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•	State, federal and foreign legislative and regulatory initiatives, including costs of compliance with existing and future environmental requirements, including those related to 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 rate case proceedings and 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;

•	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 sustained downturns of the economy and the economic health of our service territories or variations in customer usage patterns, including energy efficiency efforts and use of alternative energy sources, such as 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 private 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 and natural gas markets and continued industry consolidation;

•	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, including extreme weather associated with climate change;

•	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 natural gas distribution and transmission activities;

•	The availability of adequate interstate pipeline transportation capacity and natural gas supply;

•	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 of nuclear facilities, including environmental, health, safety, regulatory and financial risks, including the financial stability of third-party service providers;

•	The timing and extent of changes in commodity prices and interest 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, compliance with debt covenants and conditions and general market and economic conditions;

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

•	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 the 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;

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•	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 new U.S. tax legislation to our financial condition, results of operations or cash flows and our credit ratings;

•	The impacts from potential impairments of goodwill or equity method investment carrying values;

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

•	The ability to implement our business strategy.

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(a)	Statistics related to all fuels reflect Electric Utilities and Infrastructure's ownership interest in jointly owned generation facilities.

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

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(a)	Represents approximately 7 percent of total system requirements for 2017 and 2016 and 6 percent for 2015.

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(b)	Amounts include 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)	Duke Energy Florida received reimbursements from the NDTF for costs related to ongoing decommissioning activity of Crystal River Unit 3.

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(a)	An increase of approximately $38 million in revenues was effective January 1, 2017, and an additional increase of approximately $18.5 million in revenues was effective January 1, 2018. Duke Energy Progress amortized approximately $18.5 million from the cost of removal reserve in 2017.

(b)	On November 22, 2017, Duke Energy Progress and the North Carolina Public Staff filed an Agreement and Stipulation of Partial Settlement resolving certain portions of the proceeding, pending NCUC approval.

(c)	Represents portions in the original 2017 rate case application not covered by the Agreement and Stipulation of Partial Settlement.

(d)	Represents the requested effective dates in the filings. Actual effective dates may differ based on orders from the respective commission.

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(a)	Under the rate stabilization adjustment mechanism, Piedmont resets rates in South Carolina based on updated costs and revenues on an annual basis.

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(c)	Cumulative investment amounts through October 31, 2017. A ruling from the TPUC is pending.

•	Regulations of the FERC affect the certification and siting of new interstate natural gas pipeline projects, the purchase and sale of, the prices paid for, and the terms and conditions of service for the interstate transportation and storage of natural gas.

•	Regulations of the PHMSA affect the design, construction, operation, maintenance, integrity, safety and security of natural gas distribution and transmission systems.

•

Regulations of the EPA relate to the environment including proposed air emissions regulations that would expand to include emissions of methane. For a discussion of environmental regulation, see “Environmental Matters” in this section. Refer to “Other Matters” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion about potential Global Climate Change legislation and other EPA regulations under development and the potential impacts such legislation and regulation could have on Duke Energy’s operations.

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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 navigable waters.

•	The Comprehensive Environmental Response, Compensation and Liability Act, which can require any individual or entity that currently owns or in the past 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 National Environmental Policy Act, which requires federal agencies to consider potential environmental impacts in their permitting and licensing decisions, including siting approvals.

•	Coal Ash Act, as amended, which establishes requirements regarding the use and closure of existing ash basins, the disposal of ash at active coal plants and the handling of surface water and groundwater impacts from ash basins in North Carolina.

•	The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act (RCRA), which creates a framework for the proper management of hazardous and nonhazardous solid waste; classifies CCR as nonhazardous waste; and establishes standards for landfill and surface impoundment placement, design, operation and closure, groundwater monitoring, corrective action, and post-closure care.

•	The Toxic Substances Control Act (TSCA), which gives EPA the authority to require reporting, recordkeeping and testing requirements, and to place restrictions relating to chemical substances and/or mixtures, including polychlorinated biphenyls.

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•	weather conditions, including abnormally mild winter or summer weather that cause lower energy or natural gas usage for heating or cooling purposes, as applicable, 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 natural 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, natural 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. Duke Energy Carolinas' ownership is 19.25 percent of the facility.

(b)	Duke Energy Indiana owns and operates Gibson Station Units 1 through 4 and is a joint owner of unit 5 with Wabash Valley Power Association, Inc. (WVPA) and Indiana Municipal Power Agency. Duke Energy Indiana operates unit 5 and owns 50.05 percent.

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(a)

Significant transactions reflected in the results above include: (i) the sale of the International Disposal Group in 2016, including a loss on sale recorded within discontinued operations (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”) (ii) the acquisition of Piedmont in 2016, including losses on interest rate swaps related to the acquisition financing (see Note 2); (iii) 2014 impairment related to the disposal of the Midwest Generation Disposal Group; (iv) 2014 incremental tax expense resulting from the decision to repatriate all cumulative historical undistributed foreign earnings; (v) 2014 increase in the litigation reserve related to a criminal investigation of the Dan River release; (vi) 2013 charges related to Crystal River Unit 3 and nuclear development costs; and (vii) costs to achieve mergers in all periods.

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(a)	See Results of Operations below for Duke Energy’s definition of adjusted earnings and adjusted earnings per 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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•	Transformation of the customer experience to meet changing customer expectations through enhanced convenience, control and choice in energy supply and usage.

•	Modernization of the electric grid, including smart meters, storm hardening, self-healing and targeted undergrounding to ensure the system is better prepared for severe weather and to improve the system's reliability and flexibility, as well as to provide better information and services for customers.

•	Generation of cleaner energy through an increased amount of natural gas, renewables generation and the continued safe and reliable operation of nuclear plants.

•	Expansion of natural gas infrastructure, from midstream gas pipelines to local distribution systems.

•	Operational excellence through engagement with employees and being an industry leader in safety performance and efficient operations.

•	Stakeholder engagement to ensure the regulatory rules in the states in which Duke Energy operates benefit customers and allow Duke Energy to recover its significant investments in a timely manner while maintaining affordable rates.

•	Engagement with regulatory commissions to determine the regulatory treatment of the impact of the Tax Act.

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•	Duke Energy Indiana's $1.4 billion grid modernization plan, which is aimed at improving reliability, including fewer outages and quicker restoration.

•	Significant investments in combined-cycle natural gas plants, including completing the $1.5 billion Citrus County plant in Florida, the $600 million W.S. Lee facility in South Carolina and the $900 million investment in the Western Carolinas Modernization Project. These investments will allow Duke Energy to replace older, less efficient coal units.

•	Duke Energy expects to continue to advance other cleaner energy sources within its regulated electric jurisdictions, including hydro, wind, solar and combined heat and power projects, increasing the flexibility of the system and allowing Duke Energy to continue lowering carbon emissions.

◦	In North Carolina, HB 589 provides a timely cost recovery mechanism for any solar investments we are able to make through a competitive market process.

◦

In Florida, as part of the comprehensive multi-year rate settlement, we committed to invest in approximately 700 MW of solar capacity over the next five years and will be authorized to recover the cost of that investment through a single issue base rate increase. We also advanced our strategic priority of energy grid investment, establishing a multiyear recovery method for $1 billion of grid investments.

