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•	State, federal and foreign legislative and regulatory initiatives, including costs of compliance with existing and future environmental requirements or climate change, as well as rulings that affect cost and investment recovery or have an impact on rate structures or market prices;

•	The extent and timing of the costs and liabilities relating to the Dan River ash basin release and compliance with current and any future regulatory changes related to the management of coal ash;

•	The ability to recover eligible costs, including those associated with future significant weather events, and earn an adequate return on investment through the regulatory process;

•	The costs of decommissioning nuclear facilities could prove to be more extensive than are currently identified and all costs may not be fully recoverable through the regulatory process;

•	The risk that the credit ratings of the company or its subsidiaries may be different from what the companies expect;

•	Costs and effects of legal and administrative proceedings, settlements, investigations and claims;

•	Industrial, commercial and residential growth or decline in service territories or customer bases resulting from customer usage patterns, including energy efficiency efforts and use of alternative energy sources, including self-generation and distributed generation technologies;

•	Additional competition in electric markets and continued industry consolidation;

•	Political and regulatory uncertainty in other countries in which Duke Energy conducts business;

•	The influence of weather and other natural phenomena on operations, including the economic, operational and other effects of severe storms, hurricanes, droughts and tornadoes;

•	The ability to successfully operate electric generating facilities and deliver electricity to customers;

•	The impact on facilities and business from a terrorist attack, cybersecurity threats, data security breaches, and other catastrophic events;

•	The inherent risks associated with the operation and potential construction of nuclear facilities, including environmental, health, safety, regulatory and financial risks;

•	The timing and extent of changes in commodity prices, interest rates and foreign currency exchange rates and the ability to recover such costs through the regulatory process, where appropriate, and their impact on liquidity positions and the value of underlying assets;

•	The results of financing efforts, including the ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions;

•	Declines in the market prices of equity and fixed income securities and resultant cash funding requirements for defined benefit pension plans, other post-retirement benefit plans, and nuclear decommissioning trust funds;

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Construction and development risks associated with the completion of Duke Energy Registrants’ capital investment projects in existing and new generation facilities, including risks related to financing, obtaining and complying with terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards, as well as the ability to recover costs from customers in a timely manner or at all;

•	Changes in rules for regional transmission organizations, including changes in rate designs and new and evolving capacity markets, and risks related to obligations created by the default of other participants;

•	The ability to control operation and maintenance costs;

•	The level of creditworthiness of counterparties to transactions;

•	Employee workforce factors, including the potential inability to attract and retain key personnel;

•	The ability of subsidiaries to pay dividends or distributions to Duke Energy Corporation holding company (the Parent);

•	The performance of projects undertaken by our nonregulated businesses and the success of efforts to invest in and develop new opportunities;

•	The effect of accounting pronouncements issued periodically by accounting standard-setting bodies;

•	The impact of potential goodwill impairments;

•	The ability to reinvest prospective undistributed earnings of foreign subsidiaries or repatriate such earnings on a tax-efficient basis; and

•	The ability to successfully complete future merger, acquisition or divestiture plans.

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(a)	Primary general service sectors include health care, education, financial services, information technology and military buildings. Primary industrial sectors include textiles, chemicals, rubber and plastics, paper, food and beverage, and auto manufacturing.

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(b)	Primary general service sectors include tourism, health care and government facilities and schools. Primary industrial sectors include phosphate rock mining and processing and citrus and other food processing.

(c)	Primary general service sectors include health care, education, real estate and rental leasing, financial and insurance services, water/wastewater services, and wholesale trade services. Primary industrial sectors include aerospace, primary metals, chemicals and food.

(d)	Primary general service sectors include retail, financial, healthcare and education services. Primary industrial sectors include primary and fabricated metals, transportation equipment, building materials, food and beverage, stone/clay/glass, and chemicals.

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(a)	Statistics include Duke Energy Progress and Duke Energy Florida beginning July 2, 2012.

(b)	Statistics related to all fuels reflect Regulated Utilities' ownership interest in jointly owned generation facilities.

(c)	Generating figures are net of output required to replenish pumped storage facilities during off-peak periods.

(d)	Purchased power includes renewable energy purchases.

(e)	Includes the effect of the Joint Dispatch Agreement (JDA) and Mitigation sales. Mitigation sales are excluded from the Regulated Utilities segment.

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(a)	Represents cost per the most recent site-specific nuclear decommissioning cost studies, including costs to decommission plant components not subject to radioactive contamination. Amounts are in dollars of the year of cost study.

(b)	Includes the Subsidiary Registrants' ownership interest in jointly owned reactors. Other joint owners are responsible for decommissioning costs related to their interest in the reactors.

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(a)	Duke Energy Florida has requested the NRC to terminate the Crystal River Unit 3 operating license as Crystal River Unit 3 permanently ceased operation in February 2013. For additional information on decommissioning activity and transition to SAFSTOR, see Note 4 "Regulatory Matters."

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(a)	Rates increase over a two or three year period as approved by the NCUC and PSCSC. Annual increase amounts represent the total increase once effective.

(b)

Terms of this rate case include (i) recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs, (ii) a $10 million shareholder contribution to agencies providing energy assistance to low-income customers, (iii) an annual reduction in the regulatory liability for costs of removal of $30 million for each of the first two years, and (iv) no additional base rate increases to be effective before September 2015.

(c)

Terms of this rate case include (i) recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs, (ii) an approximate $4 million shareholder contribution to agencies providing energy assistance to low-income customers and for economic development, (iii) a reduction in the regulatory liability for costs of removal of $45 million for the first year, and (iv) no additional base rate increases to be effective before September 2015.

(d)	Terms of this rate case include (i) recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs, (ii) a $20 million shareholder contribution to agencies providing energy assistance to low-income customers, and (iii) a reduction in the regulatory liability for costs of removal of $20 million for the first year.

(e)

Although the PUCO approved no increase in base rates, more than half of the revenue request was approved to be recovered in various riders, including recovery of costs related to former manufactured gas plants (MGP). Recovery of $56 million of MGP costs via a rider was approved in November 2013. The rider became effective in March 2014, was suspended in June 2014 and reinstated in January 2015. For additional information on MGP recovery see Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”

(f)	Terms of this settlement include (i) no additional base rate increases until 2019, (ii) partial recovery of Crystal River Unit 3 beginning in 2014, and (iii) full recovery of Crystal River Unit 3, not to exceed $1,466 million, plus the cost to build a dry cask storage facility, beginning no later than 2017.

(g)	Terms of this settlement include the removal of Crystal River Unit 3 assets from rate base.

(h)	Capital structure includes deferred income tax, customer deposits and investment tax credits.

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•	The Clean Air Act (CAA), as well as state laws and regulations impacting air emissions, including State Implementation Plans related to existing and new national ambient air quality standards for ozone and particulate matter. Owners and/or operators of air emission sources are responsible for obtaining permits and for annual compliance and reporting.

•	The Clean Water Act (CWA) which requires permits for facilities that discharge wastewaters into the environment.

•	The Comprehensive Environmental Response, Compensation and Liability Act, which can require any individual or entity that currently owns or in the past may have owned or operated a disposal site, as well as transporters or generators of hazardous substances sent to a disposal site, to share in remediation costs.

•	The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act (RCRA), which requires certain solid wastes, including hazardous wastes, to be managed pursuant to a comprehensive regulatory regime.

•	The National Environmental Policy Act, which requires federal agencies to consider potential environmental impacts in their decisions, including siting approvals.

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•	weather conditions, including abnormally mild winter or summer weather that cause lower energy usage for heating or cooling purposes, respectively, and periods of low rainfall that decrease the ability to operate facilities in an economical manner;

•	supply of and demand for energy commodities;

•	transmission or transportation constraints or inefficiencies that impact nonregulated energy operations;

•	availability of competitively priced alternative energy sources, which are preferred by some customers over electricity produced from coal, nuclear or gas plants, and customer usage of energy efficient equipment that reduces energy demand;

•	natural gas, crude oil and refined products production levels and prices;

•	ability to procure satisfactory levels of inventory, such as coal, gas and uranium; and

•	capacity and transmission service into, or out of, the Duke Energy Registrants’ markets.

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(a)	Jointly owned with North Carolina Municipal Power Agency Number 1, North Carolina Electric Membership Corporation and Piedmont Municipal Power Agency.

(b)	Duke Energy Progress owns and operates Roxboro Station Units 1-3 and owns 87.06 percent of, and operates, Unit 4.

(c)	Jointly owned with North Carolina Eastern Municipal Power Agency (NCEMPA). Duke Energy Progress executed an agreement in September 2014 to purchase NCEMPA's ownership interest in these facilities. For additional information see Note 2 to the Consolidated Financial Statements, "Acquisitions, Dispositions and Sales of Other Assets."

(d)	Duke Energy Florida owns and operates Intercession City Station Units 1-10 and 12-14. Unit 11 is jointly owned with Georgia Power Company (GPC). GPC has the exclusive right to the output of this unit during the months of June through September. Duke Energy Florida has the exclusive right to the output of this unit for the remainder of the year.

