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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 obtain the necessary permits and approvals and 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, operational accidents, information technology failures or 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 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; and

◦	The ability to implement our business strategy, including enhancing existing technology systems.

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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 2018, 2017 and 2016.

(b)	These agreements include approximately 412 MW of firm capacity under contract by Duke Energy Florida with QFs.

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

(b)	Decommissioning cost for Duke Energy Carolinas reflects its ownership interest in jointly owned reactors. Other joint owners are responsible for decommissioning costs related to their interest in the reactors.

(c)	Duke Energy Carolinas' site-specific nuclear decommissioning cost study completed in 2018 is expected to be filed with the NCUC and PSCSC by the second quarter 2019. Duke Energy Carolinas will also complete a new funding study, which will be completed and filed with the NCUC and PSCSC in 2019.

(d)	Duke Energy Florida's site-specific nuclear decommissioning cost study and a new funding study were completed and filed with the FPSC in 2018. For the years ended December 31, 2017 and December 31, 2018, 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 $19 million in revenues was effective January 1, 2018.

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•	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.

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•

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 the “Other Matters” section of Management's Discussion and Analysis 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 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 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.

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•	The Solid Waste Disposal Act, as amended by the 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 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.

•	The proposed ACE rule, which will require states to develop CO2 reduction plans based on efficiency (heat rate) improvements at coal-fired power plants.

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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;

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•	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, NCEMC and PMPA. Duke Energy Carolinas' ownership is 19.25 percent of the facility.

(b)	Jointly owned with NCEMC. Duke Energy Carolinas' ownership is 86.67 percent of the facility.

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

(d)	Includes Cayuga Internal Combustion.

(e)	Jointly owned with WVPA. Duke Energy Indiana's ownership is 62.50 percent of the facility.

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(a)	Commercial Renewables owns 47 percent of Sweetwater IV and V and 50 percent of Ironwood, Cimarron II and Mesquite Creek.

(b)	Shoreham and certain projects included in Other small solar are in tax-equity structures where investors have differing interests in the project's economic attributes. 100 percent of the tax-equity project's capacity is included in the table above.

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(a)

Significant transactions reflected in the results above include: (i) regulatory and legislative charges related to Duke Energy Progress and Duke Energy Carolinas North Carolina rate case orders and impairment charges in 2018 (see Notes 4, 11 and 12 to the Consolidated Financial Statements, "Regulatory Matters," "Goodwill and Intangible Assets" and "Investments in Unconsolidated Affiliates"); (ii) 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”); (iii) the acquisition of Piedmont in 2016, including losses on interest rate swaps related to the acquisition financing (see Note 2); (iv) 2014 impairment related to the disposal of the Midwest Generation Disposal Group; (v) 2014 incremental tax expense resulting from the decision to repatriate all cumulative historical undistributed foreign earnings; (vi) 2014 increase in the litigation reserve related to a criminal investigation of the Dan River release.

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(a)	See Results of Operations below for Duke Energy’s definition of adjusted earnings and adjusted diluted 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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•	Continuing to place the customer at the center of all that we do.

•	Advancing the achievement of modernized regulatory constructs across all jurisdictions, including consideration of cost recovery models that break the link between load growth and earnings.

•	Improving and strengthening the energy grid to provide customers with more control, convenience and communications, and make the grid more resilient to severe weather and ever-evolving cyber threats.

•	Investing in both natural gas generation and infrastructure to support our growing gas system, as we replace coal units and continue to expand our LDC customer base in the Carolinas and Midwest.

•	Increasing renewables, energy storage and next-generation demand-side management into our supply/demand resource plans, in pursuit of a growth strategy that leverages these resources to provide choices that our customers value.

•	Modernizing the way we plan and build our generation, transmission, distribution and customer systems in a fully integrated way through Integrated System and Operations Planning to accommodate increased distributed energy resources.

•	Transforming the business using multiple levers, including digital tools, to increase productivity and reinvest the proceeds into new growth opportunities, improved customer service, and lower bills for customers.

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

•	Regulatory and Legislative Impacts in 2018 represents charges related to the Duke Energy Progress and Duke Energy Carolinas North Carolina rate case orders and the repeal of the South Carolina Base Load Review Act. For 2017, it represents charges related to the Levy nuclear project in Florida and the Mayo Zero Liquid Discharge and Sutton combustion turbine projects in North Carolina.