•	With the acquisition of Piedmont, Duke Energy now operates natural gas distribution businesses across five states. The continued integration of Piedmont, as well as additional investments in the natural gas Local Distribution Company (LDC) system, will help maintain system integrity and expand natural gas distribution to new customers.

•	Duke Energy will continue to grow its midstream pipeline business, underpinned by investments in the Atlantic Coast Pipeline, Sabal Trail and Constitution pipeline projects. These highly contracted pipelines will bring much needed, low-cost natural gas supplies to the eastern U.S., spurring economic growth and helping Duke Energy to grow its customer base in the Southeast.

•	Costs to Achieve Mergers represents charges that result from strategic acquisitions.

•	Cost Savings Initiatives represent severance charges related to company-wide initiatives, excluding merger integration, to standardize processes and systems, leverage technology and workforce optimization.

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•	Regulatory Settlements in 2017 represent charges related to the Levy nuclear project in Florida and the Mayo Zero Liquid Discharge and Sutton combustion turbine projects in North Carolina. The 2015 amount represents charges related to the IGCC Settlement.

•	Commercial Renewables Impairments represent other-than-temporary, asset and goodwill impairments.

•	Impacts of the Tax Act represent estimated amounts recognized related to the Tax Cuts and Jobs Act.

•	Ash Basin Settlement and Penalties represent charges related to Plea Agreements and settlement agreements with regulators and other governmental entities.

(a)	For 2016, includes a loss on sale of the International Disposal Group. Represents the GAAP reported Loss from Discontinued Operations, less the International Disposal Group operating results, which are included in adjusted earnings.

(b)

For 2015, includes the impact of a litigation reserve related to the Midwest Generation Disposal Group. Represents (i) GAAP reported Income from Discontinued Operations, less the International Disposal Group operating results and Midwest Generation Disposal Group operating results, which are included in adjusted earnings, and (ii) a state tax charge resulting from the completion of the sale of the Midwest Generation Disposal Group but not reported as discontinued operations.

(c)

The Tax Act reduced the corporate income tax rate from 35 percent to 21 percent, effective January 1, 2018. As the tax change was enacted in 2017, Duke Energy is required to remeasure its existing deferred tax assets and liabilities at the lower rate. For Duke Energy's regulated operations, where the reduction in the net accumulated deferred income tax liability is expected to be returned to customers in future rates, the remeasurement has been deferred as a regulatory liability.

•	Lower regulated electric revenues of $0.26 per share due to less favorable weather in the current year, including lost revenues related to Hurricane Irma;

•	The prior year operating results from the International Disposal Group, which was sold in December 2016. The 2016 operating results included a benefit from the valuation of deferred income taxes. See Note 22 to the Consolidated Financial Statements, Income Taxes," for additional information;

•	Higher financing costs, primarily due to the Piedmont acquisition; and

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•	Higher depreciation and amortization expense at Electric Utilities and Infrastructure primarily due to higher depreciable base.

•	Higher regulated electric revenues from increased pricing and riders driven by new rates in Duke Energy Progress South Carolina, base rate adjustments in Florida and energy efficiency rider revenues in North Carolina, as well as growth in weather-normal retail volumes;

•	Lower operations, maintenance and other expenses, net of amounts recoverable in rates, at Electric Utilities and Infrastructure resulting from ongoing cost efficiency efforts and lower year-to-date storm costs than the prior year; and

•	Additional earnings from incremental investments in Atlantic Coast Pipeline, LLC (ACP) and Sabal Trail natural gas pipelines.

•	More favorable weather in 2016 compared to 2015;

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

•	Strong operations and maintenance cost control at Electric Utilities and Infrastructure; and

•	Piedmont’s earnings contribution subsequent to the acquisition in October 2016.

•	Higher storm costs at Electric Utilities and Infrastructure due to significant 2016 storms;

•	Higher interest expense related to additional debt outstanding; and

•	Higher depreciation and amortization expense at Electric Utilities and Infrastructure primarily due to higher depreciable base.

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(a)	Except where noted below, amounts are included within Income Tax Expense From Continuing Operations on the Consolidated Statement of Operations.

(b)	See Note 4 and Note 22 to the Consolidated Financial Statements, "Regulatory Matters" and "Income Taxes," for information about the Tax Act's impact on Duke Energy's Consolidated Balance Sheets.

(c)	Amount primarily relates to the remeasurement of net deferred tax liabilities that are excluded for ratemaking purposes related to abandoned or impaired assets and certain wholesale fixed rate contracts.

(d)	Includes a $16 million expense recorded within Equity in earnings (losses) of unconsolidated affiliates on the Consolidated Statement of Operations.

(e)	Amount primarily relates to the remeasurement of net deferred tax liabilities that relates to equity method investments and certain wholesale fixed rate contracts.

(f)	Amount primarily relates to the remeasurement of Foreign Tax Credits, federal net operating losses and non-regulated deferred tax assets.

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•	a $292 million decrease in retail sales, net of fuel revenue, due to less favorable weather in the current year; and

•	a $235 million decrease in fuel revenues driven by lower retail sales volumes, lower fuel prices included in rates and changes in the generation mix.

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a $364 million increase in rider revenues including increased revenues related to energy efficiency programs, Duke Energy Florida’s nuclear asset securitization, Midwest transmission and distribution capital investments and Duke Energy Indiana’s Edwardsport Integrated Gasification Combined Cycle (IGCC) plant, as well as an increase in retail pricing due to base rate adjustments for Duke Energy Florida’s Osprey acquisition and Hines Chillers and the Duke Energy Progress South Carolina rate case;

•	an $86 million increase in weather-normal sales volumes to customers; and

•	a $26 million increase in other revenues primarily due to favorable transmission revenues.

•	a $160 million increase in impairment charges primarily due to the write-off of remaining unrecovered Levy Nuclear Project costs in the current year at Duke Energy Florida and the disallowance from rate base of certain projects at the Mayo and Sutton plants in the current year at Duke Energy Progress related to the partial settlement in the North Carolina rate case;

•	a $216 million decrease in fuel expense (including purchased power) primarily due to lower retail sales and changes in the generation mix; and

•	a $96 million decrease in operation, maintenance and other expense primarily due to lower plant outage, storm restoration and labor and benefits costs partially offset by higher operational costs that are recoverable in rates.

•	a $768 million decrease in fuel revenues driven by lower fuel prices included in rates.

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a $414 million increase in rider revenues including increased revenues related to energy efficiency programs, the additional ownership interest in generating assets acquired from NCEMPA in the third quarter of 2015 and increased revenues related to Duke Energy Indiana’s clean coal equipment, and increased retail electric pricing primarily due to the expiration of the North Carolina cost of removal decrement rider;

•	a $101 million increase in retail sales, net of fuel revenue, due to favorable weather compared to the prior year; and

•	a $76 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.

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•	a $713 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 volumes of coal and oil, partially offset by higher volumes of natural gas; and

•	an $85 million decrease in pretax impairment charges in the prior year primarily due to the 2015 Edwardsport IGCC settlement.

•	a $162 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, as well as the expiration of the North Carolina cost of removal decrement rider; and

•	a $154 million increase in operations and maintenance expense primarily due to higher environmental and operational costs that are recoverable in rates, increased employee benefit costs, and higher storm restoration costs, partially offset by lower costs due to effective cost control efforts.