(e)	Duke Energy Indiana owns and operates Gibson Station Units 1-4 and owns 50.05 percent of, and operates, Unit 5. Unit 5 is jointly owned with Wabash Valley Power Association, Inc. and Indiana Municipal Power Agency.

(f)	Includes Cayuga Internal Combustion (IC).

(g)	Includes Wabash River IC.

(h)	Jointly owned with Wabash Valley Power Association.

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(a)	Includes Canoas I and II, which are jointly owned with Companhia Brasileira de Aluminio, as well as the wholly owned Palmeiras and Retiro small hydro plants.

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(a)	Jointly owned with American Electric Power Generation Resources and/or The Dayton Power & Light Company.

(b)	Facility operated by Duke Energy Ohio

(c)	Duke Energy Ohio facilities are included in the Disposal Group as of December 31, 2014.

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(a)	Stock prices represent the intra-day high and low stock price.

(b)	Two dividends were declared in the second quarter of 2013. The first was $0.765 per share and the second was $0.78 per share.

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(a)

Significant transactions reflected in the results above include: (i) 2014 impairment of the Disposal Group (see Note 2 to the Consolidated Financial Statements, "Acquisitions, Dispositions and Sales of Other Assets"); (ii) 2014 incremental tax expense resulting from the decision to repatriate all cumulative historical undistributed foreign earnings (see Note 22 to the Consolidated Financial Statements, "Income Taxes"); (iii) 2014 increase in the litigation reserve related to the criminal investigation of the Dan River coal ash spill (see Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies”); (iv) 2013 charges related to Crystal River Unit 3 and nuclear development costs (see Notes 4 and 25 to the Consolidated Financial Statements, "Regulatory Matters" and "Quarterly Financial Data", respectively); (v) the 2012 merger with Progress Energy (see Note 2 to the Consolidated Financial Statements, "Acquisitions, Dispositions and Sales of Other Assets"); (vi) 2012 and 2011 pretax impairment and other charges related to the Edwardsport Integrated Gasification Combined Cycle (IGCC) project of $628 million and $222 million, respectively; and (vii) 2010 pretax impairment of goodwill and other assets of $660 million.

(b)	On July 2, 2012, immediately prior to the merger with Progress Energy, Duke Energy executed a one-for-three reverse stock split. All share and earnings per share amounts are presented as if the one-for-three reverse stock split had been effective at the beginning of the earliest period presented.

(c)	Operating results reflect reclassifications due to the impact of discontinued operations (see Note 2 to the Consolidated Financial Statements, "Acquisitions, Dispositions and Sales of Other Assets").

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(a)	See Results of Operations below for Duke Energy’s definition of adjusted earnings and adjusted earnings per diluted share as well as a reconciliation of this non-GAAP financial measure to net income attributable to Duke Energy and net income attributable to Duke Energy per diluted share.

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•	Duke Energy Indiana proposed transmission and distribution infrastructure improvement totaling $1.9 billion.

•	Duke Energy Florida proposed approximately $1.8 billion investment in three new generation projects, a combined-cycle plant in Citrus County, an uprate plan at the Hines Energy Complex (Hines) facility and acquisition of the Osprey plant from Calpine Corporation (Calpine).

•	Duke Energy Progress proposed the acquisition of North Carolina Eastern Municipal Power Agency's (NCEMPA) ownership interest in some of Duke Energy Progress’s existing nuclear and coal generation and the acquisition of solar projects in eastern North Carolinas for a total amount of approximately $1.2 billion.

•	Duke Energy Carolinas proposed construction of a combined-cycle natural gas plant at the William States Lee generation facility at a cost of approximately $600 million.

•	Commercial Power proposed construction of the Atlantic Coast Pipeline for a total investment of approximately $2 billion

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•	Growing and adapting the business and achieving financial objectives, including delivering on the 2015 adjusted diluted earnings per share (EPS) guidance range of $4.55 to $4.75, and advancing viable future growth opportunities for regulated and nonregulated businesses

•	Excelling in safety, operational performance and environmental stewardship

•	Developing and engaging employees, while strengthening leadership

•	Improving the lives of our customers and the vitality of our communities

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•	Increased retail pricing and riders primarily resulting from the implementation of revised rates in most jurisdictions;

•	Favorable weather in 2014 compared to 2013;

•	Higher PJM capacity revenues for the nonregulated Midwest generation business due to higher prices; and

•	Higher results of the renewables business due to higher production from the wind and solar portfolios, lower costs and additional renewables investments.

•	Higher depreciation and amortization expense primarily due to higher depreciable asset base and lower reductions to cost of removal reserves;

•	Higher operations and maintenance expense due to higher storm costs, the timing of fossil plant outages and the impact of nuclear outage cost levelization;

•	Lower post in-service debt returns due to projects added to customer rates; and

•	Higher property and other non-income taxes.

•	The inclusion of Progress Energy results for the first six months of 2013;

•	Increased retail pricing and riders resulting primarily from the implementation of revised rates in all jurisdictions; and

•	Lower operating and maintenance expense resulting primarily from the adoption of nuclear outage cost levelization in the Carolinas, lower benefit costs and merger synergies.

•	Higher depreciation and amortization expense;

•	Lower AFUDC;

•	Lower nonregulated Midwest gas generation results; and

•	Incremental shares issued to complete the Progress Energy merger (impacts per diluted share amounts only).

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(a)	For Duke Energy Progress, 26,634 Gigawatt-hours (GWh) sales for the year ended December 31, 2012, occurred prior to the merger between Duke Energy and Progress Energy.

(b)	For Duke Energy Florida, 18,348 GWh sales for the year ended December 31, 2012, occurred prior to the merger between Duke Energy and Progress Energy.

•	A $614 million increase in fuel revenues driven primarily by increased demand from electric retail customers resulting from favorable weather conditions, and higher fuel rates for electric retail customers for all jurisdictions, except North Carolina. Fuel revenues represent sales to retail and wholesale customers;

•	A $556 million net increase in retail pricing primarily due to retail rate changes and updated rate riders;

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A $216 million increase in electric sales (net of fuel revenue) to retail customers due to more favorable weather conditions. (i) For the year ended December 31, 2014 in the Carolinas, cooling degree days were 4 percent below normal as compared with 15 percent below normal during the same period in 2013, and heating degree days were 11 percent above normal as compared with 4 percent above normal during the same period in 2013. (ii) For the year ended December 31, 2014 in the Midwest, cooling degree days were 21 percent below normal as compared with 8 percent below normal during the same period in 2013, and heating degree days were 18 percent above normal as compared with 7 percent above normal during the same period in 2013. (iii) For the year ended December 31, 2014 in Florida, cooling degree days were 3 percent below normal as compared with 2 percent above normal during the same period in 2013, and heating degree days were 4 percent above normal as compared with 35 percent below normal during the same period in 2013;

•	A $63 million increase in wholesale power revenues, net of sharing, primarily due to additional volumes and capacity charges for customers served under long-term contracts; and

•	A $21 million increase in weather-normal sales volumes to retail customers (net of fuel revenue) reflecting increased demand.

•	A $139 million decrease in gross receipts tax revenue due to the NC Tax Simplification and Rate Reduction Act which terminated the collection of the North Carolina gross receipts tax effective July 1, 2014.

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A $611 million increase in fuel expense (including purchased power and natural gas purchases for resale) primarily related to (i) higher volumes of coal, and oil used in electric generation due primarily to increased generation resulting from favorable weather conditions, (ii) higher natural gas prices, and (iii) the application of the Nuclear Electric Insurance Limited (NEIL) settlement proceeds in 2013 for Duke Energy Florida;

•	A $436 million increase in depreciation and amortization expense primarily due to increases in depreciation as a result of additional plant in service and amortization of regulatory assets, and higher 2013 reductions to cost of removal reserves in accordance with regulatory orders; and

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A $292 million increase in operating and maintenance expense primarily due to a litigation reserve related to the criminal investigation of the Dan River coal ash spill (See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies,” for additional information), higher storm costs, repairs and remediation expenses associated with the Dan River coal ash discharge and other ash basin related assessment costs, and higher nuclear costs, including nuclear outage levelization costs, and higher environmental and operational costs that are recoverable in rates; partially offset by a 2013 Crystal River Unit 3 Nuclear Station (Crystal River Unit 3) related settlement matter, decreased benefits costs and 2013 donations for low-income customers and job training in accordance with 2013 North Carolina Utilities Commission (NCUC) and Public Service Commission of South Carolina (PSCSC) rate case orders.

•	A $346 million decrease due to the 2013 impairment and other charges primarily related to Crystal River Unit 3 and the proposed Levy Nuclear Station (Levy). See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for additional information;

•	A $42 million decrease in property and other taxes primarily due to the termination of the collection of the North Carolina gross receipts tax as mentioned above; partially offset by a sales tax reserve as a result of an Indiana sales tax audit, and higher property taxes; and

•	A $22 million decrease due to the 2013 impairment resulting from the decision to suspend the application for two proposed nuclear units at Shearon Harris Nuclear Station (Harris).

