts

1,625,359

reported

the

253,030

2014,

5,069

(Actuals)

are

Wholesale

inclusion

for

respectively.

those

for above

ACCOUNTS

2012

Retail

SALES

54,555,907

58,562,512

TOTAL

4,006,605

applicable ear-end

are

(Actuals)

olthe

those

Year-end

and

2012.

1,634,116

to

258,407

AND

5,254

2013

applicable

REPS

Wholesale

Wholesale

and

NORTH

BY

146

compliance

YEAR-END

the

Number

CLASS

projected

to

the

cost

years Customers Customers

1,647,527

262960

5,263

2014 CAROLINA

number

caps

55,232,870

59161,845

of

3,928,975

2013-

2013

NUMBER

Customer

for

of

2015,

compliance

accounts

in

and

the

1,666,206

267,090

represent

5,256

2015

Compliance

fir

Accounts

OF

years

RETAIL

year-end

2013—

actual

2013

MWh

2015.

55,756,164

59,743,779

3,987,615

Plan.

through

AND 2014

sales

and

for

2012,

and C. PROJECTED ANNUAL COST CAP COMPARISON OF TOTAL AND INCREMENTAL COSTS, REPS RIDER AND FUEL COST IMPACT

Projected compliance costs tbr the Planning Period are presented in the cost tables below by calendar year. The cost cap data is based on the numberof accounts as reported above.

Table 5: Projected Annual Cost Caps and Fuel Related Cost Impact

2013 2014 2015

TotalprojectedREPScompliancecosts $ 32,969,472 $ 46,126,516 $ 50,567,253

Recoveredthroughthe FuelRider $ 24,690,757 $ 33,996,739 $ 35,985,121

Totalincrementalcosts (REPSRider) $ 8,278,714 $ 12,129,777 $ 14,582,132

TotalIncludingGRTandRegulatoryFee $ 8,575,016 $ 12,563,910 $ 15,104,036

ProjectedAnnualCostCaps (REPSRider) $ 63,600,083 $ 64,543,124 $ 106,425,364

147

IBECIN

T

otal

Solar

CONFIDENTIALI

Duke

RE

C

Energy

Duke

Piwchases

Resurce

Energy

Carolinas’

Supi

Carolinas,

Renewable

(signed

EXHIBIT

LLC’s

148

Resource

contracts)

2013

A

REPS

DnrtEn

Procurement

Compliance

from

Plan

3 rd

Estimated

Parties RECa_____

Totil

Swir

RE

CPurchase

Rsource

SuDl1r

149

2C

20 20 20

20

ic

10

Diuahc

Cønt!act

Yars

Y.ax Yai Yai

Iai Yar

Y13

Estind RECs

*

lEND

Indicates

T

oilHIro

CONFIDENTIALI

bundle

Purchases

purchase

Resour

of

R[Cs

Sulier

and

energy,

as

Hydro

opposed

flectnc

150

to

RE(’-only

Ronrs

Duzahx

Contract

purchase.

I

2C13

Estizmt1

2C14

REC 2C15

Smart

Appliance

My

Residential

Energy

Smart

Low

Residential

Home

Income

Saver®

Saver®

Efficiency

Energy

Recycle

Duke

Neighborhood

Energy

Energy

for

for

Forecasted

Non.Res

Report

Residential

Education

Assessments

Energy

Efficiency

Duke

Low

Customers

Program

Energy

Customers

Carolinas,

Annual

and

Income

Planning

Weatherization

for

Energy

Carolinas,

Program

Schools

Non

LLC’s

Period

Residential_Programs

Efficiency

Residential

Assistance

2013,

EXHIBIT

EE

LLC’s

151

Programs

Impacts

2014,

Programs

Sub

Sub

2013

2015

Total

Total

Total

B

for

REPS

the

(MWh)

and

REPS

414,346

213,697

213,697

200,650

101,110

30,429 48,562

Projected

8,454

5,318 4,935

Compliance

1,842

2013

Compliance

T715

REPS

316,200

223,834

223,834

92,366

34,868

37,080

7,655

5,297

1,508 4,116

1,842

Plan

Impacts

330,885

235,026

235,026

95,858

34,868

39,667

3,061

7,017

5,297

4,116 1,832