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(a)	Includes throughput subsequent to Duke Energy's acquisition of Piedmont on October 3, 2016.

•	an $884 million increase in operating revenues due to the inclusion of Piedmont's operating revenues beginning in October 2016; and

•	a $47 million increase in Piedmont's fourth quarter results due to colder weather, higher natural gas prices, Integrity Management Rider (IMR) rate adjustments, customer growth and new power generation customers.

•	a $686 million increase in operating expenses due to the inclusion of Piedmont's operating expenses beginning in October 2016; and

•	a $34 million increase in Piedmont's fourth quarter results primarily due to higher natural gas costs passed through to customers due to the higher price per dekatherm of natural gas.

•	a $398 million increase in operating revenues due to the inclusion of Piedmont's operating revenues beginning in October 2016,

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•	a $38 million decrease in fuel revenues driven by lower natural gas prices and decreased sales volumes for Midwest operations.

•	a $276 million increase in operating expenses due to the inclusion of Piedmont's operating expenses beginning in October 2016.

•	a $38 million decrease in the cost of natural gas, primarily due to decreased volumes and lower natural gas prices for Midwest operations.

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(a)	Except where noted below, amounts are included within Income Tax Expense From Continuing Operations or Income Tax Expense on the Consolidated Statement of Operations and Comprehensive Income.

(b)	See Notes 4 and 22 to the Consolidated Financial Statements, "Regulatory Matters" and "Income Taxes," for information about the Tax Act's impact on Duke Energy's Consolidated Balance Sheets.

(c)	Amount primarily relates to the remeasurement of deferred tax liabilities that are excluded for ratemaking purposes related to abandoned assets and certain wholesale fixed rate contracts.

(d)	Amount primarily relates to the remeasurement of deferred tax liabilities of certain wholesale fixed rate contracts.

(e)	Amount primarily relates to the remeasurement of deferred tax assets that are excluded for ratemaking purposes related to a prior transfer of certain electric generating assets.

(f)	Amount primarily relates to the remeasurement of deferred tax liabilities that are excluded for ratemaking purposes related to impaired assets.

(g)	Includes a $16 million expense recorded within Equity in earnings (losses) of unconsolidated affiliates on the Consolidated Statement of Operations and Comprehensive Income.

(h)	The decrease in the effective tax rate was primarily due to the impact of the Tax Act and lower North Carolina corporate tax rates.

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•	a $179 million decrease in retail sales, net of fuel revenues, due to less favorable weather in the current year.

•	a $74 million increase in rider revenues and retail pricing primarily related to energy efficiency programs;

•	a $41 million increase in weather-normal sales volumes to retail customers, net of fuel revenues;

•	a $30 million increase in fuel revenues primarily due to changes in generation mix partially offset by lower retail sales; and

•	a $7 million increase in wholesale power revenues, net of sharing and fuel, primarily due to additional volumes for customers served under long-term contracts.

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•	a $145 million decrease in operations, maintenance and other expense primarily due to lower expenses at generating plants, lower costs associated with merger commitments related to the Piedmont acquisition in 2016, lower severance expenses, and lower employee benefit costs, partially offset by higher energy efficiency program costs.

•	a $25 million increase in fuel expense (including purchased power) primarily due to changes in generation mix, partially offset by lower retail sales; and

•	a $15 million increase in depreciation and amortization expense primarily due to additional plant in service, partially offset by lower amortization of certain regulatory assets.

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•	a $231 million decrease in fuel revenues primarily due to lower retail sales and changes in generation mix at Duke Energy Progress; and

•	an $87 million decrease in retail sales, net of fuel revenues, due to less favorable weather in the current year.

•	a $108 million increase in retail pricing primarily due to Duke Energy Florida’s base rate adjustment for the Osprey Acquisition and the completion of the Hines Energy Complex Chiller Uprate Project, as well as the Duke Energy Progress South Carolina rate case;

•	a $76 million increase in rider revenues related to energy efficiency programs at Duke Energy Progress, as well as nuclear asset securitization beginning in July 2016 and extended uprate project revenues beginning in 2017 at Duke Energy Florida; and

•	a $51 million increase in weather-normal sales volumes to retail customers.

•	a $227 million decrease in fuel expense and purchased power primarily due to lower retail sales and changes in generation mix at Duke Energy Progress; and

•	a $166 million decrease in operations, maintenance and other expense primarily due to lower plant outage, storm restoration and labor costs.

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•	a $149 million increase in impairment charges primarily due to the write-off of remaining unrecovered Levy Nuclear Project costs in the current year at Duke Energy Florida and the disallowance from rate base of certain projects at the Mayo and Sutton plants in the current year at Duke Energy Progress related to the partial settlement in the North Carolina rate case; and

•	a $72 million increase in depreciation and amortization expense primarily due to additional plant in service, as well as nuclear regulatory asset amortization at Duke Energy Florida.

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•	a $238 million decrease in fuel revenues due to lower retail sales and changes in generation mix; and

•	a $37 million decrease in retail sales, net of fuel revenues, due to less favorable weather in the current year, partially offset by lower lost revenues related to hurricanes in the current year.

•	a $40 million increase in rider revenues primarily due to energy efficiency programs;

•	a $38 million increase in retail sales due to the South Carolina rate case; and

•	a $31 million increase in wholesale power revenues, net of fuel, primarily due to higher peak demand.

•	a $221 million decrease in fuel used in electric generation and purchased power primarily due to lower retail sales and changes in generation mix; and

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•	a $115 million decrease in operation, maintenance and other expense primarily due to lower nuclear outage costs and lower storm restoration costs.

•	a $22 million increase in depreciation and amortization expense primarily due to additional plant in service; and

•	an $18 million increase in impairment charges primarily due to the disallowance from rate base of certain projects at the Mayo and Sutton plants in the current year related to the partial settlement in the North Carolina rate case.

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•	a $70 million increase in retail pricing primarily due to the base rate adjustment for the Osprey acquisition and the completion of the Hines Energy Complex Chiller Uprate Project;

•	a $45 million increase in weather-normal sales volumes to retail customers in the current year; and

•	a $36 million increase in rider revenues primarily due to nuclear asset securitization beginning in July 2016 and extended power uprate project revenues beginning in 2017.

•	a $50 million decrease in retail sales, net of fuel revenues, due to less favorable weather in the current year, including lost revenues related to Hurricane Irma; and

•	a $34 million decrease in wholesale power revenues primarily due to contracts that expired in the prior year.

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•	a $132 million increase in impairment charges primarily due to the write-off of remaining unrecovered Levy Nuclear Project costs in the current year; and

•	a $51 million increase in depreciation and amortization expense primarily due to nuclear regulatory asset amortization, as well as additional plant in service.

•	a $47 million decrease in operations and maintenance expense primarily due to lower planned outage costs, lower severance expenses and lower employee benefit costs, partially offset by higher storm restoration costs in the current year.

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•	a $69 million decrease in fuel revenues primarily due to lower electric fuel costs and a decrease in electric and natural gas sales volumes; and

•	a $16 million decrease in electric retail sales, net of fuel revenues, due to less favorable weather in the current year.

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•	a $38 million increase in rider revenues primarily due to growth in energy efficiency programs and a rate increase for the distribution capital investment rider, partially offset by a decrease in the percentage of income payment plan rider due to a rate decrease;

•	a $10 million increase in PJM Interconnection, LLC (PJM) transmission revenues;

•	a $9 million increase in other revenues related to OVEC; and

•	a $6 million increase in non-native sales for resale.