•	A $4,339 million increase due to the inclusion of Progress Energy for the first six months of 2013,

•	A $434 million net increase in retail pricing primarily due to revised rates approved in all jurisdictions;

•	A $76 million net increase in wholesale power revenues, net of sharing, primarily due to additional volumes and charges for capacity for customers served under long-term contracts; and

•	A $72 million increase in weather-normal sales volumes to retail customers (net of fuel revenue) reflecting increased demand.

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A $132 million decrease in fuel revenues (including emission allowances) driven primarily by (i) the impact of lower Florida residential fuel rates, including amortization associated with the settlement agreement approved by the Florida Public Service Commission (FPSC) in 2012 (2012 Settlement), (ii) lower fuel rates for electric retail customers in the Carolinas, Florida and Ohio, and (iii) lower revenues for purchased power, partially offset by (iv) increased demand from electric retail customers. Fuel revenues represent sales to retail and wholesale customers.

•	A $3,393 million increase due to the inclusion of Progress Energy for the first six months of 2013,

•	A $346 million increase in impairment and other charges in 2013 primarily related to Crystal River Unit 3 and Levy, and

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•	A $102 million increase in depreciation and amortization expense primarily due to a decrease in the reduction of the cost of removal component of amortization expense as allowed under the 2012 Settlement.

•	A $600 million decrease due to 2012 impairment and other charges related to the Edwardsport IGCC plant. See Note 4 to the Consolidated Financial Statements, "Regulatory Matters," for additional information, and

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A $120 million decrease in fuel expense (including purchased power and natural gas purchases for resale) primarily related to (i) the application of the NEIL settlement proceeds in Florida, including amortization associated with the 2012 Settlement; (ii) lower purchased power costs in (a) the Carolinas, primarily due to additional generating capacity placed in service in late 2012 and market conditions, (b) Ohio, primarily due to reduced sales volumes, and (c) Indiana, reflective of market conditions; partially offset by (iii) higher volumes of natural gas used in electric generation due primarily to additional generating capacity placed in service; (iv) higher prices for natural gas and coal used in electric generation; and (v) higher volumes of coal used in electric generation primarily due to generation mix.

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•	A $44 million decrease in Peru as a result of lower sales volumes and unfavorable exchange rates;

•	A $35 million decrease in Brazil due to unfavorable exchange rates and lower sales volumes partially offset by higher average prices;

•	A $27 million decrease in Chile as a result of lower sales volumes due to an unplanned outage, and lower average prices; and

•	A $25 million decrease in Argentina due to unfavorable exchange rates and lower average prices.

•	A $75 million increase in Brazil due to higher purchased power as a result of unfavorable hydrology, partially offset by favorable exchange rates.

•	A $38 million decrease in Peru as a result of lower purchased power, transmission, and royalty costs; and

•	A $26 million decrease in Argentina due to favorable exchange rates and lower purchased power and fuel consumption.

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•	A $67 million decrease in Brazil due to weakening of the Real to the U.S. dollar,

•	A $53 million decrease in Central America due to lower average prices and volumes, and

•	An $18 million decrease in Argentina as a result of unfavorable exchange rates.

•	A $67 million increase in Brazil due to higher average prices, net of lower volumes, and

•	A $65 million increase in Chile as a result of asset acquisitions in 2012.

•	A $65 million decrease in Central America due to lower fuel costs, partially offset by higher purchased power and coal consumption, and

•	A $20 million decrease in Brazil due to weakening of the Real to the U.S. dollar and lower purchased power partially offset by higher variable costs.

•	A $36 million increase in Chile as a result of acquisitions in 2012.

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•	An $8 million decrease in electric revenues for the Beckjord station, which is not included in the Disposal Group, driven from lower production as units have been retired;

•	A $7 million decrease in net mark-to-market revenues on non-qualifying power hedge contracts.

•	A $16 million increase in electric revenues from higher production in the renewables portfolio.

•	A $94 million increase driven by an impairment taken related to Ohio Valley Electric Corporation (OVEC). See Note 11 to the Consolidated Financial Statements, “Goodwill and Intangible Assets” for additional information.

•	An $18 million decrease in depreciation driven by discontinued amortization of an intangible asset that was impaired and written off in 2014 and extensions on the projected useful lives of assets in the renewable portfolio;

•	A $17 million decrease in fuel expense for the Beckjord station driven by lower cost of coal from decreased production as units have been retired;

•	A $16 million decrease related to a 2013 legal settlement reserve related to previously disposed businesses;

•	A $10 million decrease in general and administrative costs;

•	A $9 million decrease in operations and maintenance expense for the renewables portfolio driven primarily by development cost reductions; and

•	A $6 million decrease in property tax expense driven by cost reductions in the renewables portfolio resulting from a property tax abatement that went into effect in the current year.

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•	An $81 million decrease due primarily to the sale of non-core businesses in 2012; and

•	A $35 million decrease in electric revenues for the Beckjord station driven from lower production as units were prepared for retirement;

•	A $67 million increase due to higher volumes in the renewables portfolio.

•	A $34 million increase in operations and maintenance expense for the renewables portfolio driven primarily by commercial operation of certain assets and costs to run the renewables services company acquired in 2012;

•	A $25 million increase in depreciation driven by renewable portfolio assets put in service;

•	A $17 million increase related to Midcontinent Independent System Operator, Inc. (MISO) and PJM Transmission System Enhancement obligations; and

•	A $16 million increase related to a 2013 legal settlement reserve related to previously disposed businesses.

•	A $56 million decrease due primarily to the sale of non-core businesses in 2012;

•	A $17 million decrease in general and administrative costs; and

•	A $16 million decrease in fuel expense for the Beckjord station, which is not included in the Disposal Group, driven by lower cost of coal from decreased production as units were prepared for retirement;

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•	A $180 million increase in retail pricing and updated rate riders, which primarily reflects the impact of the 2013 North Carolina and South Carolina retail rate cases;

•	A $151 million increase in fuel revenues driven primarily by increased demand from retail customers, mainly due to favorable weather conditions. Fuel revenues represent sales to retail and wholesale customers;

•	A $99 million increase in electric sales (net of fuel revenues) to retail customers due to favorable weather conditions. Heating degree days in 2014 were 11 percent above normal compared to 5 percent above normal during the same period in 2013 and cooling degree days were 6 percent below normal as compared to 17 percent below normal in 2013;

•	A $19 million increase in wholesale power revenues, net of sharing, primarily due to new customers; and

•	An $18 million increase in weather-normal sales volumes to retail customers reflecting increased demand.

•	A $79 million decrease in gross receipts tax revenue due to the NC Tax Simplification and Rate Reduction Act which terminated the collection of the North Carolina gross receipts tax effective July 1, 2014.

•	A $151 million increase in fuel expense (including purchased power) primarily due to increased retail demand resulting from favorable weather conditions;

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A $127 million increase in operating and maintenance expenses primarily due to a litigation reserve related to the criminal investigation of the Dan River coal ash spill (See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies,” for additional information), repairs and remediation expenses associated with the Dan River coal ash discharge and other ash basin related assessment costs, higher non-outage costs at generation plants, higher storm costs, higher distribution costs, higher nuclear outage expense including the impacts of nuclear levelization, and higher energy efficiency program costs, partially offset by decreased corporate costs and lower costs associated with the Progress Energy merger; and

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•	An $88 million increase in depreciation and amortization primarily due to higher depreciation as a result of additional plant in service and amortization of certain regulatory assets, partially offset by lower depreciation expense due to reductions for costs of removal in accordance with the 2013 North Carolina and South Carolina rate case orders.

•	A $58 million decrease in property and other tax expenses primarily due to lower revenue related taxes driven by the elimination of North Carolina gross receipts tax effective July 1, 2014, partially offset by higher property tax expense.

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A $341 million increase in fuel revenues (including emission allowances) driven primarily by increased demand from wholesale and retail customers, partially resulting from favorable weather conditions, and higher fuel rates for wholesale customers reflective of higher fuel costs for Duke Energy Progress; and to a higher fuel rate in the current year related to lower NEIL insurance reimbursements and accelerated Crystal River Unit 3 regulatory asset cost recovery in 2014 as allowed by the 2013 Settlement for Duke Energy Florida. Fuel revenues represent sales to retail and wholesale customers;

•	A $149 million increase in retail pricing, which primarily reflects the impact of the 2013 North Carolina retail rate case in North Carolina and the 2014 base rate increase in Florida; and

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A $114 million increase (net of fuel revenue) in GWh sales to retail customers due to favorable weather conditions. For Duke Energy Progress, heating degree days in 2014 were 11 percent above normal compared to 2 percent above normal in 2013 and cooling degree days were 2 percent below normal compared to 13 percent below normal in 2013. For Duke Energy Florida, heating degree days in 2014 were 51 percent higher and cooling degree days were 4 percent lower compared to the same period in 2013

•	A $344 million increase in fuel expenses (including purchased power). For Duke Energy Florida the increase is due to the application of the NEIL settlement proceeds in 2013 and higher sales volumes driven by increased demand and higher fuel prices in the current year. For Duke Energy Progress the increase is primarily due to increased sales volumes;

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A $245 million increase in depreciation and amortization. For Duke Energy Florida the increase is primarily due to a reduction of the cost of removal component of amortization expense in 2013 as allowed under the 2012 Settlement, increased environmental cost recovery clause amortization related to prior year under-recovery and nuclear cost recovery clause amortization due to an increase in recoverable nuclear assets in the current year. For Duke Energy Progress the increase is primarily due to higher depreciation as a result of additional plant in service and amortization of certain regulatory assets and a prior year reversal of a portion of cost of removal reserves in accordance with the 2013 NCUC rate case order; and

•	An $88 million increase in operations, maintenance and other expense primarily due to a litigation reserve related to the criminal investigation of the management of North Carolina coal ash basins (See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies,” for additional information).

