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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 costs and liabilities to comply with federal and state laws, regulations and legal requirements related to coal ash remediation, including amounts for required closure of certain ash impoundments, are uncertain and difficult to estimate;

◦	The ability to recover eligible costs, including amounts associated with coal ash impoundment retirement obligations and costs related to significant weather events, and to earn an adequate return on investment through the regulatory process;

◦	The costs of decommissioning Crystal River Unit 3 and other nuclear facilities could prove to be more extensive than amounts estimated and all costs may not be fully recoverable through the regulatory process;

◦	Credit ratings of the Duke Energy Registrants may be different from what is expected;

◦	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 variations in customer usage patterns, including energy efficiency efforts and use of alternative energy sources, including self-generation and distributed generation technologies;

◦	Federal and state regulations, laws and other efforts designed to promote and expand the use of energy efficiency measures and distributed generation technologies, such as rooftop solar and battery storage, in Duke Energy service territories could result in customers leaving the electric distribution system, excess generation resources as well as stranded costs;

◦	Advancements in technology;

◦	Additional competition in electric markets and continued industry consolidation;

◦	Political, economic and regulatory uncertainty in Brazil and 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, earthquakes and tornadoes;

◦	The ability to successfully operate electric generating facilities and deliver electricity to customers including direct or indirect effects to the company resulting from an incident that affects the U.S. electric grid or generating resources;

◦	The ability to complete necessary or desirable pipeline expansion or infrastructure projects in our natural gas business;

◦	Operational interruptions to our gas distribution and transmission activities;

◦	The impact on facilities and business from a terrorist attack, cybersecurity threats, data security breaches, and other catastrophic events such as fires, explosions, pandemic health events or other similar occurrences;

◦	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, interest rate fluctuations, 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;

◦

Construction and development risks associated with the completion of Duke Energy Registrants’ capital investment projects, 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;

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◦	The impact of potential goodwill impairments;

◦	The ability to successfully complete future merger, acquisition or divestiture plans, including the proposed sale of International Energy, excluding the equity investment in National Methanol Company; and

◦	The ability to successfully integrate the natural gas businesses since the acquisition of Piedmont Natural Gas Company, Inc. and realize anticipated benefits and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect.

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(a)	The $19 million change in Noncontrolling Interests for the nine months ended September 30, 2015, is primarily related to an acquisition of majority interest in a solar company.

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(a)	The (Loss) Income before income taxes includes the pretax impact of an $81 million charge for the agreement in principle reached in a lawsuit related to the Midwest Generation Disposal Group for the nine months ended September 30, 2015. Refer to Note 5 for further information related to the lawsuit.

(b)	Relates to discontinued operations of businesses not related to the Midwest Generation Disposal Group and includes indemnifications provided for certain legal, tax and environmental matters, and foreign currency translation adjustments.

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(a)	Other includes after-tax charges for costs to achieve mergers of $52 million, primarily due to interest expense related to the Piedmont acquisition financing, and cost savings initiatives of $12 million primarily due to severance costs.

(b)	Commercial Portfolio includes an after-tax impairment of $45 million related to certain equity method investments in renewable energy projects. See Note 13, Variable Interest Entities, for additional information.

(c)	Represents an income tax benefit resulting from deferred tax liability adjustments related to previously sold businesses. See Note 2, Acquisitions and Dispositions, for further information.

(a)	Regulated Utilities includes an after-tax charge of $56 million related to the Edwardsport settlement. See Note 4 for further information.

(b)	Other includes $15 million of after-tax costs to achieve the 2012 Progress Energy merger.

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(a)	Other includes after-tax charges for costs to achieve mergers of $195 million, primarily due to losses on forward-starting interest rate swaps related to the Piedmont acquisition, and cost savings initiatives of $39 million primarily due to severance costs. See Note 10 for additional information related to the swaps.

(b)	International Energy includes an after-tax impairment charge of $145 million. See Note 2 for additional information.