•	a $66 million decrease in fuel expense, primarily due to lower sales volumes and lower electric fuel costs.

•	a $28 million increase in depreciation and amortization expense due to additional plant in service and a true-up related to SmartGrid assets in the prior year;

•	a $20 million increase in property and other taxes due to higher property taxes; and

•	a $12 million increase in operations, maintenance and other expense primarily due to higher energy efficiency program costs and higher transmission and distribution operations costs; partially offset by lower fossil/hydro operations costs due to timing of outage schedules.

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•	a $67 million increase in rate rider revenues primarily related to the Edwardsport IGCC plant, the Transmission, Distribution and Storage System Improvement Charge (TDSIC) and energy efficiency programs; and

•	a $48 million increase in fuel revenues primarily due to higher purchased power costs passed through to customers and higher financial transmission rights (FTR) revenues.

•	a $13 million decrease in retail sales due to less favorable weather in the current year; and

•	a $13 million decrease in wholesale power revenues, net of fuel, primarily due to a decrease in demand rates and contracts that expired in the current year.

•	a $57 million increase in fuel used in electric generation and purchased power expenses, primarily due to higher purchased power volumes, partially offset by favorable fuel prices;

•	an $18 million increase in property and other taxes primarily due to higher franchise taxes;

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•	a $10 million increase in operations, maintenance and other expense primarily due to growth in energy efficiency programs and higher transmission costs; and

•	a $10 million increase in impairments and other charges primarily due to the impairment of certain metering equipment not recoverable in customer rates.

•	a $38 million decrease in depreciation and amortization primarily due to the recognition of certain asset retirement obligations in 2016 that were subsequently deferred in 2017, partially offset by new IGCC rates that result in a lower deferral amount and higher depreciation due to additional plant in service.

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•	a $74 million increase due to higher natural gas costs passed through to customers primarily due to higher natural gas prices;

•	a $34 million increase in revenues to residential and commercial customers, net of natural gas costs passed through to customers, primarily due to Integrity Management Rider (IMR) rate adjustments and customer growth. Increase is also due to new power generation customers, and is partially offset by wholesale marketing revenue; and

•	a $10 million increase in revenues due to merger-related bill credits applied to customer bills in 2016.

•	a $73 million increase in costs of natural gas primarily due to higher natural gas costs passed through to customers due to the higher price per dekatherm of natural gas;

•	a $15 million increase in depreciation expense and property and franchise taxes due to additional plant in service; and

•	a $7 million increase due to an impairment of software resulting from planned accounting system and process integration in 2018.

•	a $38 million decrease in operations, maintenance and other related to acquisition and integration expenses recorded in the prior year from costs paid to outside parties, primarily financial and legal advisory, severance expenses, retention costs and acceleration of incentive plans, and an accrual for our commitment of charitable contributions and community support.

•	a $132 million decrease in gain on sale of unconsolidated affiliates recorded in the prior year due to Piedmont’s sale of its 15 percent ownership interest in SouthStar Energy Services, LLC (SouthStar) on October 3, 2016; and

•	a $32 million decrease in equity in (losses) earnings of unconsolidated affiliates primarily due to equity earnings from the investment in SouthStar in the prior year and the impacts of the Tax Act in the current year.

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(a)	Excludes capital leases. Duke Energy projects a reduction in short-term debt in 2020.

(b)	Subject to approval by the Board of Directors.

(c)	Duke Energy projects an increase in short-term debt in 2018 and 2019.

(d)	2018 equity issuances to be achieved through a public offering and through issuances under the Equity Distribution Agreement and the Dividend Reinvestment Program (DRIP). See Note 18 to the Consolidated Financial Statements, "Common Stock" for additional information.

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(a)	In January 2018, Moody's revised the ratings outlook for Duke Energy Corporation and Piedmont from stable to negative, principally due to risk of deterioration in credit metrics resulting from the Tax Act. See the Tax Cuts and Jobs Act section above for additional information on the Tax Act.

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•	a $1,325 million decrease in working capital due to weather, payment of merger transaction and integration related costs and increased property tax payments in 2017.

•	a $969 million increase in net income after non-cash adjustments primarily due to the inclusion of Piedmont's earnings for a full year, favorable pricing and weather-normal retail volumes driven by the residential class in the Electric Utilities and Infrastructure Segment combined with continued strong cost control;

•	a $136 million decrease in contributions to qualified pension plans; and

•	a $37 million decrease in payments to AROs.

•	a $388 million increase in cash flows from working capital primarily due to the sale of the International business; and

•	a $147 million decrease in contributions to qualified pension plans.

•	a $262 million increase in payments for AROs; and

•	a $156 million decrease in net income after non-cash adjustments due to higher storm costs offset by favorable weather, increased rider revenues, higher wholesale margins and strong cost control.

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•	a $5,017 million decrease in capital, investment and acquisition expenditures mainly due to the Piedmont acquisition in the prior year.

•	a $1,418 million decrease in net proceeds from sales of discontinued operations due to the prior year sale of the International business.

•	a $4,852 million increase in capital, investment and acquisition expenditures mainly due to the Piedmont acquisition; and

•	a $1,550 million decrease in net proceeds from sales of discontinued operations mainly due to the variance in proceeds between the 2015 sale of the Midwest generation business and the 2016 sale of the International business.

•

a $2,722 million net decrease in proceeds from issuances of long-term debt driven principally by the prior year $3,750 million of senior unsecured notes used to fund a portion of the Piedmont acquisition, offset primarily by $900 million of first mortgage bonds issued by Duke Energy Florida in the current year to fund capital expenditures for ongoing construction and capital maintenance and for general corporate purposes;

•	a $731 million decrease in proceeds from stock issuances used to fund a portion of the Piedmont acquisition in 2016; and

•	a $118 million current year increase in dividends paid.

•	a $1,085 million decrease in net borrowings from notes payable and commercial paper primarily due to the use of proceeds from $1,294 million nuclear asset-recovery bonds issued at Duke Energy Florida in 2016 to pay down outstanding commercial paper.

•	a $7,389 million increase in proceeds from net issuances of long-term debt mainly due to the issuances of $3,750 million of senior unsecured notes used to fund a portion of the Piedmont acquisition, $1,294 million of nuclear asset-recovery bonds and other issuances primarily used to fund capital expenditures, pay down outstanding commercial paper and repay debt maturities;

•	a $1,500 million decrease in cash outflows due to the 2015 repurchase of 19.8 million common shares under the ASR; and

•	a $714 million increase in proceeds resulting from the issuance of common stock to fund the acquisition of Piedmont.

•

a $2,692 million increase in cash outflows for the net payments of notes payable and commercial paper primarily through the use of proceeds from $1,294 million nuclear asset-recovery bonds issued at Duke Energy Florida, further increased by the use of short-term debt in 2015 to repay long-term debt maturities at Duke Energy Florida in advance of the 2016 proceeds from the nuclear asset-recovery bonds.

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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, 2017, 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. Amounts exclude contingent lease obligations.

(d)	Current liabilities, except for current maturities of long-term debt, and purchase obligations reflected on 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, 2017, 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)	Amounts exclude obligations under the OVEC purchase power agreement. See Note 17 to the Consolidated Financial Statements, "Variable Interest Entities," for additional information.