•	A $346 million decrease due to 2013 impairment and other charges at Duke Energy Florida primarily related to Crystal River Unit 3 and Levy; and

•	A $49 million decrease at Duke Energy Progress due to a current year $18 million reduction to a 2012 impairment charge related to the disallowance of transmission project costs, which are a portion of the Long-Term FERC Mitigation and a $22 million prior-year impairment charge resulting from the decision to suspend the application for two proposed nuclear units at the Harris nuclear station.

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•	A $104 million increase in fuel revenues (including emission allowances) driven primarily by increased demand from wholesale and retail customers, partially resulting from favorable weather conditions, and higher fuel rates for wholesale customers reflective of higher fuel costs. Fuel revenues represent sales to retail and wholesale customers;

•	An $82 million increase (net of fuel revenue) in electric sales to retail customers due to favorable weather conditions. Heating degree days in 2014 were 11 percent above normal compared to 2 percent above normal in 2013 and cooling degree days were 2 percent below normal compared to 13 percent below normal in 2013; and

•	An $80 million increase in retail pricing, which primarily reflects the impact of the 2013 North Carolina retail rate case.

•	A $60 million decrease in gross receipts tax revenue due to the NC Tax Simplification and Rate Reduction Act which terminated the collection of the North Carolina gross receipts tax effective July 1, 2014; and

•	A $19 million decrease in weather-normal sales volumes to retail customers reflecting decreased demand.

•	A $111 million increase in fuel expenses (including purchased power) primarily due to increased sales volumes;

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A $113 million increase in operations and maintenance expenses primarily due to a litigation reserve related to the criminal investigation of the management of North Carolina coal ash basins (See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies,” for additional information), the impacts of amortization on nuclear levelization outage deferrals and higher storm costs, partially offset by prior year donations for low-income customers and job training in accordance with the 2013 NCUC rate case order and lower costs to achieve the merger with Duke Energy including severance and employee relocation expenses; and

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•	A $48 million increase in depreciation and amortization expenses primarily due to higher depreciation as a result of additional plant in service and amortization of certain regulatory assets and a prior year reversal of a portion of cost of removal reserves in accordance with the 2013 NCUC rate case order.

•	A $49 million decrease in property and other tax expenses primarily due to lower revenue related taxes driven by the elimination of North Carolina gross receipts tax effective July 1, 2014, partially offset by higher property tax expense; and

•	A $40 million decrease due to a current year $18 million reduction to a 2012 impairment charge related to the disallowance of transmission project costs, which are a portion of the Long-Term FERC Mitigation and a $22 million prior-year impairment charge resulting from the decision to suspend the application for two proposed nuclear units at the Harris nuclear station.

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•	A $237 million increase in fuel and capacity revenues primarily due to a higher fuel rate in the current year related to lower NEIL insurance reimbursements and accelerated Crystal River Unit 3 regulatory asset cost recovery in 2014 as allowed by the 2013 Settlement. Fuel revenues represent sales to retail and wholesale customers;

•	A $69 million net increase in base revenues due primarily to the 2014 base rate increase;

•	A $63 million increase in nuclear cost recovery clause and energy conservation cost recovery clause revenues due to higher recovery rates in the current year;

•	A $32 million increase in electric sales (net of fuel revenue) to retail customers due to favorable weather conditions. Heating degree days in 2014 were 51 percent higher and cooling degree days were 4 percent lower compared to the same period in 2013; and

•	A $29 million increase in wholesale power revenues primarily driven by increased capacity rates partially offset by the impact of contracts that expired in 2013.

•	A $231 million increase in fuel used in electric generation and purchased power due to the application of the NEIL settlement proceeds in 2013 and higher sales volumes driven by increased demand and higher fuel prices in the current year;

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A $215 million increase in depreciation and amortization primarily due to a reduction of the cost of removal component of amortization expense in 2013 as allowed under the 2012 Settlement, increased environmental cost recovery clause amortization related to prior year under-recovery and nuclear cost recovery clause amortization due to an increase in recoverable nuclear assets in the current year; and

•	A $16 million increase in property and other taxes primarily driven by higher revenue-related taxes in 2014 due to the higher revenues.

•	A $346 million decrease due to 2013 impairment and other charges primarily related to Crystal River Unit 3 and Levy; and

•	A $48 million decrease in operations and maintenance costs primarily due to prior year Crystal River Unit 3 related settlement matters and lower costs associated with Progress Energy’s merger with Duke Energy. These costs were partially offset by increased expenses that are recoverable under the energy conservation and environmental cost recovery clauses.

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•	A $56 million increase in regulated fuel revenues primarily driven by higher fuel costs and increased sales volumes;

•	A $51 million increase in retail pricing and rate riders primarily due to 2013 rate increases; and

•	A $9 million increase in volumes to retail customers.

•	An $8 million decrease in electric revenues for the Beckjord station driven from lower production as units have been retired; and

•	A $7 million decrease in net mark-to-market revenue on non-qualifying power hedge contracts.

•	A $94 million impairment taken related to OVEC. See Note 11 to the Consolidated Financial Statements, “Goodwill and Intangible Assets” for additional information; and

•	A $64 million increase in regulated fuel expense driven primarily by higher fuel costs and increased volumes.

•	A $30 million decrease in operating and maintenance expenses primarily due to lower corporate governance costs;

•	A $16 million decrease in nonregulated fuel expense for the Beckjord station driven by lower cost of coal from decreased production as units have been retired; and

•	An $8 million decrease in property and other taxes driven primarily by an Ohio gas excise tax settlement in 2014.

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•	A $138 million increase in fuel revenues (including emission allowances) due to an increase in fuel rates as a result of higher fuel and purchased power costs;

•	An $86 million net increase in rate riders primarily due to updates to the IGCC rider; and

•	A $17 million increase in wholesale power revenues primarily due to higher customer rates.

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•	A $128 million increase in fuel costs primarily driven by higher fuel and purchased power costs;

•	A $71 million increase in depreciation and amortization primarily as a result of the Edwardsport IGCC plant being placed into service in the second quarter of 2013;

•	A $57 million increase in property and other taxes, primarily as a result of amounts recorded related to an Indiana sales tax audit; and

•	A $21 million increase in operation and maintenance primarily due to higher operation and maintenance costs, higher outage costs at generation plants, partially offset by decreased corporate costs.

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(a)	Excludes capital leases and securitized receivables maturities in 2016 and 2017 expected to be renewed. Amounts represent Duke Energy's financing plan, which accelerates certain contractual maturities.

(b)	Cash flows from operations includes expenditures related to ash basin closures.

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(a)	Represents the sublimit of each borrower at December 31, 2014. The Duke Energy Ohio sublimit includes $100 million for Duke Energy Kentucky.

(b)	Duke Energy issued $475 million of commercial paper and loaned the proceeds through the money pool to Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana. The balances are included within Long-Term Debt Payable to Affiliated Companies in the Consolidated Balance Sheets.

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*	A $204 million increase due to prior year contributions to qualified pension plans, favorable retail pricing and rate riders and favorable weather, partially offset by current year under collection of fuel and purchased power costs and timing of cash payments for operations and maintenance expenses.

*	A $2,001 million increase in net income after non-cash adjustments, mainly due to the inclusion of Progress Energy's results for first six months of 2013 and the impact of revised rates and lower operation and maintenance expenses, partially offset by;

*	A $917 million decrease in operating cash flows from increased investments in traditional working capital, mainly due to the timing of receivables and accruals, lower incentive accruals, net of current year payments and reserve reductions and the prior year overallocation of the Carolinas' fuels costs. These decreases were partially offset by the NEIL proceeds.

*	A $192 million return of collateral related to the Chilean hydro acquisition in 2013 and

*	A $150 million decrease in net proceeds from sales and maturities of available for sale securities, net of purchases.

*	A $581 million variance in restricted cash due to posting collateral on a secured debt issuance related to the Chilean hydro acquisition in 2012 and the return of a portion of this collateral in 2013,

*	A $355 million increase in proceeds from the sales of available-for-sale securities, net of purchases due to the investment of excess cash held in foreign jurisdictions and

*	A $351 million decrease in capital, investment and acquisition expenditures primarily due to lower spending on Duke Energy's renewable energy projects and ongoing infrastructure modernization program as these projects were completed, net of expenditures on Progress Energy's maintenance projects.