•	Impairment Charges in 2018 represents an impairment at Citrus County CC, a goodwill impairment at Commercial Renewables and an other-than-temporary impairment of an investment in Constitution Pipeline Company, LLC. For 2017 and 2016, the charges represent goodwill and other-than-temporary asset impairments at Commercial Renewables.

•	Sale of Retired Plant represents the loss associated with selling Beckjord, a nonregulated generating facility in Ohio.

•	Impacts of the Tax Act represents amounts recognized related to the Tax Act.

•	Severance Charges relate to companywide initiatives, excluding merger integration, to standardize processes and systems, leverage technology and workforce optimization.

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(a)	Net of tax benefit of $19 million in 2018, $39 million in 2017, and $194 million in 2016.

(b)	Net of tax benefit of $63 million in 2018 and $60 million in 2017.

(c)	Net of $27 million tax benefit and $2 million Noncontrolling Interests in 2018. Net of $28 million tax benefit in 2017 and $26 million in 2016.

(d)	Net of $25 million tax benefit.

(e)

The Tax Act reduced the corporate income tax rate from 35 to 21 percent, effective January 1, 2018. As the tax change was enacted in 2017, Duke Energy was required to remeasure its existing deferred tax assets and liabilities at the lower rate at December 31, 2017. 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. For 2018, the amount represents a true up of existing regulatory liabilities related to the Tax Act. See Note 23 to the Consolidated Financial Statements, "Income Taxes" for more information.

(f)	Net of tax benefit of $43 million in 2018 and $35 million in 2016.

(g)	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. For 2017 and 2018, amounts reflect adjustments related to the sale of the International Disposal Group, primarily related to estimated tax expense.

•	Higher regulated electric revenues due to favorable weather and higher retail sales volumes in the current year;

•	Positive impacts from the North Carolina rate case orders; and

•	Rider growth.

•	Higher interest expense due to higher debt outstanding and higher interest rates;

•	Higher depreciation and amortization expense at Electric Utilities and Infrastructure primarily due to rate base growth; and

•	A reduced tax benefit on holding company interest as a result of the Tax Act.

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

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•	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 23 to the Consolidated Financial Statements, "Income Taxes," for additional information;

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

•	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 ACP and Sabal Trail natural gas pipelines.

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

(b)	See Notes 4 and 23 to the Consolidated Financial Statements, "Regulatory Matters" and "Income Taxes," respectively, for information about the Tax Act's impact on Duke Energy's Consolidated Balance Sheets.

(c)	Amount primarily relates to the 2017 remeasurement, and true up of that remeasurement in 2018, of net deferred tax liabilities that are excluded for ratemaking purposes related to abandoned or impaired assets and certain wholesale fixed rate contracts.

(d)	2017 amount includes a $16 million expense recorded within Equity in earnings (losses) of unconsolidated affiliates on the Consolidated Statement of Operations.

(e)	2017 amount primarily relates to the remeasurement of net deferred tax liabilities related to equity method investments.

(f)	2017 amount primarily relates to the remeasurement of Foreign Tax Credits, federal NOLs and nonregulated deferred tax assets.

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•	a $577 million increase in fuel related revenues due to higher sales volumes driven primarily by favorable weather in the current year, and increases in fuel rates billed to customers, which reflects higher average fuel prices;

•	a $331 million increase in retail sales, net of fuel revenues, due to favorable weather in the current year;

•	a $236 million increase in retail pricing primarily due to the Duke Energy Progress and Duke Energy Carolinas North Carolina rate cases and Duke Energy Florida base rate adjustments related to generation assets being placed into service;

•	a $109 million increase in wholesale power revenues, net of fuel, primarily due to higher recovery of coal ash costs at Duke Energy Progress and Duke Energy Carolinas, partially offset by contracts that expired in the prior year at Duke Energy Indiana and customer refunds in the current year at Duke Energy Carolinas related to a FERC order on a complaint filed by PMPA;

•	an $82 million increase in weather-normal retail sales volumes driven by residential growth;

•	a $73 million net increase in retail rider revenues, primarily related to capital investment riders at Duke Energy Indiana and Duke Energy Ohio, partially offset by a net decrease in rider revenues related to the implementation of new base rates at Duke Energy Carolinas and Duke Energy Progress; and

•	a $49 million increase in other revenues at Duke Energy Carolinas primarily due to the recognition of previously deferred revenues associated with storm restoration costs in South Carolina and favorable transmission revenues.

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•	a $578 million decrease in retail and wholesale sales due to revenues subject to refund to customers associated with the lower statutory federal corporate tax rate under the Tax Act.