(g)

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, wind and solar facilities, plant refurbishments, maintenance and day-to-day contract work and commitments to buy certain products. Amount excludes certain open purchase orders for services that are provided on demand, for which the timing of the purchase cannot be determined.

(h)	Related to future annual funding obligations to NDTF through nuclear power stations' relicensing dates. See Note 9 to the Consolidated Financial Statements, "Asset Retirement Obligations."

(i)	Unrecognized tax benefits of $25 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."

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(j)

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"), AROs, 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 ITCs 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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(a)	Noncontrolling Interests amount is primarily related to the acquisitions of a majority interest in a provider of energy management systems and services for commercial customers and a solar company.

(b)	Foreign Currency Translation Adjustments amount includes $620 million of cumulative adjustment realized as a result of the sale of the Latin American generation business. See Note 2 to the Consolidated Financial Statements.

(c)	Noncontrolling Interests amount is primarily related to the sale of the Latin American generation business. See Note 2 to the Consolidated Financial Statements.

(d)	Retained Earnings relates to a cumulative-effect adjustment due to implementation of a new accounting standard related to stock-based compensation and the associated income taxes. See Note 1 to the Consolidated Financial Statements for additional information. Noncontrolling Interests relates to the purchase of remaining interest in REC Solar.

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(a)	Piedmont's weighted average depreciation rate was 2.4 percent, 2.4 percent, and 2.5 percent for the annualized two months ended December 31, 2016 and for the years ended October 31, 2016 and 2015, respectively.

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(a)	Piedmont's excise taxes were immaterial for the two months ended December 31, 2016, and $2 million for the years ended October 31, 2016, and 2015.

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•	Interest expense of $234 million related to the acquisition financing, including realized losses on forward-starting interest rate swaps of $190 million. See Note 14 for additional information on the swaps.

•	Charges of $104 million related to commitments made in conjunction with the transaction, including charitable contributions and a one-time bill credit to Piedmont customers. $10 million was recorded as a reduction in Operating Revenues, with the remaining $94 million recorded within Operation, maintenance and other.

•	Other transaction and integration costs of $101 million recorded to Operation, maintenance and other, including professional fees and severance.

•	$3.75 billion of long-term debt issued in August 2016.

•	$750 million borrowed under the $1.5 billion short-term loan facility in September 2016, which was repaid in December 2016.

•	10.6 million shares of common stock issued in October 2016 for net cash proceeds of approximately $723 million.

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(a)	Relates to previously sold businesses not related to the Disposal Groups. The amount for 2016 represents an income tax benefit resulting from immaterial out of period deferred tax liability adjustments. The amount for 2015 includes indemnifications provided for certain legal, tax and environmental matters and foreign currency translation adjustments.

•

On December 20, 2016, Duke Energy closed on the sale of its ownership interests in businesses in Argentina, Chile, Ecuador, El Salvador, Guatemala and Peru to I Squared Capital. The assets sold included approximately 2,230 MW of hydroelectric and natural gas generation capacity, transmission infrastructure and natural gas processing facilities. I Squared Capital purchased the businesses for an enterprise value of $1.2 billion.

•	On December 29, 2016, Duke Energy closed on the sale of its Brazilian business, which included approximately 2,090 MW of hydroelectric generation capacity, to CTG for an enterprise value of $1.2 billion. With the closing of the CTG deal, Duke Energy finalized its exit from the Latin American market.

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(a)	Upon meeting the criteria for assets held for sale, beginning in the fourth quarter of 2016 depreciation expense was ceased.

(b)

In conjunction with the advancements of marketing efforts during 2016, Duke Energy performed recoverability tests of the long-lived asset groups of International Energy. As a result, Duke Energy determined the carrying value of certain assets in Central America was not fully recoverable and recorded a pretax impairment charge of $194 million. The charge represents the excess of carrying value over the estimated fair value of the assets, which was based on a Level 3 Fair Value measurement that was primarily determined from the income approach using discounted cash flows but also considered market information obtained in 2016.

(c)	The pretax loss on disposal includes the recognition of cumulative foreign currency translation losses of $620 million as of the disposal date. See the Consolidated Statements of Changes in Equity for additional information.

(d)	Pretax (Loss) Income attributable to Duke Energy Corporation was $(445) million and $221 million for the years ended December 31, 2016 and 2015, respectively.

(e)	2016 amount includes $126 million of income tax expense on the disposal, which primarily reflects in-country taxes incurred as a result of the sale. The after-tax loss on disposal was $640 million.

(f)	2016 amount includes an income tax benefit of $95 million. See Note 22, "Income Taxes," for additional information.

(a)	The Loss on disposal includes impairments recorded to adjust the carrying amount of the assets to the estimated fair value of the business, based on the selling price to Dynegy less cost to sell.

(b)	2015 amounts include the impact of an $81 million charge for the settlement agreement reached in a lawsuit related to the Midwest Generation Disposal Group. Refer to Note 5 for further information about the lawsuit.

(c)	2016 amounts result from immaterial out of period deferred tax liability adjustments.

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(a)	All segments include impacts of the Tax Cuts and Jobs Act (the Tax Act). Electric Utilities and Infrastructure includes a $231 million benefit, Gas Utilities and Infrastructure includes a $26 million benefit, Commercial Renewables includes a $442 million benefit and Other includes charges of $597 million.

(b)	Electric Utilities and Infrastructure includes after-tax regulatory settlement charges of $98 million. See Note 4 for additional information.

(c)	Commercial Renewables includes after-tax impairment charges of $74 million related to certain wind projects and the Energy Management Solutions reporting unit. See Notes 10 and 11 for additional information.

(d)	Other includes $64 million of after-tax costs to achieve the Piedmont merger. See Note 2 for additional information.

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(b)	Other includes $329 million of after-tax costs to achieve mergers. Refer to Note 2 for additional information on costs related to the Piedmont merger.

(c)	Other includes after-tax charges of $57 million related to cost savings initiatives. Refer to Note 19 for further information.

(d)	Includes a loss on sale of the International Disposal Group. Refer to Note 2 for further information.

(e)	Other includes $26 million of capital investments expenditures related to the International Disposal Group. Gas Utilities and Infrastructure includes the Piedmont acquisition of $5 billion. Refer to Note 2 for more information on the Piedmont acquisition.

(a)	Electric Utilities and Infrastructure includes an after-tax charge of $58 million related to the Edwardsport settlement. Refer to Note 4 for further information.

(b)	Other includes $60 million of after-tax costs to achieve mergers.

(c)	Other includes after-tax charges of $77 million related to cost savings initiatives. Refer to Note 19 for further information.

(d)	Includes the impact of a settlement agreement reached in a lawsuit related to the Midwest Generation Disposal Group. Refer to Note 5 for further information related to the lawsuit and Note 2 for further information on discontinued operations.

(e)	Other includes capital investment expenditures of $45 million related to the International Disposal Group.

(f)	Other includes Assets Held for Sale balances related to the International Disposal Group. Refer to Note 2 for further information.

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(a)	Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b)	The expected recovery or refund period varies or has not been determined.

(c)	Included in rate base.

(d)	Includes regulatory liabilities related to the change in the North Carolina tax rate discussed in Note 22.