(c)	Commercial Portfolio includes an after-tax impairment of $45 million related to certain equity method investments in renewable energy projects. See Note 13, Variable Interest Entities, for additional information.

(d)	Includes income tax benefit of $122 million resulting from deferred tax liability adjustments related to previously sold businesses. See Note 2 for further information.

(a)	Regulated Utilities includes an after-tax charge of $56 million related to the Edwardsport settlement. Refer to Note 4 for further information.

(c)	Commercial Portfolio includes state tax expense of $41 million, resulting from changes to state apportionment factors due to the sale of the Midwest Generation Disposal Group, that does not qualify for discontinued operations. Refer to Note 2 for further information related to the sale.

(d)	Includes after-tax impact of $53 million for the settlement agreement reached in a lawsuit related to the Midwest Generation Disposal Group. Refer to Note 5 for further information related to the lawsuit.

(a)	Other for Progress Energy also includes interest expense on corporate debt instruments of $55 million and $166 million for the three and nine months ended September 30, 2016, respectively, and $61 million and $180 million for the three and nine months ended September 30, 2015, respectively.

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•	Electric Utilities and Infrastructure will be comprised of the regulated electric utilities in the Carolinas, Florida and the Midwest. This segment will also include the commercial transmission infrastructure investments.

•	Gas Utilities and Infrastructure will contain Piedmont, Duke Energy's local distribution companies in Ohio and Kentucky, and gas storage and pipeline investments.

•	Commercial Renewables will primarily include the company's non-regulated utility scale wind and solar generation assets.

•	International Energy will remain a segment until the divestiture is complete, although results of the equity method investment in NMC will be recast to Other in the fourth quarter of 2016.

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(a)	Remaining net book value amounts exclude any capitalized asset retirement costs.

(b)

In April 2016, Wabash River 6 terminated coal burning operations and is targeted for retirement by the end of 2016. The total net book value of $90 million for the retail portion of Wabash River Unit 6 and the retail portion of capitalized asset retirement costs for Wabash River Units 2 through 6 is classified as Generation facilities to be retired, net on Duke Energy Indiana's Condensed Consolidated Balance Sheet at September 30, 2016.

(c)	Duke Energy Indiana committed to either retire or stop burning coal at Gallagher Units 2 and 4 by December 31, 2022, as part of the settlement of Edwardsport IGCC matters.

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(a)	Proceeds were used to pay down outstanding commercial paper and for general corporate purposes.

(b)	Proceeds were used to fund capital expenditures for ongoing construction, capital maintenance and for general corporate purposes.

(c)	Proceeds were used to repay $325 million of unsecured debt due June 2016, $150 million of first mortgage bonds due July 2016 and for general corporate purposes.

(d)	Proceeds were used to fund capital expenditures for ongoing construction, capital maintenance, to repay short-term borrowings under the intercompany money pool borrowing arrangement and for general corporate purposes.

(e)	The nuclear asset-recovery bonds are sequential pay amortizing bonds. The maturity date above represents the scheduled final maturity date for the bonds.

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(a)	The interest rate includes country-specific risk premiums.

(b)	Includes capital lease obligations, amortizing debt and small bullet maturities.

(a)	Represents the sublimit of each borrower.

(b)	Duke Energy issued $625 million of commercial paper and loaned the proceeds through the money pool to Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio and Duke Energy Indiana. The balances are classified as Long-Term Debt Payable to Affiliated Companies in the Condensed Consolidated Balance Sheets.

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(a)	Primarily relates to decommissioning nuclear power facilities, closure of ash basins, asbestos removal, closure of landfills at fossil generation facilities, retirement of natural gas mains and removal of renewable energy generation assets.

(b)	For the nine months ended September 30, 2016, substantially all accretion expense relates to Duke Energy's regulated electric operations and has been deferred in accordance with regulatory accounting treatment.

(c)	Primarily relates to ash impoundment closures and nuclear decommissioning of Crystal River Unit 3.