•	a $538 million increase in fuel used in electric generation and purchased power due to higher sales and higher amortization of deferred fuel expenses;

•	a $513 million increase in depreciation and amortization expense primarily due to higher amortization of deferred coal ash costs, additional plant in service and new depreciation rates associated with the Duke Energy Progress and Duke Energy Carolinas North Carolina rate cases;

•	a $271 million increase in operation, maintenance and other expense primarily due to impacts associated with the Duke Energy Progress North Carolina rate case and higher storm costs, partially offset by a FERC approved settlement refund of certain transmission costs previously billed by PJM; and

•	a $133 million increase in impairment charges primarily due to the impacts associated with the Duke Energy Carolinas and Duke Energy Progress North Carolina rates cases and the Duke Energy Florida Citrus County CC impairments in the current year, offset by the write-off of remaining unrecovered Levy Nuclear project costs at Duke Energy Florida in the prior year.

•	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 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 $113 million increase in depreciation and amortization expense primarily due to additional plant in service; and

•	a $58 million increase in property and other taxes primarily due to higher property taxes.

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

•	a $73 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.

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

•	a $76 million increase primarily due to higher natural gas costs passed through to customers as a result of higher volumes sold driven primarily by weather and higher natural gas prices; and

•	a $37 million increase primarily due to residential and commercial customer revenue, net of natural gas costs passed through to customers, due to customer growth and IMR rate adjustments and new power generation customers.

•	a $69 million decrease primarily due to revenues subject to refund to customers associated with the lower statutory corporate tax rate under the Tax Act.

•	a $65 million increase in natural gas costs primarily due to higher costs passed through to customers, as a result of a higher natural gas prices;

•	a $38 million increase in operations, maintenance, and other expense primarily due to increased shared services, costs to achieve merger expenses and a pension settlement charge at Piedmont in 2017; and

•	a $14 million increase in depreciation and amortization expense due to additional plant in service and higher amortization of software costs.

•	a $55 million impairment recorded for the investment in Constitution in 2018.

•	a $25 million increase in non-service components of employee benefit costs in 2018. For additional information on employee benefit costs, see Note 22 to the Consolidated Financial Statements, "Employee Benefit Plans"; and

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•	a $20 million increase in equity earnings from pipeline investments.

•	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, 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.

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(a)	Certain projects are included in tax-equity structures where investors have differing interests in the project's economic attributes. In 2018, 100 percent of the tax-equity project's capacity is included in the table above.

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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 Statements of Operations and Comprehensive Income.

(b)	See Notes 4 and 23 to the Consolidated Financial Statements, "Regulatory Matters" and "Income Taxes," respectively, for information about the Tax Act's impact on Duke Energy's Consolidated Balance Sheets.

(c)	2017 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)	2017 amount primarily relates to the remeasurement of deferred tax liabilities of certain wholesale fixed rate contracts.

(e)	2017 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)	2017 amount primarily relates to the remeasurement of deferred tax liabilities that are excluded for ratemaking purposes related to impaired assets.

(g)	2017 amount includes a $16 million expense recorded within Equity in earnings (losses) of unconsolidated affiliates on the Consolidated Statements of Operations and Comprehensive Income.

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•	a $263 million decrease in retail sales due to revenues subject to refund to customers associated with the lower statutory federal corporate tax rate under the Tax Act;

•	a $68 million decrease in retail rider revenues primarily related to the implementation of new base rates; and

•	an $8 million decrease in wholesale power revenues, net of sharing and fuel, primarily due to wholesale customer refunds in the current year related to a FERC order on a complaint filed by PMPA, partially offset by higher revenues related to recovery of coal ash costs.

•	a $169 million increase in retail sales, net of fuel revenues, due to favorable weather in the current year;

•	an $83 million increase in retail pricing from impacts of the North Carolina rate case;

•	a $49 million increase in other revenues primarily due to the recognition of previously deferred revenues associated with storm restoration costs in South Carolina and favorable transmission revenues; and

•	a $36 million increase in weather-normal retail sales volumes.

•	a $192 million increase in impairment charges primarily due to the impacts of the North Carolina rate order and charges related to coal ash costs in South Carolina;

•	a $111 million increase in depreciation and amortization expense primarily due to additional plant in service, new depreciation rates associated with the North Carolina rate case and higher amortization of deferred coal ash costs, partially offset by lower amortization of certain regulatory assets; and

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•	a $109 million increase in operations, maintenance and other expense primarily due to severance charges.