(e)	Earns a return on outstanding balance in North Carolina.

(f)	Pays interest on over-recovered costs in North Carolina. Includes certain purchased power costs in North Carolina and South Carolina and costs of distributed energy in South Carolina.

(g)	Recovered over the life of the associated assets.

(h)	Includes incentives on DSM/EE investments and is recovered through an annual rider mechanism.

(i)	Earns a debt return on coal ash expenditures for North Carolina and South Carolina retail customers.

(j)	Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 21 for additional detail.

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(a)	Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b)	The expected recovery or refund period varies or has not been determined.

(c)	Recovery period for costs related to nuclear facilities runs through the decommissioning period of each unit.

(d)	Recovery over the life of the associated assets. Includes regulatory liabilities related to the change in the North Carolina tax rate discussed in Note 22.

(e)	South Carolina storm costs are included in rate base.

(f)	Included in rate base.

(g)	Pays interest on over-recovered costs in North Carolina. Includes certain purchased power costs in North Carolina and South Carolina and costs of distributed energy in South Carolina.

(h)	South Carolina retail allocated costs are earning a return.

(i)	Earns a debt return on coal ash expenditures for North Carolina and South Carolina retail customers.

(j)	Includes incentives on DSM/EE investments.

(k)	Recovered over the life of the associated assets.

(l)	Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 21 for additional detail.

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(a)	Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b)	The expected recovery or refund period varies or has not been determined.

(c)	Included in rate base.

(d)	Recovery over the life of the associated assets.

(e)	Certain costs earn a return.

(f)	Earns a debt return/interest once collections begin.

(g)	Earns commercial paper rate.

(h)	Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 21 for additional detail.

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(a)	Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b)	The expected recovery or refund period varies or has not been determined.

(c)	Included in rate base.

(d)	Recovery over the life of the associated assets.

(e)	Recovered via a rider mechanism.

(f)	Includes incentives on DSM/EE investments.

(g)	Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 21 for additional detail.

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(a)	Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b)	The expected recovery or refund period varies or has not been determined.

(c)	Included in rate base.

(d)	Recovery over the life of the associated assets.

(e)	Includes incentives on DSM/EE investments and is recovered through a tracker mechanism over a two-year period.

(f)	The IURC authorized Duke Energy Indiana to recover costs incurred to buy out a gasification services agreement, including carrying costs through 2017.

(g)	Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 21 for additional detail.

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(a)	Regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b)	The expected recovery or refund period varies or has not been determined.

(c)	Included in rate base.

(d)	Recovery over the life of the associated assets.

(e)	Balance will fluctuate with changes in the market. Current contracts extend into 2031.

(f)	Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 21 for additional detail.

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(a)	Duke Energy Carolinas will retire Allen Steam Station Units 1 through 3 by December 31, 2024, as part of the resolution of a lawsuit involving alleged New Source Review violations.

(b)	Duke Energy Florida expects to retire these coal units by the end of 2018 to comply with environmental regulations.

(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)	Substantially all electric utility property is mortgaged under mortgage bond indentures.

(b)	Duke Energy includes $81 million and $603 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 $625 million that was classified as Long-Term Debt on the Consolidated Balance Sheets due to the existence of long-term credit facilities that backstop 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 for Duke Energy's commercial paper program was 14 days.

(e)	Duke Energy includes $1,509 million and $176 million in purchase accounting adjustments related to Progress Energy and Piedmont, respectively.

(f)	Duke Energy includes $47 million in purchase accounting adjustments primarily related to the merger with Progress Energy.

(g)	Refer to Note 17 for additional information on amounts from consolidated VIEs.

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(a)	Substantially all electric utility property is mortgaged under mortgage bond indentures.

(b)	Duke Energy includes $98 million and $670 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 $625 million that was classified as Long-Term Debt on the Consolidated Balance Sheets due to the existence of long-term credit facilities that backstop 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 for Duke Energy and Piedmont's commercial paper programs were 14 days and eight days, respectively.

(e)	Progress Energy amount includes a $1 billion intercompany loan related to the sale of the International Disposal Group. See Note 2 for further discussion of the sale.

(f)	Duke Energy includes $1,653 million and $197 million purchase accounting adjustments related to the mergers with Progress Energy and Piedmont, respectively.

(g)	Duke Energy includes $53 million in purchase accounting adjustments primarily related to the merger with Progress Energy.

(h)	Refer to Note 17 for additional information on amounts from consolidated VIEs.

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

(b)	Debt has a floating interest rate.

(a)	Excludes $1,732 million in purchase accounting adjustments related to the Progress Energy merger and the Piedmont acquisition.

(a)	Progress Energy amounts are equal to Duke Energy Progress amounts.

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(a)	Proceeds were used to refinance $400 million of unsecured debt at maturity and to repay a portion of outstanding commercial paper.

(b)	Debt issued to repay a portion of outstanding commercial paper.

(c)	Debt issued to repay at maturity $700 million of unsecured debt, to repay outstanding commercial paper and for general corporate purposes.

(d)	Debt issued to fund storm restoration costs related to Hurricane Irma and for general corporate purposes.

(e)	Portfolio financing of four Texas and Oklahoma wind facilities. Duke Energy pledged substantially all of the assets of these wind facilities and is nonrecourse to Duke Energy. Proceeds were used to reimburse Duke Energy for a portion of previously funded construction expenditures.

(f)	Portfolio financing of eight solar facilities located in California, Colorado and New Mexico. Duke Energy pledged substantially all of the assets of these solar facilities and is nonrecourse to Duke Energy. Proceeds were used to reimburse Duke Energy for a portion of previously funded construction expenditures.

(g)	Debt issued to fund capital expenditures for ongoing construction and capital maintenance, to repay a $250 million aggregate principal amount of bonds at maturity and for general corporate purposes.

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

(i)	Debt issued to repay at maturity a $200 million aggregate principal amount of bonds at maturity, pay down intercompany short-term debt and for general corporate purposes, including capital expenditures.

(j)	Debt issued to refinance $400 million aggregate principal amount of bonds due January 2018, pay down intercompany short-term debt and for general corporate purposes.

(k)	Principal balance will be repaid in equal quarterly installments beginning in March 2018.

(l)	Debt issuance has a floating interest rate.

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

(b)	Proceeds were used to finance a portion of the Piedmont acquisition. The $4.9 billion Bridge Facility was terminated following the issuance of this debt. See Note 2 for additional information on the Piedmont acquisition.

(c)

DEFPF issued nuclear-asset recovery bonds and used the proceeds to acquire nuclear-asset recovery property from its parent, Duke Energy Florida. The nuclear-asset recovery bonds are payable only from and secured by the nuclear asset-recovery property. DEFPF is consolidated for financial reporting purposes; however, the nuclear asset-recovery bonds do not constitute a debt, liability or other legal obligation of, or interest in, Duke Energy Florida or any of its affiliates other than DEFPF. The assets of DEFPF, including the nuclear-asset recovery property, are not available to pay creditors of Duke Energy Florida or any of its affiliates. Duke Energy Florida used the proceeds from the sale to repay short-term borrowings under the intercompany money pool borrowing arrangement and make an equity distribution of $649 million to the ultimate parent, Duke Energy (Parent), which repaid short-term borrowings. The nuclear-asset recovery bonds are sequential pay amortizing bonds. The maturity date above represents the scheduled final maturity date for the bonds. See Notes 4 and 17 for additional information.