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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 and employee benefits, information technology, legal and accounting fees, as well as other third-party costs. These amounts are recorded in Operation, maintenance and other on the Condensed 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 Condensed 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 Condensed 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 Condensed Consolidated Statements of Operations and Comprehensive Income.

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(a)	Duke Energy includes amounts related to consolidated VIEs of $789 million and $497 million as of September 30, 2016 and December 31, 2015, respectively. In August 2016, Duke Energy entered into $326 million of interest rate swaps related to the solar facilities financing described in Note 6, including $103 million of 4-year swaps and $223 million of 18-year swaps.

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(b)	Substantially all these amounts are considered other-than-temporary impairments on investments within Investment Trusts that have been recognized immediately as a regulatory asset.

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

(b)	Substantially all these amounts represent other-than-temporary impairments on investments within Investment Trusts that have been recognized immediately as a regulatory asset.

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(b)	Substantially all these amounts represent other-than-temporary impairments on investments within Investment Trusts that have been recognized immediately as a regulatory asset.

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(b)	Substantially all these amounts represent other-than-temporary impairments on investments within Investment Trusts that have been recognized immediately as a regulatory asset.

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(b)	Substantially all these amounts represent other-than-temporary impairments on investments within Investment Trusts that have been recognized immediately as a regulatory asset.

(c)	The decrease in estimated fair value of the NDTF as of September 30, 2016, is due to reimbursements from the NDTF for costs related to ongoing decommissioning activity of the Crystal Unit 3 Nuclear Plant.

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(b)	Substantially all these amounts represent other-than-temporary impairments on investments within Investment Trusts that have been recognized immediately as a regulatory asset.

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(a)	Performance stock awards were not included in the dilutive securities calculation because the performance measures related to the awards had not been met.

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•	Electric Utilities and Infrastructure will be comprised of the regulated electric utilities in the Carolinas, Florida and the Midwest. This segment will also include the commercial transmission infrastructure investments.

•	Gas Utilities and Infrastructure will contain Piedmont, Duke Energy's local distribution companies in Ohio and Kentucky, and gas storage and pipeline investments.

•	Commercial Renewables will primarily include the company's non-regulated utility scale wind and solar generation assets.

•	International Energy will remain a segment until the divestiture is complete, although results of the equity method investment in NMC will be recast to Other in the fourth quarter of 2016.

•	Costs to achieve mergers and International impairment represent charges that result from potential or completed strategic acquisitions and divestitures that do not reflect ongoing costs.

•	Cost savings initiatives represents severance charges related to company-wide initiatives to standardize processes and systems, leverage technology and workforce optimization, which are not representative of ongoing costs.

•	Commercial Renewables Impairment represents an other-than-temporary impairment of certain equity method investments. Management believes the impairment does not reflect an ongoing cost.

•	Edwardsport Settlement and Ash Basin Settlement represent charges related to settlement agreements with regulators and other governmental entities and do not represent ongoing costs.

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Midwest generation operations represents the operating results of the nonregulated Midwest generation business and Duke Energy Retail Sales (collectively, the Midwest Generation Disposal Group), which have been classified as discontinued operations. Management believes inclusion of the Midwest Generation Disposal Group's operating results within adjusted earnings and adjusted diluted EPS results in a better reflection of Duke Energy's financial performance during the period.

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(a)	Net of $32 million tax benefit.

(b)	Net of $7 million tax benefit. Primarily consists of severance costs.

(c)	Net of $26 million tax benefit. Impairment charge related to certain equity method investments. See Note 13 to the Condensed Consolidated Financial Statements, "Variable Interest Entities," for additional information.

(a)	Net of $9 million tax benefit.

(b)	Net of $34 million tax benefit.

(c)	Net of $3 million tax benefit.

•	Higher regulated results due to warmer weather in the current year, higher retail volumes and effective cost control efforts driving down operating expenses; as well as

•	Higher Commercial Portfolio earnings driven by additional wind farms placed in service and improved wind production.

•	The impact of a higher effective income tax rate.