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•	a $614 million increase in fuel and capacity revenues primarily due to an increase in fuel and capacity rates billed to retail customers and increased demand;

•	a $149 million increase in retail pricing due to the impacts of the Duke Energy Progress North Carolina and South Carolina rate cases and Duke Energy Florida base rate adjustments related to generation assets being placed into service;

•	a $108 million increase in retail sales due to favorable weather in the current year, net of lost revenue impacts associated with Hurricane Irma in 2017 and Hurricane Florence in 2018;

•	a $96 million increase in wholesale power revenues, net of fuel, primarily due to recovery of coal ash costs and higher peak demand at Duke Energy Progress;

•	a $34 million net increase in retail rider revenues in conjunction with the implementation of new base rates at Duke Energy Progress; and

•	a $47 million increase in weather-normal retail sales volumes.

•	a $119 million decrease in retail sales due to revenues subject to refund to customers associated with the lower statutory federal corporate tax rate under the Tax Act at Duke Energy Progress.

•	a $559 million increase in fuel used in electric generation and purchased power primarily due to higher amortization of deferred fuel and capacity expenses, increased demand and changes in generation mix;

•	a $334 million increase in depreciation and amortization expense primarily due to higher amortization of deferred coal ash costs and new depreciation rates associated with the North Carolina rate case at Duke Energy Progress, and accelerated depreciation of Crystal River Units 4 and 5 at Duke Energy Florida;

•	a $312 million increase in operation, maintenance and other expense primarily due to higher costs related to storms, vegetation management costs and severance charges; and

•	a $26 million increase in property and other taxes primarily due to higher revenue related taxes at Duke Energy Florida.

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•	a $69 million decrease in impairment charges primarily due to the write-off of remaining unrecovered Levy Nuclear Project costs in the prior year, offset by the current year impairment of the Citrus County CC at Duke Energy Florida and the impacts associated with the North Carolina rate case at Duke Energy Progress.

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•	a $324 million increase in fuel revenues driven by higher retail sales and changes in generation mix;

•	a $125 million increase in retail pricing due to the impacts from the North Carolina and South Carolina rate cases;

•	a $96 million increase in wholesale power revenues, net of fuel, primarily due to recovery of coal ash costs and higher peak demand;

•	a $34 million net increase in retail rider revenues in conjunction with the implementation of new base rates;

•	a $61 million increase in retail sales due to favorable weather in the current year, net of the impact of lost revenues due to Hurricane Florence; and

•	a $35 million increase in weather-normal retail sales volumes.

•	a $119 million decrease in retail sales due to revenues subject to refund to customers associated with the lower statutory federal corporate tax rate under the Tax Act.

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•	a $283 million increase in fuel used in electric generation and purchased power primarily due to higher retail sales and changes in generation mix;

•	a $266 million increase in depreciation and amortization expense primarily due to higher amortization of deferred coal ash costs and new depreciation rates associated with the North Carolina rate case;

•	a $139 million increase in operation, maintenance and other expense primarily due to higher storm costs, impacts associated with the North Carolina rate case and severance charges; and

•	a $14 million increase in impairment charges associated with the North Carolina rate case.

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•	a $290 million increase in fuel and capacity revenues primarily due to an increase in fuel and capacity rates billed to retail customers and increased demand;

•	a $47 million increase in retail sales, net of fuel revenues, due to favorable weather in the current year and impacts of lost revenue resulting from Hurricane Irma in the prior year:

•	a $24 million increase in retail pricing due to base rate adjustments related to generation assets being placed into service; and

•	a $12 million increase in weather-normal retail sales volumes.

•	a $277 million increase in fuel used in electric generation and purchased power primarily due to higher amortization of deferred fuel and capacity expenses and increased purchased power and demand;

•	a $172 million increase in operation, maintenance and other expense primarily due to higher storm cost amortization, vegetation management costs and severance charges, partially offset by lower storm restoration costs in the current year;

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•	a $68 million increase in depreciation and amortization expense primarily due to accelerated depreciation of Crystal River Units 4 and 5 and additional plant in service; and

•	a $27 million increase in property and other taxes primarily due to higher revenue related taxes.

•	an $84 million decrease in impairment charges primarily due to the write-off of remaining unrecovered Levy Nuclear Project costs in the prior year, offset by the current year impairment of the Citrus County CC.

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•	a $44 million increase in electric and natural gas retail sales, net of fuel revenues, due to favorable weather in the current year;

•	a $17 million increase in rider revenue primarily related to capital investment riders;

•	a $16 million increase in financial transmission rights revenues;

•	a $7 million increase in point-to-point transmission revenues; and

•	a $6 million increase in fuel revenues due to higher natural gas costs.