(d)

Emerald State Solar, LLC, an indirect wholly owned subsidiary of Duke Energy entered into portfolio financing of approximately 22 North Carolina solar facilities. Tranche A of $228 million is secured by substantially all of the assets of the solar facilities and is nonrecourse to Duke Energy. Tranche B of $105 million is secured by an Equity Contribution Agreement with Duke Energy. Proceeds were used to reimburse Duke Energy for a portion of previously funded construction expenditures related to the Emerald State Solar, LLC portfolio. The initial interest rate on the loans was six months London Interbank Offered Rate (LIBOR) plus an applicable margin of 1.75 percent plus a 0.125 percent increase every three years thereafter. In connection with this debt issuance, Emerald State Solar, LLC entered into two interest rate swaps to convert the substantial majority of the loan interest payments from variable rates to fixed rates of approximately 1.81 percent for Tranche A and 1.38 percent for Tranche B, plus the applicable margin. See Note 14 for further information on the notional amounts of the interest rate swaps.

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

(f)	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.

(g)	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.

(h)	Proceeds were used to repay at maturity $350 million aggregate principal amount of certain bonds due December 2016, as well as to fund capital expenditures for ongoing construction and capital maintenance and for general corporate purposes.

(i)	Debt issuance has a floating interest rate.

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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 Consolidated Balance Sheets.

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

(b)	Jointly owned with NCEMC.

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

(d)	Jointly owned with Wabash Valley Power Association, Inc. (WVPA) and Indiana Municipal Power Agency.

(e)	Jointly owned with WVPA.

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(a)	Duke Energy amount includes purchase accounting adjustments related to the merger with Progress Energy.

(b)	Primarily includes obligations related to asbestos removal. Duke Energy Ohio and Piedmont also include AROs related to the retirement of natural gas mains and services. Duke Energy includes AROs related to the removal of renewable energy generation assets.

(a)	Amounts for Progress Energy equal the sum of Duke Energy Progress and Duke Energy Florida.

(b)	Amounts include the Subsidiary Registrant's 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 amount relates to the Piedmont acquisition. See Note 2 for additional information.

(b)	Substantially all accretion expense for the years ended December 31, 2017, and 2016 relates to Duke Energy’s regulated electric operations and has been deferred in accordance with regulatory accounting treatment.

(c)	Amounts primarily relate to ash impoundment closures and nuclear decommissioning of Crystal River Unit 3.

(d)	Amounts primarily relate to AROs recorded as a result of state agency closure requirements at Duke Energy Indiana.

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(a)	Includes a pretax impairment charge of $58 million on a wholly owned non-contracted wind project. See discussion below.

(b)

Includes capitalized leases of $1,294 million, $81 million, $272 million, $139 million, $133 million, $80 million and $35 million at Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio and Duke Energy Indiana, respectively, primarily within Plant – Regulated. The Progress Energy, Duke Energy Progress and Duke Energy Florida amounts are net of $114 million, $11 million and $103 million, respectively, of accumulated amortization of capitalized leases.

(c)	Includes $2,113 million, $1,283 million, $831 million and $831 million of accumulated amortization of nuclear fuel at Duke Energy, Duke Energy Carolinas, Progress Energy and Duke Energy Progress, respectively.

(d)	Includes accumulated amortization of capitalized leases of $57 million, $11 million, $21 million and $9 million at Duke Energy, Duke Energy Carolinas, Duke Energy Ohio and Duke Energy Indiana, respectively.

(e)	Includes gross property, plant and equipment cost of consolidated VIEs of $3,941 million and accumulated depreciation of consolidated VIEs of $598 million at Duke Energy.

(a)

Includes capitalized leases of $1,355 million, $40 million, $288 million, $142 million, $146 million, $81 million and $35 million at Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio and Duke Energy Indiana, respectively, primarily within Plant – Regulated. The Progress Energy, Duke Energy Progress and Duke Energy Florida amounts are net of $99 million, $9 million and $90 million, respectively, of accumulated amortization of capitalized leases.

(b)	Includes $1,922 million, $1,192 million, $730 million and $730 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 $50 million, $9 million, $19 million and $8 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 $2,591 million and accumulated depreciation of consolidated VIEs of $411 million at Duke Energy.

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(a)	Duke Energy evaluated the recoverability of goodwill during 2017 and recorded impairment charges of $29 million related to the Energy Management Solutions reporting unit within the Commercial Renewables segment. The fair value of the reporting unit was determined based on the market approach.

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(a)	During the year ended December 31, 2017, Piedmont transferred its share of ownership interest in ACP and Constitution to a wholly owned subsidiary of Duke Energy at book value.

(b)	Piedmont owns the Cardinal, Pine Needle and Hardy Storage investments.

(c)	Duke Energy includes purchase accounting adjustments related to Piedmont.

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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, information technology, legal and accounting fees, as well as other third-party costs. These amounts are primarily 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 and expenses from the purchase of power pursuant to the JDA are recorded in Operating Revenues and Fuel used in electric generation and purchased power, respectively, on the Consolidated Statements of Operations and Comprehensive Income.

(d)

Piedmont provides long-term natural gas delivery service to certain Duke Energy Carolinas and Duke Energy Progress natural gas-fired generation facilities. Piedmont records the sales in Regulated natural gas revenues, and Duke Energy Carolinas and Duke Energy Progress record the related purchases in Fuel used in electric generation and purchased power on their respective Consolidated Statements of Operations and Comprehensive Income. The amounts are not eliminated in accordance with rate-based accounting regulations. For the two months ended December 31, 2016, and for sales made subsequent to the acquisition for the year ended October 31, 2016, Piedmont recorded $14 million and $7 million, respectively, of natural gas sales with Duke Energy. For sales made prior to the acquisition for the year ended October 31, 2016, and for the year ended October 31, 2015, Piedmont recorded $74 million and $83 million, respectively of natural gas sales with Duke Energy.

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(a)

Duke Energy includes amounts related to consolidated VIEs of $660 million and $750 million at December 31, 2017, and 2016, respectively. During 2016, Duke Energy entered into interest rate swaps related to solar financing with an outstanding notional amount of $300 million, including $81 million of four-year swaps and $219 million of 18-year swaps, at December 31, 2016. See note 6 for additional information related to the solar facilities financing.

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(a)	During the year ended December 31, 2017, Duke Energy Florida continued to receive reimbursements from the NDTF for costs related to ongoing decommissioning activity of the Crystal River Unit 3 nuclear plant.

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(a)

Duke Energy holds a 50 percent equity interest in Duke-American Transmission Company, LLC (DATC). As of December 31, 2016, DATC was considered a VIE due to having insufficient equity to finance its own activities without subordinated financial support. However, DATC is no longer considered a VIE based on sufficient equity to finance its own activities, and, therefore, is no longer considered a VIE as of December 31, 2017. Duke Energy's investment in DATC was $46 million at December 31, 2017.

(a)	In April 2017, Piedmont transferred its non-consolidated VIE investments to a wholly owned subsidiary of Duke Energy. See Note 12 and the "Pipeline Investments" section below for additional detail.

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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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(a)	Piedmont severance benefit costs were $3 million for the two months ended December 31, 2016, and $19 million for the year ended October 31, 2016. Piedmont did not record any severance benefit costs for the year ended October 31, 2015.