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(a)	Net of $120 million tax benefit. Primarily consists of losses on forward-starting interest rate swaps related to the Piedmont acquisition financing.

(b)	Net of $49 million tax benefit. Impairment charge related to certain assets in Central America.

(c)	Net of $24 million tax benefit. Primarily consists of severance costs.

(d)	Net of $26 million tax benefit. Impairment charge related to certain equity method investments. See Note 13 to the Condensed Consolidated Financial Statements, "Variable Interest Entities," for additional information.

(a)	Net of $25 million tax benefit.

(b)	Net of $34 million tax benefit.

(c)	Net of $53 million tax benefit.

(d)	Net of $3 million tax benefit.

•	Lower operations and maintenance expense at Regulated Utilities driven by effective cost control efforts, partially offset by an increase in storm restoration costs including those related to severe winter storms in the Carolinas;

•	Higher retail revenues from pricing and riders, including energy efficiency programs;

•	Lower income tax expense as a result of the Company's intent to no longer indefinitely reinvest the foreign earnings of the International Energy segment combined with more efficient utilization of foreign tax credits. See Note 17 to the Condensed Consolidated Financial Statements, "Income Taxes," for additional information;

•	Higher results in Latin America primarily due to favorable hydrology in Brazil, partially offset by weaker foreign currency exchange rates;

•	Incremental earnings from the additional ownership interest in generating assets acquired from North Carolina Eastern Municipal Power Agency (NCEMPA); and

•	Reduction in weighted average shares outstanding primarily due to the prior-year accelerated stock repurchase.

•	Lower results due to the absence of earnings from the Midwest Generation Disposal Group sold in April 2015;

•	Increased depreciation and amortization expense primarily due to a higher amount of property, plant and equipment in service; and

•	Lower earnings from International Energy's equity method investment in NMC, primarily due to lower methyl tertiary butyl ether (MTBE) and methanol prices.

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•	a $154 million increase in electric retail sales, net of fuel revenue, due to favorable weather as compared to the prior year;

•	a $134 million increase in rider revenues, including amounts related to energy efficiency programs, Duke Energy Florida’s Nuclear Asset Securitization revenues beginning in 2016, the additional ownership interest in certain generating assets acquired from NCEMPA in the third quarter of 2015, and increased revenues related to Duke Energy Indiana’s clean coal equipment;

•	a $47 million increase in weather-normal sales volumes to retail customers (net of fuel revenue) reflecting increased demand; and

•	a $32 million increase in wholesale power revenues, primarily due to additional volumes and capacity charges for customers served under long-term contracts, including the NCEMPA wholesale contract that became effective August 1, 2015.

•	a $104 million decrease in fuel revenues driven by lower fuel prices included in electric rates.

•	a $98 million decrease in fuel expense (including purchased power and natural gas purchases for resale) primarily due to lower natural gas and coal prices, partially offset by increased generation due to higher sales volumes; and

•	an $85 million impairment charge in prior year related to the September 2015 Edwardsport IGCC settlement.

•	a $58 million increase in depreciation and amortization expense primarily due to additional plant in service, including the amortization of Duke Energy Florida's Crystal River 3 regulatory asset, and the additional ownership interest in generating assets acquired from NCEMPA in the third quarter of 2015; and

•	a $22 million increase in operations and maintenance expense primarily due to higher environmental and operational costs that are recoverable in rates, increased employee benefits costs, and higher storm restoration costs; partially offset by lower costs due to effective cost control efforts.

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•	a $739 million decrease in fuel revenues driven by lower fuel prices included in electric rates.

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a $275 million increase in rider revenues including increased revenues related to energy efficiency programs, the additional ownership interest in certain generating assets acquired from NCEMPA in the third quarter of 2015, and increased revenues related to Duke Energy Indiana’s clean coal equipment, and retail electric pricing primarily due to the expiration of the North Carolina cost of removal decrement rider;

•	an $84 million increase in wholesale power revenues, primarily due to additional volumes and capacity charges for customers served under long-term contracts, including the NCEMPA wholesale contract that became effective August 1, 2015; and

•	a $40 million increase in weather-normal sales volumes to retail customers (net of fuel revenue) reflecting retail sales growth.