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*	A $1,595 million increase in proceeds from net issuances of notes payable and commercial paper, primarily due to funding a larger proportion of total financing needs with short-term debt in anticipation of the receipt in 2015 of proceeds from the sale of the Midwest Generation business, the proceeds from which will partially be used for debt reduction, partially offset by;

*	A $963 million decrease in net issuances of long-term debt, primarily due to funding a larger proportion of total financing needs with short-term debt in 2014 than in 2013.

*	An $832 million decrease in net issuances of long-term debt, primarily due to the timing of issuances and redemptions between years, resulting from the completion of major construction projects,

*	A $436 million increase in quarterly dividends primarily due to an increase in common shares outstanding, resulting from the merger with Progress Energy and an increase in dividends per share from $0.765 to $0.78 in the third quarter of 2013. The total annual dividend per share was $3.09 in 2013 compared to $3.03 in 2012 and

*	A $185 million decrease in proceeds from net issuances of notes payable and commercial paper, primarily due to changes in short-term working capital needs.

(a)	Proceeds were used to redeem $402 million of tax-exempt bonds at Duke Energy Ohio, the repayment of outstanding commercial paper and for general corporate purposes. See Note 13 to the Consolidated Financial Statements, "Related Party Transactions" for additional information related to the redemption of Duke Energy Ohio's tax-exempt bonds.

(b)	The debt is floating rate based on three-month London Interbank Offered Rate (LIBOR) plus a fixed credit spread of 38 basis points.

(c)	Proceeds were used to repay $196 million of debt for International Energy and for general corporate purposes.

(d)	Relates to the securitization of accounts receivable at a subsidiary of Duke Energy Florida. Proceeds were used to repay short-term borrowings under the intercompany money pool borrowing arrangement and for general corporate purposes. See Note 17 to the Consolidated Financial Statements, "Variable Interest Entities" for further details.

(e)	Proceeds were used to fund a portion of Duke Energy's prior investment in the existing Wind Star renewables portfolio.

(f)	Proceeds were used to repay short-term borrowings under the intercompany money pool borrowing arrangement and for general corporate purposes.

(g)	The debt is floating rate based on three-month LIBOR plus a fixed credit spread of 20 basis points.

(h)	Proceeds will be used to repay to redeem $450 million of tax-exempt bonds, repay short-term borrowings under the intercompany money pool borrowing arrangement and for general corporate purposes.

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(a)	Callable after January 2018 at par. Proceeds were used to redeem the $300 million 7.10 percent Cumulative Quarterly Income Preferred Securities (QUIPS) and to repay a portion of outstanding commercial paper and for general corporate purposes.

(b)	Proceeds were used to repay $250 million of current maturities and for general corporate purposes, including the repayment of outstanding commercial paper.

(c)	Proceeds were used to repay $200 million of current maturities. The maturity date included above applies to half of the instrument. The remaining half matures in August 2018.

(d)	The debt is floating rate based on a consumer price index and an overnight funds rate in Brazil. The debt is denominated in Brazilian Real.

(e)	Proceeds were used to repay commercial paper as well as for general corporate purposes.

(f)	Represents the conversion of construction loans related to a renewable energy project issued in December 2012 to term loans. No cash proceeds were received in conjunction with the conversion. The term loans have varying maturity dates. The maturity date presented represents the latest date for all components of the respective loans.

(g)	The debt is floating rate. Duke Energy has entered into a pay fixed-receive floating interest rate swap for 95 percent of the loans.

(h)	Represents the conversion of a $190 million bridge loan issued in conjunction with the acquisition of Ibener in December 2012. Duke Energy received incremental proceeds of $40 million upon conversion of the bridge loan. The debt is floating rate and is denominated in U.S. dollars. Duke Energy has entered into a pay fixed-receive floating interest rate swap for 75 percent of the loan.

(i)	Relates to the securitization of accounts receivable at a subsidiary of Duke Energy Progress; the proceeds were used to repay short-term debt. See Note 17 to the Consolidated Financial Statements, "Variable Interest Entities" for further details.

(j)	Proceeds were used to repay notes payable to affiliated companies as well as for general corporate purposes.

(k)	Proceeds were used to repay $400 million of current maturities.

(l)	The debt is floating rate based on 3-month LIBOR and a fixed credit spread of 35 basis points.

(m)	Proceeds were used for general corporate purposes including the repayment of short-term notes payable, a portion of which was incurred to fund the retirement of $250 million of first mortgage bonds that matured in the first half of 2013.

(n)	The debt is floating rate based on 3-month LIBOR plus a fixed credit spread of 14 basis points.

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(a)	See Note 6 to the Consolidated Financial Statements, “Debt and Credit Facilities.”

(b)	Interest payments on variable rate debt instruments were calculated using December 31, 2014 interest rates and holding them constant for the life of the instruments.

(c)	See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies.” Amounts in the table above include the interest component of capital leases based on the interest rates stated in the lease agreements and exclude certain related executory costs.

(d)	Current liabilities, except for current maturities of long-term debt, and purchase obligations reflected in the Consolidated Balance Sheets, have been excluded from the above table.

(e)

Includes firm capacity payments that provide Duke Energy with uninterrupted firm access to electricity transmission capacity and natural gas transportation contracts, as well as undesignated contracts and contracts that qualify as normal purchase/normal sale (NPNS). For contracts where the price paid is based on an index, the amount is based on market prices at December 31, 2014, or the best projections of the index. For certain of these amounts, Duke Energy may settle on a net cash basis since Duke Energy has entered into payment netting arrangements with counterparties that permit Duke Energy to offset receivables and payables with such counterparties.

(f)

Includes contracts for software, telephone, data and consulting or advisory services. Amount also includes contractual obligations for engineering, procurement and construction costs for new generation plants and nuclear plant refurbishments, environmental projects on fossil facilities, major maintenance of certain nonregulated plants, maintenance and day to day contract work at certain wind facilities and commitments to buy wind and combustion turbines. Amount excludes certain open purchase orders for services that are provided on demand, for which the timing of the purchase cannot be determined.

(g)

Related to future annual funding obligations to nuclear decommissioning trust fund (NDTF) through nuclear power stations' re-licensing dates. Amounts through 2017 include North Carolina jurisdictional amounts that Duke Energy Progress retained internally and is transitioning to its external decommissioning funds per a 2008 NCUC order. The transition of the original $131 million must be complete by December 31, 2017, and at least 10 percent must be transitioned each year. See Note 9 to the Consolidated Financial Statements, "Asset Retirement Obligations."

(h)	Uncertain tax positions of $213 million are not reflected in this table as Duke Energy cannot predict when open income tax years will close with completed examinations. See Note 22 to the Consolidated Financial Statements, "Income Taxes."

(i)

The table above excludes reserves for litigation, environmental remediation, asbestos-related injuries and damages claims and self-insurance claims (see Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies”) because Duke Energy is uncertain as to the timing and amount of cash payments that will be required. Additionally, the table above excludes annual insurance premiums that are necessary to operate the business, including nuclear insurance (see Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies”), funding of pension and other post-retirement benefit plans (see Note 21 to the Consolidated Financial Statements, "Employee Benefit Plans"), asset retirement obligations, including ash management expenditures (see Note 9 to the Consolidated Financial Statements, "Asset Retirement Obligations") and regulatory liabilities (see Note 4 to the Consolidated Financial Statements, “Regulatory Matters”) because the amount and timing of the cash payments are uncertain. Also excluded are Deferred Income Taxes and Investment Tax Credits recorded on the Consolidated Balance Sheets since cash payments for income taxes are determined based primarily on taxable income for each discrete fiscal year.

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(b)	Amounts represent sensitivities related to derivative contracts executed to manage generation portfolio risks for periods beyond 2014. Amounts exclude the potential impact of commodity price changes on forecasted economic generation and fuel needed to achieve such forecasted generation.

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(b)	Amounts represent the potential impact to the currency translation through Accumulated Other Comprehensive Income (AOCI) on the Consolidated Balance Sheets.

(a)	Includes the results of Progress Energy beginning on July 2, 2012.

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(a)	Net of insignificant tax expense in 2014, $17 million tax expense in 2013 and $9 million tax expense in 2012. See Note 21 for additional information.

(b)	Net of $13 million tax benefit in 2014, $20 million tax expense in 2013 and $6 million tax expense in 2012.

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(a)	For the year ended December 31, 2012, consolidated net income of $1,782 million includes $2 million attributable to preferred shareholders of subsidiaries. Income attributable to preferred shareholders of subsidiaries is not a component of total equity and is excluded from the table above.

(b)	This decrease primarily relates to cash distributions to noncontrolling interests.

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(a)	Net of $62 million tax expense in 2012.

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(a)	For the year ended December 31, 2012, consolidated net income of $407 million included $4 million attributable to preferred shareholders of subsidiaries. Income attributable to preferred shareholders of subsidiaries is not a component of total equity and is excluded from the table above.

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(a)	Net of $46 million tax expense in 2012.

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(a)	Net of $16 million tax expense in 2012.

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(a)	Jointly owned with American Electric Power Generation Resources and/or The Dayton Power & Light Company.