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(a)	Piedmont contributed $10 million to its U.S. qualified defined benefit pension plan during the two months ended December 31, 2016, and for each of the years ended October 31, 2016, and 2015, respectively.

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(a)	Duke Energy amounts exclude $7 million, $8 million and $9 million for the years ended December 2017, 2016 and 2015, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006.

(b)	Duke Energy Ohio amounts exclude $3 million, $4 million and $4 million for the years ended December 2017, 2016 and 2015, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006.

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

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(a)	Duke Energy amounts exclude $7 million, $8 million and $10 million for the years ended December 2017, 2016 and 2015, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006.

(b)	Duke Energy Ohio amounts exclude $2 million, $2 million and $3 million for the years ended December 2017, 2016 and 2015, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006.

(c)	Curtailment credit resulted from a reduction in average future service of plan participants due to a plan amendment.

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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)	Excludes Piedmont Pension Assets, which had a targeted asset allocation of 60 percent return-seeking and 40 percent liability hedging fixed-income. Actual asset allocations were 61 percent return-seeking and 39 percent liability hedging fixed-income at December 31, 2016.

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(a)

Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio, Duke Energy Indiana, and Piedmont were allocated approximately 27 percent, 30 percent, 15 percent, 15 percent, 5 percent, 8 percent, and 4 percent, respectively, of the Duke Energy Master Retirement Trust at December 31, 2017. Accordingly, all amounts included in the table above are allocable to the Subsidiary Registrants using these percentages.

(b)	Certain investments that are measured at fair value using the net asset value per share practical expedient have not been categorized in the fair value hierarchy.

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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 27 percent, 30 percent, 15 percent, 15 percent, 5 percent and 8 percent, respectively, of the Duke Energy Master Retirement Trust and Piedmont's Pension assets at December 31, 2016. Accordingly, all amounts included in the table above are allocable to the Subsidiary Registrants using these percentages.

(b)	Certain investments that are measured at fair value using the net asset value per share practical expedient have not been categorized in the fair value hierarchy.

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(a)	Piedmont's pretax employer matching contributions were $1 million, $7 million and $7 million during the two months ended December 31, 2016 and for the years ended October 31, 2016 and 2015, respectively.

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(a)

Includes utilization of NOL (Net operating loss) carryforwards and tax credit carryforwards of $428 million at Duke Energy, $74 million at Progress Energy, $36 million at Duke Energy Florida, $17 million at Duke Energy Ohio, $42 million at Duke Energy Indiana and $79 million at Piedmont. In addition the total deferred income taxes Includes benefits of NOL carryforwards and tax credit carryforwards of $10 million at Duke Energy Carolinas and $1 million at Duke Energy Progress.

(b)	As a result of the Tax Act, Duke Energy's deferred tax assets and liabilities were revalued as of December 31, 2017. See the Statutory Rate Reconciliation section below for additional information on the Tax Act's impact on income tax expense.

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(a)	Includes benefits of NOL carryforwards and utilization of NOL and tax credit carryforwards of $648 million at Duke Energy, $4 million at Duke Energy Carolinas, $190 million at Progress Energy, $60 million at Duke Energy Progress, $49 million at Duke Energy Florida, $26 million at Duke Energy Ohio and $58 million at Duke Energy Indiana.

(a)	Includes utilization of NOL carryforwards and tax credit carryforwards of $264 million at Duke Energy, $15 million at Duke Energy Carolinas, $119 million at Progress Energy, $21 million at Duke Energy Progress, $84 million at Duke Energy Florida, $3 million at Duke Energy Ohio and $45 million at Duke Energy Indiana.

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(a)	Includes benefits of NOL and tax carryforwards of $17 million and $91 million for the two months ended December 31, 2016, and the year ended October 31, 2016, respectively.

(b)	Includes benefits and utilization of NOL carryforwards of $46 million for the year ended October 31, 2015.

(a)	Includes a $16 million expense in 2017 related to the Tax Act impact on equity earnings included within Equity in earnings (losses) of unconsolidated affiliates on the Consolidated Statement of Operations.

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(a)	Amounts primarily include but are not limited to items that are excluded for ratemaking purposes related to abandoned or impaired assets, certain wholesale fixed rate contracts, remeasurement of nonregulated net deferred tax liabilities, Federal net operating losses, and valuation allowance on foreign tax credits.

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

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(a)	A valuation allowance of $90 million has been recorded on the state NOL carryforwards, as presented in the Net Deferred Income Tax Liability Components table.

(b)	A valuation allowance of $13 million has been recorded on the foreign NOL carryforwards, as presented in the Net Deferred Income Tax Liability Components table.

(c)	A valuation allowance of $416 million has been recorded on the foreign tax credits, as presented in the Net Deferred Income Tax Liability Components table.

(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, Duke Energy Indiana and Piedmont are unable to estimate the specific amounts that would affect the effective tax rate versus the regulatory liability.

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(2)

Includes restricted stock units and performance shares (assuming the maximum payout level) granted under the Duke Energy Corporation 2010 Long-Term Incentive Plan or the Duke Energy Corporation 2015 Long-Term Incentive Plan, as well as shares that could be payable with respect to certain compensation deferred under the Duke Energy Corporation Executive Savings Plan (Executive Savings Plan) or the Duke Energy Corporation Directors' Savings Plan (Directors’ Savings Plan).

(3)	Includes shares remaining available for issuance pursuant to stock awards under the Duke Energy Corporation 2015 Long-Term Incentive Plan.

(4)

Includes shares that could be payable with respect to certain compensation deferred under the Executive Savings Plan or and the Directors' Savings Plan, each of which is a nonqualified deferred compensation plan described in more detail below. Upon the acquisition of Piedmont Natural Gas Company, Inc., performance shares granted prior to such acquisition under the Piedmont Natural Gas Company, Inc. Incentive Compensation Plan were converted into restricted stock units payable in shares of Duke Energy common stock. As of December 31, 2017, 45,173 such restricted stock units were outstanding. Following the acquisition, no further stock awards were permitted to be granted under the Piedmont Natural Gas Company, Inc. Incentive Compensation Plan. These converted awards are not listed in the table above.

(5)	The number of shares remaining available for future issuance under equity compensation plans not approved by security holders cannot be determined because it is based on the amount of future voluntary deferrals, if any, under the Executive Savings Plan and the Directors' Savings Plan.

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(a)	Audit Fees are fees billed, or expected to be billed, by Deloitte for professional services for the financial statement audits, audit of the Duke Energy Registrants’ financial statements included in the Annual Report on Form 10-K, reviews of financial statements included in Quarterly Reports on Form 10‑Q, and services associated with securities filings such as comfort letters and consents.

(b)	Audit-Related Fees are fees billed, or expected to be billed, by Deloitte for assurance and related services that are reasonably related to the performance of an audit or review of financial statements, including statutory reporting requirements.

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

(d)	Other Fees are billed by Deloitte for attendance at Deloitte-sponsored conferences and access to Deloitte research tools and subscription services. In 2016, Other Fees also included non-audit fees related to consulting services.

(e)	Includes all accounting fees and services paid prior to and subsequent to the acquisition. Prior to the acquisition, Piedmont's Audit Committee preapproved all services provided by the independent auditor.

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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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