•	a $725 million decrease in fuel expense (including purchased power and natural gas purchases for resale) primarily due to lower natural gas and coal prices and lower natural gas volumes to full-service retail natural gas customers; and

•	an $85 million impairment charge in prior year related to the September 2015 Edwardsport IGCC settlement.

•	a $102 million increase in depreciation and amortization expense primarily due to additional plant in service, including the expiration of the North Carolina cost of removal decrement rider, and the additional ownership interest in generating assets acquired from NCEMPA in the third quarter of 2015; and

•	a $45 million increase in property and other taxes primarily due to higher property taxes across multiple jurisdictions and higher sales and use tax at Duke Energy Indiana.

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•	a $39 million decrease in Central America due to lower average prices and volumes; and

•	a $9 million decrease in Peru due to lower hydrocarbon and energy sales volumes and average prices.

•	a $19 million increase in Brazil due to stronger foreign currency exchange rates and higher average contract prices.

•	a $34 million decrease in Central America due to lower fuel and purchased power costs; and

•	a $20 million decrease in Ecuador primarily due to the absence of a prior year impairment loss.

•	a $27 million increase in Brazil due to higher purchased power costs and stronger foreign currency exchange rates.

•	a $65 million decrease in Central America due to lower average prices; and

•	a $14 million decrease in Peru due to lower hydrocarbon average prices and volumes and lower energy sales volumes.

•	a $130 million increase in Central America due to the asset impairment, partially offset by lower purchased power and fuel costs; and

•	an $11 million increase in Peru due to higher purchased power costs, partially offset by lower hydrocarbon royalty costs.

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•	a $39 million decrease in Brazil due to lower purchased power costs resulting from improved hydrology and weaker foreign currency exchange rates, partially offset by higher variable costs; and

•	a $14 million decrease in Ecuador primarily due to the absence of a prior year impairment.

•	a $58 million increase in electric revenues due to growth in the REC Solar business; and

•	a $22 million increase in electric revenues from new wind and solar generation placed in service and improved wind production.

•	a $55 million increase in operating expenses due to growth in the REC Solar business; and

•	a $13 million increase in operating expenses from new wind and solar generation placed in service.

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•	a $115 million increase in electric revenues due to acquisition and growth of REC Solar; and

•	a $52 million increase in electric revenues from new wind and solar generation placed in service and improved wind production.

•	a $14 million decrease due to the shift of the residual Midwest Generation business out of Commercial Portfolio following the sale of the Midwest Generation Disposal Group.

•	a $111 million increase in operating expenses due to acquisition and growth of REC Solar; and

•	a $26 million increase in operating expenses from new wind and solar generation placed in service.

•	a $28 million decrease due to the shift of the residual Midwest generation business out of Commercial Portfolio following the sale of the Midwest Generation Disposal Group. See Note 3 to the Condensed Consolidated Financial Statements, “Business Segments,” for additional information.

•	a $71 million pretax impairment charge related to certain equity method investments in wind projects. See Note 13 to the Condensed Consolidated Financial Statements, "Variable Interest Entities," for additional information.

•	a $12 million increase in equity earnings from the Commercial Pipeline business.

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•	a $179 million decrease in fuel revenues driven by lower fuel prices included in electric retail and wholesale rates.

•	a $65 million increase in retail pricing and rate riders, which primarily reflects increased revenues related to energy efficiency programs and the expiration of the North Carolina cost of removal decrement rider;

•	a $35 million increase in electric sales, net of fuel revenues, to retail customers due to favorable weather compared to the prior year;

•	a $28 million increase in weather-normal electric sales, net of fuel revenues, to retail customers due to load growth; and

•	a $26 million increase in wholesale power revenues, net of sharing, primarily due to additional volumes for customers served under long-term contracts.