(b)	Station is not operated by Duke Energy Ohio.

(c)	Total MW capacity is based on summer capacity.

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(a)	Other discontinued operations relate to prior sales of businesses and includes indemnifications provided for certain legal, tax and environmental matters, and foreign currency translation adjustments.

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(a)	International Energy includes a tax adjustment of $373 million related to deferred tax impact resulting from the decision to repatriate all cumulative historical undistributed foreign earnings. See Note 22 for additional information.

(b)	Commercial Power recorded a pretax impairment charge of $94 million related to OVEC. See Note 11 for additional information.

(c)	Other includes costs to achieve the Progress Energy merger. See Notes 2 and 25 for additional information about the merger and related costs.

(d)	Regulated Utilities includes an increase in the litigation reserve related to the criminal investigation of the Dan River coal ash spill. See Note 5 for additional information.

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(a)	In May 2013, the PUCO approved a Duke Energy Ohio settlement agreement that provides for a net annual increase in electric distribution revenues beginning in May 2013. This rate increase impacts Regulated Utilities. See Note 4 for additional information.

(b)	In June 2013, NCUC approved a Duke Energy Progress settlement agreement that included an increase in rates in the first year beginning in June 2013. This rate increase impacts Regulated Utilities. See Note 4 for additional information.

(c)	In September 2013, Duke Energy Carolinas implemented revised customer rates approved by the NCUC and the PSCSC. These rate increases impact Regulated Utilities. See Note 4 for additional information.

(d)	Regulated Utilities recorded an impairment charge related to Duke Energy Florida's Crystal River Unit 3. See Note 4 for additional information.

(e)

Regulated Utilities recorded an impairment charge related to the letter Duke Energy Progress filed with the NRC requesting the NRC to suspend its review activities associated with the combined construction and operating license (COL) at the Harris site. Regulated Utilities also recorded an impairment charge related to the write-off of the wholesale portion of the Levy investments at Duke Energy Florida in accordance with the 2013 Settlement. See Note 4 for additional information.

(f)	Other includes costs to achieve the Progress Energy merger. See Notes 2 and 25 for additional information about the merger and related costs.

(g)	Other includes gain from the sale of Duke Energy's ownership interest in DukeNet. See Note 12 for additional information on the sale of DukeNet.

(a)	Regulated Utilities recorded charges related to Duke Energy Indiana's Integrated Gasification Combined Cycle

(b)	Other includes costs to achieve the Progress Energy merger. See Notes 2 and 25 for additional information about the merger and related costs.

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(a)	Change in amounts of long-lived assets in Latin America includes foreign currency translation adjustments on property, plant and equipment and other long-lived asset balances.

(a)	Commercial Power recorded a pretax impairment charge of $94 million related to OVEC. See Note 11 for additional information.

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(a)	Included in Net property, plant and equipment as of December 31, 2014, on the Consolidated Balance Sheets.

(b)	Includes Crystal River Units 1 and 2.

(c)	Includes Miami Fort Unit 6 which is expected to be retired by June 1, 2015.

(d)	Includes Wabash River Units 2 through 6. Wabash River Unit 6 is being evaluated for potential conversion to gas. Duke Energy Indiana committed to retire or convert these units by June 2018 in conjunction with a settlement agreement associated with the Edwardsport air permit.

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(b)	Duke Energy includes $129 million and $787 million of capital lease purchase accounting adjustments related to Duke Energy Progress and Duke Energy Florida, respectively, related to power purchase agreements that are not accounted for as capital leases in their respective financial statements because of grandfathering provisions in GAAP.

(c)	Substantially all tax-exempt bonds are secured by first mortgage bonds or letters of credit.

(d)	Includes $475 million that was classified as Long-Term Debt on the Consolidated Balance Sheets due to the existence of long-term credit facilities that back-stop these commercial paper balances, along with Duke Energy’s ability and intent to refinance these balances on a long-term basis. The weighted-average days to maturity was 27 days.

(e)	Duke Energy includes $1,975 million in purchase accounting adjustments related to the merger with Progress Energy. See Note 2 for additional information.

(f)	Refer to Note 17 for additional information on amounts from consolidated VIE’s.

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(b)	Duke Energy includes $144 million and $838 million of capital lease purchase accounting adjustments related to Duke Energy Progress and Duke Energy Florida, respectively, related to power purchase agreements that are not accounted for as capital leases in their respective financial statements because of grandfathering provisions in GAAP.

(c)	Substantially all tax-exempt bonds are secured by first mortgage bonds or letters of credit.

(d)	Includes $450 million that was classified as Long-Term Debt on the Consolidated Balance Sheets due to the existence of long-term credit facilities that back-stop these commercial paper balances, along with Duke Energy’s ability and intent to refinance these balances on a long-term basis. The weighted-average days to maturity was 49 days.

(e)	Duke Energy includes $2,067 million in purchase accounting adjustments related to the merger with Progress Energy. See Note 2 for additional information.

(f)	Refer to Note 17 for additional information on amounts from consolidated VIE’s.

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(a)	Excludes $1,975 million in purchase accounting adjustments related to the merger with Progress Energy. See Note 2 for additional information.

(a)	Instrument has a term of less than one year with the right to extend the maturity date for additional one-year periods with a final maturity date no later than December 2026.

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(a)	Proceeds were used to redeem $402 million of tax-exempt bonds at Duke Energy Ohio, the repayment of outstanding commercial paper and for general corporate purposes. See Note 13 for additional information related to the redemption of Duke Energy Ohio's tax-exempt bonds.

(b)	The debt is floating rate based on three-month London Interbank Offered Rate (LIBOR) plus a fixed credit spread of 38 basis points.

(c)	Proceeds were used to repay $196 million of debt for International Energy and for general corporate purposes.

(d)	Relates to the securitization of accounts receivable at a subsidiary of Duke Energy Florida. Proceeds were used to repay short-term borrowings under the intercompany money pool borrowing arrangement and for general corporate purposes. See Note 17 for further details.

(e)	Proceeds were used to fund a portion of Duke Energy's prior investment in the existing Wind Star renewables portfolio.

(f)	Proceeds were used to repay short-term borrowings under the intercompany money pool borrowing arrangement and for general corporate purposes.

(g)	The debt is floating rate based on three-month LIBOR plus a fixed credit spread of 20 basis points.

(h)	Proceeds will be used to redeem $450 million of tax-exempt bonds, repay short-term borrowings under the intercompany money pool borrowing arrangement and for general corporate purposes.

(a)	Callable after January 2018 at par. Proceeds were used to redeem the $300 million 7.10% Cumulative Quarterly Income Preferred Securities (QUIPS) and to repay a portion of outstanding commercial paper and for general corporate purposes.

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(b)	Proceeds were used to repay $250 million of current maturities and for general corporate purposes, including the repayment of outstanding commercial paper.

(c)	Proceeds were used to repay $200 million of current maturities. The maturity date included above applies to half of the instrument. The remaining half matures in August 2018.

(d)	The debt is floating rate based on a consumer price index and an overnight funds rate in Brazil. The debt is denominated in Brazilian Real.

(e)	Proceeds were used to repay commercial paper as well as for general corporate purposes.

(f)	Represents the conversion of construction loans related to two renewable energy projects issued in December 2012 to term loans. No cash proceeds were received in conjunction with the conversion. The term loans have varying maturity dates. The maturity date presented represents the latest date for all components of the respective loans.

(g)	The debt is floating rate. Duke Energy has entered into a pay fixed-receive floating interest rate swap for 95 percent of the loans.

(h)	Represents the conversion of a $190 million bridge loan issued in conjunction with the acquisition of Ibener in December 2012. Duke Energy received incremental proceeds of $40 million upon conversion of the bridge loan. The debt is floating rate and is denominated in U.S. dollars. Duke Energy has entered into a pay fixed-receive floating interest rate swap for 75 percent of the loan.

(i)	Relates to the securitization of accounts receivable at a subsidiary of Duke Energy Progress; the proceeds were used to repay short-term debt. See Note 17 for further details.

(j)	Proceeds were used to repay notes payable to affiliated companies as well as for general corporate purposes.

(k)	Proceeds were used to repay $400 million of current maturities.

(l)	The debt is floating rate based on three-month LIBOR and a fixed credit spread of 35 basis points.

(m)	Proceeds were used for general corporate purposes including the repayment of short-term notes payable, a portion of which was incurred to fund the retirement of $250 million of first mortgage bonds that matured in the first half of 2013.

(n)	The debt is floating rate based on three-month LIBOR plus a fixed credit spread of 14 basis points.

(a)	Represents the sublimit of each borrower.

(b)	Duke Energy issued $475 million of commercial paper and loaned the proceeds through the money pool to Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana. The balances are classified as Long-Term Debt Payable to Affiliated Companies in the Consolidated Balance Sheets.

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(a)	Included in Regulated Utilities segment.

(b)	Jointly owned with North Carolina Municipal Power Agency Number 1, NCEMC and Piedmont Municipal Power Agency.