•	a $163 million decrease in fuel used in electric generation and purchased power primarily related to lower natural gas and coal prices, as well as a change in generation mix.

•	a $23 million increase in depreciation and amortization expense primarily due to higher amount of property, plant and equipment in service; and

•	a $13 million increase in operating and maintenance expense primarily due to higher storm restoration costs and severance expenses, partially offset by lower expenses at generating plants.

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•	a $469 million decrease in fuel and capacity revenues from retail customers primarily due to lower natural gas prices, changes in generation mix, and decreased demand from retail customers; partially offset by increased capacity rates to retail customers at Duke Energy Florida.

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a $124 million increase in rate riders, including increased revenues related to energy efficiency programs, the additional ownership interest in certain generating assets acquired from NCEMPA in the third quarter of 2015, higher nuclear asset securitization revenues in the current year, and an increase in energy conservation and environmental cost recovery clause revenues, partially offset by lower nuclear cost recovery clause rider revenues due to suspending recovery for the Levy nuclear project in 2015; and

•	a $34 million increase in wholesale power revenues primarily due to a new NCEMPA contract effective August 1, 2015, partially offset by lower peak demand at Duke Energy Progress and wholesale contracts that expired in the prior year at Duke Energy Florida.

•	a $441 million decrease in fuel used in electric generation and purchased power primarily due to lower natural gas prices, changes in generation mix, lower deferred fuel expense, and lower generation costs, partially offset by increased purchased power.

•	a $73 million increase in depreciation and amortization expense primarily due to additional plant in service, including the additional ownership interest in generating assets acquired from NCEMPA; and

•	a $27 million increase in operations and maintenance expense primarily due to an increase in costs recoverable through the energy conservation cost recovery clause and an increase in employee benefit costs, partially offset by a decrease in payroll and labor costs.

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•	a $166 million decrease in fuel revenues driven by lower natural gas prices and changes in generation mix;

•	a $12 million decrease in intercompany Joint Dispatch Agreement (JDA) coal blending revenues; and

•	a $7 million decrease in transmission revenues driven by lower volumes and a settlement with customers that reduced the rate of return on equity.

•	a $111 million increase in rider revenues due to a rider established in December 2015 to recover costs associated with the purchase of NCEMPA’s ownership interest in certain generating assets, and growth in rider revenues related to energy efficiency programs; and

•	a $52 million increase in wholesale power revenues primarily due to a new NCEMPA contract effective August 1, 2015, partially offset by lower peak demand.

•	a $167 million decrease in fuel used in electric generation and purchased power primarily due lower natural gas prices and changes in generation mix.

•	a $64 million increase in depreciation and amortization expenses primarily due to additional plant in service, including the additional ownership interest in generating assets acquired from NCEMPA in the third quarter of 2015; and

•	a $17 million increase in property and other taxes due to a 2015 North Carolina Franchise Tax refund and increases in current year property taxes in North Carolina and South Carolina.

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•	a $303 million decrease in fuel and capacity revenues primarily due to decreased fuel prices to retail customers, partially offset by increased capacity rates to retail customers; and

•	an $18 million decrease in wholesale power revenues primarily driven by contracts that expired in the prior year.

•	a $16 million increase in weather-normal sales volumes to retail customers in the current year;

•	a $15 million increase in other revenue primarily due to a transmission customer settlement charge taken in the prior year, increased transmission demand and higher transmission rates; and

•	a $13 million increase in rider revenues primarily due to nuclear asset securitization revenues beginning in 2016 and an increase in energy conservation cost recovery clause and environmental cost recovery clause revenues due to high recovery rates in 2016, partially offset by a decrease in nuclear cost recovery clause revenues due to suspending recovery of the Levy nuclear project in 2015.

•	a $274 million decrease in fuel used in electric generation and purchased power primarily due to lower deferred fuel expense and lower generation costs, partially offset by increased purchased power.