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(c)	Jointly owned with NCEMPA. Duke Energy Progress executed an agreement in September 2014 to purchase NCEMPA's ownership interest in these facilities. See Note 2 for further discussion.

(d)

All costs associated with Crystal River Unit 3 are included within Regulatory assets on the Consolidated Balance Sheets of Duke Energy, Progress Energy and Duke Energy Florida. See Note 4 for additional information. Co-owned with Seminole Electric Cooperative, Inc., City of Ocala, Orlando Utilities Commission, City of Gainesville, City of Leesburg, Kissimmee Utility Authority, Utilities Commission of the City of New Smyrna Beach, City of Alachua and City of Bushnell (Florida Municipal Joint Owners). Duke Energy Florida is in the process of obtaining the remaining ownership interest from the Florida Municipal Joint Owners.

(e)	Jointly owned with Georgia Power Company (GPC). GPC has exclusive rights to the output of the unit during the months of June through September and pays all fuel and water costs during this period. Duke Energy Florida pays all fuel and water costs during the remaining months. Other costs are allocated 66.67 percent to Duke Energy Florida and the remainder to GPC.

(f)	All costs associated with these plants are included in Assets held for sale on the Consolidated Balance Sheets of Duke Energy and Duke Energy Ohio as part of the Disposal Group. See Note 2 for further discussion.

(g)	Jointly owned with The Dayton Power and Light Company.

(h)	Jointly owned with America Electric Power Generation Resources and The Dayton Power and Light Company.

(i)	Station is not operated by Duke Energy Ohio.

(j)	Jointly owned with WVPA and Indiana Municipal Power Agency.

(k)	Jointly owned with WVPA.

(l)	Included in International Energy segment. Jointly owned with Companhia Brasileira de Aluminio.

(a)	Balances at December 31, 2013 and 2012, include $8 million and $7 million, respectively, reported in Other current liabilities on the Consolidated Balance Sheets at Duke Energy, Progress Energy and Duke Energy Progress.

(b)	Substantially all accretion expense for the years ended December 31, 2014 and 2013 relates to Duke Energy’s regulated electric operations and has been deferred in accordance with regulatory accounting treatment.

(c)

For 2014, amounts for Duke Energy, Progress Energy and Duke Energy Progress primarily relate to Duke Energy Progress' site-specific nuclear decommissioning cost studies. Amounts at Duke Energy also include impacts from Duke Energy Progress' site-specific nuclear decommissioning cost studies on purchase accounting amounts. For 2013, amounts for Duke Energy, Duke Energy Carolinas, Progress Energy and Duke Energy Florida primarily relate to the site-specific nuclear decommissioning cost studies.

(d)	Amounts relate to liability settlements for Crystal River Unit 3.

(e)	Amounts primarily relate to asset retirement obligations recorded as a result of the Coal Ash Act and an agreement with the SCDHEC related to the W.S. Lee Steam Station.

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(a)	Represents cost per the most recent site-specific nuclear decommissioning cost studies, including costs to decommission plant components not subject to radioactive contamination.

(b)	Includes the Subsidiary Registrants' ownership interest in jointly owned reactors. Other joint owners are responsible for decommissioning costs related to their interest in the reactors.

(c)	Amounts are in dollars of year of cost study.

(d)	In the fourth quarter of 2014, Duke Energy Carolinas requested from the NCUC a reduction in the annual funding requirement to zero. Duke Energy Carolinas received approval from the NCUC in January 2015.

(e)	Duke Energy Progress' site-specific cost nuclear decommissioning cost studies are expected to be filed with the NCUC and PSCSC by the second quarter of 2015. Duke Energy Progress will also complete a new funding study, which will be completed and filed with the NCUC and PSCSC in 2015.

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(a)	Duke Energy Florida has requested the NRC terminate the operating license as Crystal River Unit 3 permanently ceased operation in February 2013. Refer to Note 4 for further information on decommissioning activity and transition to SAFSTOR.

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(a)

Includes capitalized leases of $1,548 million, $40 million, $315 million, $146 million, $169 million, $98 million, and $30 million at Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio, and Duke Energy Indiana, respectively, primarily in regulated plant. The Progress Energy, Duke Energy Progress and Duke Energy Florida amounts are net of $72 million, $5 million and $67 million, respectively, of accumulated amortization of capitalized leases.

(b)	Includes $1,408 million, $847 million, $561 million and $561 million of accumulated amortization of nuclear fuel at Duke Energy, Duke Energy Carolinas, Progress Energy and Duke Energy Progress, respectively.

(c)	Includes accumulated amortization of capitalized leases of $52 million, $8 million, $25 million and $6 million at Duke Energy, Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana, respectively.

(d)	Includes gross property, plant and equipment cost of consolidated VIEs of $1,873 million and accumulated depreciation of consolidated VIEs of $257 million at Duke Energy.

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(a)

Includes capitalized leases of $1,606 million, $53 million, $328 million, $148 million, $180 million, $96 million, and $30 million at Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio, and Duke Energy Indiana, respectively, primarily in regulated plant. The Progress Energy, Duke Energy Progress and Duke Energy Florida amounts are net of $60 million, an insignificant amount and $57 million, respectively, of accumulated amortization of capitalized leases.

(b)	Includes $1,118 million, $681 million, $438 million and $438 million of accumulated amortization of nuclear fuel at Duke Energy, Duke Energy Carolinas, Progress Energy and Duke Energy Progress, respectively.

(c)	Includes accumulated amortization of capitalized leases of $40 million, $4 million, $21 million and $5 million at Duke Energy, Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana, respectively.

(d)	Includes gross property, plant and equipment cost of consolidated VIEs of $1,678 million and accumulated depreciation of consolidated VIEs of $175 million at Duke Energy.

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(a)

During 2014, Duke Energy Ohio reduced the carrying amount of OVEC to zero. A charge of $94 million is recorded in Impairment Charges on Duke Energy Ohio's Consolidated Statement of Operations. In addition, Duke Energy Ohio has emission allowances and renewable energy certificates that have been reclassified to Assets Held For Sale pending the sale of the Disposal Group. See Note 17 for further information.

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(a)	The Subsidiary Registrants are charged their proportionate share of corporate governance and other shared services costs, primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. These amounts are recorded in Operation, maintenance and other on the Consolidated Statements of Operations and Comprehensive Income.

(b)	The Subsidiary Registrants incur expenses related to certain indemnification coverages through Bison, Duke Energy’s wholly owned captive insurance subsidiary. These expenses are recorded in Operation, maintenance and other on the Consolidated Statements of Operations and Comprehensive Income.

(c)

Duke Energy Carolinas and Duke Energy Progress participate in a JDA which allows the collective dispatch of power plants between the service territories to reduce customer rates. Revenues from the sale of power under the JDA are recorded in Operating Revenues on the Consolidated Statements of Operations and Comprehensive Income. Expenses from the purchase of power under the JDA are recorded in Fuel used in electric generation and purchased power on the Consolidated Statements of Operations and Comprehensive Income.

(d)

In 2013 and 2012, Progress Energy Service Company (PESC), a consolidated subsidiary of Progress Energy, charged a proportionate share of corporate governance and other costs to consolidated affiliates of Duke Energy. Corporate governance and other shared costs were primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. These charges were recorded as an offset to Operation, maintenance and other in the Consolidated Statements of Operations and Comprehensive Income. Effective January 1, 2014, PESC was contributed to Duke Energy Corporate Services (DECS), a consolidated subsidiary of Duke Energy, and these costs were no longer charged out of Progress Energy. Progress Energy recorded a non-cash after-tax equity transfer related to the contribution of PESC to DECS in its Consolidated Statements of Changes in Common Stockholder's Equity.

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(a)	Amounts at Duke Energy Ohio include intercompany positions that eliminate at Duke Energy.

(a)	Duke Energy includes amounts related to consolidated VIEs of $541 million at December 31, 2014 and $584 million at December 31, 2013.

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(b)	Included in Other and Assets held for Sale within Investments and Other Assets on the Consolidated Balance Sheet.

(c)	Included in Other and Liabilities Associated with Assets Held for Sale within Current Liabilities on the Consolidated Balance Sheet.

(d)	Included in Other and Liabilities Associated with Assets Held for Sale within Deferred Credits and Other Liabilities on the Consolidated Balance Sheet.

(e)	Included in Other within Current Assets on the Consolidated Balance Sheet.

(f)	Included in Other within Investments and Other Assets on the Consolidated Balance Sheet.

(g)	Included in Other within Current Liabilities on the Consolidated Balance Sheet.

(h)	Included in Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheet.

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(a)	Included in Other within Current Assets on the Consolidated Balance Sheet.

(b)	Included in Other within Investments and Other Assets on the Consolidated Balance Sheet.

(c)	Included in Other within Current Liabilities on the Consolidated Balance Sheet.

(d)	Included in Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheet.

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(b)	Included in Other within Investments and Other Assets on the Consolidated Balance Sheet.

(c)	Included in Other within Current Liabilities on the Consolidated Balance Sheet.

(d)	Included in Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheet.

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(b)	Included in Other within Investments and Other Assets on the Consolidated Balance Sheet.