•	a $24 million increase in operations and maintenance expense primarily due to an increase in costs recoverable through the energy conservation cost recovery clause and an increase in employee benefit costs, partially offset by a decrease in payroll and labor costs.

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•	a $40 million decrease in fuel revenues driven by lower electric fuel and natural gas prices and decreased sales volumes; and

•	a $3 million decrease due to less favorable weather compared to the prior year.

•	a $23 million increase in the energy efficiency rider due to a prior year unfavorable regulatory order limiting the ability to utilize energy efficiency banked savings.

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•	a $46 million increase in retail pricing and rate rider revenues primarily due to increased revenues related to clean coal equipment and Edwardsport IGCC; and

•	a $29 million increase in wholesale revenues due to new contracts and higher demand.

•	a $71 million decrease in fuel revenues, including emission allowances, primarily due to a decrease in fuel prices.

•	an $89 million decrease in fuel used in electric generation and purchased power primarily due to lower fuel prices and the net benefit to expense of reduced purchased power and increased internal generation; and

•	an $85 million impairment charge in the prior year related to the September 2015 Edwardsport IGCC settlement.

•	a $26 million increase in property and other taxes, primarily driven by higher sales and use tax due to the partial reversal in 2015 of a tax reserve upon settlement of the matter;

•	a $25 million increase in depreciation and amortization expenses primarily due to a higher amount of property, plant and equipment in service; and

•	an $8 million impairment charge in the current year related to the early retirement of certain metering equipment.

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(a)	Represents the sublimit of each borrower.

(b)	Duke Energy issued $625 million of commercial paper and loaned the proceeds through the money pool to Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio and Duke Energy Indiana. The balances are classified as Long-Term Debt Payable to Affiliated Companies in the Condensed Consolidated Balance Sheets.

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(a)	The interest rate includes country-specific risk premiums.

(b)	Includes capital lease obligations, amortizing debt and small bullet maturities.

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•	a $422 million increase in working capital primarily due to higher property tax accruals due to timing of payments and lower coal stock inventory due to management of high inventory levels through less delivery receipts and higher utilization as a result of warmer than normal weather, partially offset by higher current year receivables;

•	a $235 million increase in payments for the closure of ash basins and nuclear decommissioning of Crystal River Unit 3.

•	a $2,792 million decrease in proceeds mainly due to prior year sale of the Midwest Generation Disposal Group to Dynegy Inc.;

•	a $718 million decrease in capital, investment and acquisition expenditures primarily due to the prior year purchase of NCEMPA ownership interests in certain generating assets.

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a $7,143 million increase in proceeds from net issuances of long-term debt mainly due to the issuance of $3,750 million of senior unsecured notes used to fund a portion of the Piedmont acquisition, $1,294 million of senior secured bonds used to finance the recovery of certain retired nuclear generation assets and other issuances primarily used to fund capital expenditures, pay down outstanding commercial paper and repay debt maturities; and

•	a $1,500 million decrease in cash outflows due to the prior year repurchase of 19.8 million common shares under the accelerated stock repurchase program.

•	a $534 million increase in net payments of notes payable and commercial paper, primarily due to repayment of commercial paper, partially offset by proceeds from the Term Loan used primarily to fund a portion of the Piedmont acquisition. These cash outflows were primarily made with proceeds from long-term debt issuances.

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(a)	Proceeds were used to pay down outstanding commercial paper and for general corporate purposes.

(b)	Proceeds were used to fund capital expenditures for ongoing construction, capital maintenance and for general corporate purposes.

(c)	Proceeds were used to repay $325 million of unsecured debt due June 2016, $150 million of first mortgage bonds due July 2016 and for general corporate purposes.

(d)	Proceeds were used to fund capital expenditures for ongoing construction, capital maintenance, to repay short-term borrowings under the intercompany money pool borrowing arrangement and for general corporate purposes.

(e)	The nuclear asset-recovery bonds are sequential pay amortizing bonds. The maturity date above represents the scheduled final maturity date for the bonds.

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