(c)	Included in Other within Current Liabilities on the Consolidated Balance Sheet.

(d)	Included in Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheet.

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(a)	Effective with the merger, Duke Energy Progress no longer designates interest rate derivatives for regulated operations as cash flow hedges. As a result, the pretax losses on derivatives as of the date of the merger were reclassified from AOCI to Regulatory assets.

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(a)	Included in Other within Current Assets on the Consolidated Balance Sheet.

(b)	Included in Other within Investments and Other Assets on the Consolidated Balance Sheet.

(c)	Included in Other within Current Liabilities on the Consolidated Balance Sheet.

(d)	Included in Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheet.

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(a)	Effective with the merger, Duke Energy Florida no longer designates interest rate derivatives for regulated operations as cash flow hedges. As a result, the pretax losses on derivatives as of the date of the merger were reclassified from AOCI to Regulatory assets.

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(b)	Included in Other and Assets held for Sale within Investments and Other Assets on the Consolidated Balance Sheet.

(c)	Included in Other and Liabilities Associated with Assets Held for Sale within Current Liabilities on the Consolidated Balance Sheet.

(d)	Included in Other and Liabilities Associated with Assets Held for Sale within Deferred Credits and Other Liabilities on the Consolidated Balance Sheet.

(e)	Included in Other within Current Assets on the Consolidated Balance Sheet.

(f)	Included in Other within Investments and Other Assets on the Consolidated Balance Sheet.

(g)	Included in Other within Current Liabilities on the Consolidated Balance Sheet.

(h)	Included in Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheet.

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(a)	Included in Other within Current Assets on the Consolidated Balance Sheet.

(b)	Included in Other within Investments and Other Assets on the Consolidated Balance Sheet.

(c)	Included in Other within Current Liabilities on the Consolidated Balance Sheet.

(d)	Included in Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheet.

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(a)	These amounts are recorded in Other within Investments and Other Assets on the Consolidated Balance Sheets.

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(a)	These amounts are recorded in Other within Investments and Other Assets on the Consolidated Balance Sheets.

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(a)	These amounts are recorded in Other within Investments and Other Assets on the Consolidated Balance Sheets.

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(a)	These amounts are recorded in Other within Investments and Other Assets on the Consolidated Balance Sheets.

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(a)	These amounts are recorded in Other within Investments and Other Assets on the Consolidated Balance Sheets.

(a)	These amounts are recorded in Other within Investments and Other Assets on the Consolidated Balance Sheets.

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(a)	Restricted as collateral for non-recourse debt of VIEs.

(b)	Non-recourse to the general assets of the applicable registrant.

(c)	The amount for Progress Energy is equal to the amount for Duke Energy Progress Receivables Company, LLC (DEPR) and Duke Energy Florida Receivables Company, LLC (DEFR).

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(a)	Restricted as collateral for non-recourse debt of VIEs.

(b)	Non-recourse to the general assets of the applicable registrant.

(c)	The amount Progress Energy is equal to the amount for DEPR.

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(a)	Duke Energy Ohio recorded a pretax impairment charge of $94 million related to OVEC.

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(a)	Stock options and performance and unvested stock awards were not included in the dilutive securities calculation because either the option exercise prices were greater than the average market price of the common shares during those periods, or performance measures related to the awards had not yet been met.

(a)	Includes $5 million and $14 million of accelerated stock award expense and $2 million and $19 million of COBRA and health care reimbursement expenses for 2013 and 2012, respectively.

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(a)	Includes an increase in benefit obligation of $180 million as a result of changes in Duke Energy's mortality assumptions.

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(a)	Included in Other within Investments and Other Assets on the Consolidated Balance Sheets.

(b)	Included in Accrued pension and other post-retirement benefit costs on the Consolidated Balance Sheets.

(c)	Excludes accumulated other comprehensive income of $22 million and $16 million as of 2014 and 2013, respectively, net of tax, associated with a Brazilian retirement plan.

(a)	For Progress Energy plans, the assumptions used in 2012 to determine net periodic pension costs reflect remeasurement as of July 1, 2012, due to the merger between Duke Energy and Progress Energy.

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(a)	Includes an increase in benefit obligation of $21 million as a result of changes in Duke Energy's mortality assumptions.

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(a)	Included in Other within Current Liabilities on the Consolidated Balance Sheets.

(b)	Included in Accrued pension and other post-retirement benefit costs on the Consolidated Balance Sheets.

(a)	For Progress Energy plans, the assumptions used in 2012 to determine net periodic pension costs reflect remeasurement as of July 1, 2012, due to the merger between Duke Energy and Progress Energy.

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(a)	Includes an increase in benefit obligation of $7 million as a result of changes in Duke Energy's mortality assumptions.

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(a)	Included in Other within Current Liabilities on the Consolidated Balance Sheets.

(b)	Included in Accrued pension and other post-retirement benefit costs on the Consolidated Balance Sheets.

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(a)	For Progress Energy plans, the assumptions used in 2012 to determine net periodic post-retirement benefit costs reflect remeasurement as of July 1, 2012, due to the merger between Duke Energy and Progress Energy.

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(a)

Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio and Duke Energy Indiana were allocated approximately 28 percent, 31 percent, 15 percent, 16 percent, 5 percent and 8 percent, respectively, of the Duke Energy Master Retirement Trust assets at December 31, 2014. Accordingly, all Level 1, 2 and 3 amounts included in the table above are allocable to the Subsidiary Registrants using these percentages.

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(a)

Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio and Duke Energy Indiana were allocated approximately 28 percent, 35 percent, 16 percent, 16 percent, 5 percent and 8 percent, respectively, of the Duke Energy Master Retirement Trust assets at December 31, 2013. Accordingly, all Level 1, 2 and 3 amounts included in the table above are allocable to the Subsidiary Registrants using these percentages.

(a)	As of January 1, 2013, assets previously held in the Progress Energy Master Retirement Trust were transferred into the Duke Energy Master Retirement Trust.

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(a)	For 2014, amounts include the additional employer contribution of 4 percent of eligible pay per pay period for employees not eligible to participate in a defined benefit plan.

(a)	There were no benefits of net operating loss (NOL) carryforwards.

(b)	Includes utilization of NOL and tax credit carryforwards of $1,544 million at Duke Energy, $345 million at Duke Energy Carolinas, $530 million at Progress Energy, $291 million at Duke Energy Progress, $64 million at Duke Energy Florida, $56 million at Duke Energy Ohio and $141 million at Duke Energy Indiana.

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(a)	Includes benefits of NOL carryforwards of $808 million at Duke Energy, $458 million at Progress Energy, $64 million at Duke Energy Progress, $301 million at Duke Energy Florida and $179 million at Duke Energy Indiana.

(a)	Includes benefits of NOL carryforwards of $1,062 million at Duke Energy, $245 million at Duke Energy Carolinas, $357 million at Progress Energy, $257 million at Duke Energy Progress, $25 million at Duke Energy Florida, $34 million at Duke Energy Ohio and $205 million at Duke Energy Indiana.

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(a)	Includes a $57 million benefit as a result of the merger of two Chilean subsidiaries and a change in income tax rates in various countries primarily relating to Peru.

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(a)	Primarily related to capital lease obligations and debt fair value adjustments.

(a)	A valuation allowance of $79 million has been recorded on the state Net Operating Loss carryforwards, as presented in the Net Deferred Income Tax Liability Components table.

(b)	A valuation allowance of $105 million has been recorded on the foreign Net Operating Loss carryforwards, as presented in the Net Deferred Income Tax Liability Components table.

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(a)	Primarily related to capital lease obligations and debt fair value adjustments.

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(a)	Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida and Duke Energy Indiana are unable to estimate the specific amounts that would affect the effective tax rate versus the regulatory liability.

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(a)	Operating results reflect reclassifications due to the impact of discontinued operations (see Note 2 for further information).

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(a)	Revised retail rates became effective in January for Duke Energy Florida, May for Duke Energy Ohio, June for Duke Energy Progress and September for Duke Energy Carolinas (see Note 4 for further information).

(a)	Revised retail rates became effective in September in both North Carolina and South Carolina (see Note 4 for further information).

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(a)	Revised retail rates became effective in January in Florida and June in North Carolina (see Note 4 for further information).

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(a)	Revised retail rates became effective in June in North Carolina (see Note 4 for further information).

(a)	Revised retail rates became effective in January (see Note 4 for further information).

(a)	Operating results reflect reclassifications due to the impact of discontinued operations (see Note 2 for further information).

(a)	Revised retail rates became effective in May (see Note 4 for further information).

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(a)	Audit Fees are fees billed or expected to be billed for professional services for the audit of the Duke Energy Registrants’ financial statements included in the annual report on Form 10-K and the review of financial statements included in quarterly reports on

(b)	Audit-Related Fees are fees for assurance and related services that are reasonably related to the performance of an audit or review of financial statements, including assistance with acquisitions and divestitures and internal control reviews.

(c)	Tax Fees are fees for tax return assistance and preparation, tax examination assistance, and professional services related to tax planning and tax strategy.

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(a)	Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedules included in Part II of this annual report are as follows:

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