•	a $48 million decrease in regulated revenues due to revenues subject to refund to customers associated with the lower statutory corporate tax rate under the Tax Act; and

•	a $7 million decrease in bulk power marketing sales.

•	a $50 million decrease in operations, maintenance and other expense primarily due to the FERC approved settlement refund of certain transmission costs previously billed by PJM; and

•	a $15 million decrease in fuel used in electric generation and purchased power related to the deferral of OVEC purchased power, which is reflected in regulated electric in 2018 and nonregulated electric in 2017, as noted above in the Operating Revenues section.

•	a $12 million increase in property and other taxes primarily due to higher property taxes and kilowatt tax;

•	a $7 million increase in depreciation and amortization expense primarily due to additional plant in service and increased amortization of regulatory assets; and

•	a $6 million increase in cost of natural gas primarily due to an increase in natural gas sales volumes.

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•	a $65 million increase in rate rider revenues primarily related to the Edwardsport IGCC plant and the TDSIC rider;

•	a $50 million increase in fuel and other revenues primarily due to higher base fuel, non-native fuel and Midwest Independent System Operator rider revenues;

•	a $13 million increase in retail sales, net of fuel revenues, due to favorable weather in the current year; and

•	a $13 million increase in weather-normal retail sales volumes.

•	a $105 million decrease due to revenues subject to refund to customers associated with the lower statutory federal corporate tax rate under the Tax Act; and

•	a $27 million decrease in wholesale power revenues, net of fuel, primarily due to contracts that expired in the prior year.

•	a $62 million increase in depreciation and amortization expense primarily due to additional plant in service and the deferral of certain asset retirement obligations in the prior year;

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•	a $45 million increase in operation, maintenance and other expense primarily due to amortization of previously deferred expenses, and higher transmission, storm and customer related costs;

•	a $34 million increase in fuel used in electric generation and purchased power primarily due to higher natural gas costs; and

•	a $12 million increase in impairment charges primarily due to the reduction of a regulatory asset pertaining to the Edwardsport IGCC settlement agreement in the current year, partially offset by the impairment of certain metering equipment in the prior year.

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•	a $60 million increase primarily due to higher natural gas costs passed through to customers due to higher volumes sold and higher natural gas prices; and

•	a $37 million increase primarily due to residential and commercial customer revenue, net of natural gas costs passed through to customers, due to customer growth and IMR rate adjustments and new power generation customers.

•	a $51 million decrease primarily due to revenues subject to refund to customers associated with the lower statutory corporate tax rate under the Tax Act.

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•	a $60 million increase in cost of natural gas primarily due to higher volumes sold and higher natural gas costs passed through to customers due to the higher price per dekatherm of natural gas;

•	a $53 million increase in operations, maintenance and other expense primarily due to increased shared services, cost to achieve merger expenses and pension settlement charge; and

•	an $11 million increase in depreciation and amortization expense due to additional plant in service.

•	a $7 million decrease in impairment charges due to an impairment of software recorded in the prior year.

•	a $25 million increase in other income and expenses, net primarily due to higher income from non-service components of employee benefit costs in the current year. For additional information on employee benefit costs, see Note 22 to the Consolidated Financial Statements, "Employee Benefit Plans"; and

•	a $13 million increase in equity earnings of unconsolidated affiliates from pipeline investments primarily due to favorable earnings partially offset by unfavorable impacts of the Tax Act in the prior year.

•	applicable regulatory environment changes;

•	historical regulatory treatment for similar costs in Duke Energy’s jurisdictions;

•	litigation of rate orders;

•	recent rate orders to other regulated entities;

•	levels of actual return on equity compared to approved rates of return on equity; and

•	the status of any pending or potential deregulation legislation.

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•	Significant delays in or failure to complete significant growth projects of investees;

•	Adverse regulatory actions expected to substantially reduce the investee’s product demand or profitability;

•	Expected financial performance significantly worse than anticipated when initially invested;

•	Prolonged period the fair value is below carrying value;

•	A significant or sustained decline in the market value of an investee;

•	Lower than expected cash distributions from investees;

•	Significant asset impairments or operating losses recognized by investees; and

•	Loss of significant customers or suppliers with no immediate prospects for replacement.

•	the expected long-term rate of return on plan assets;

•	the assumed discount rate applied to future projected benefit payments; and

•	the heath care cost trend rate.

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•	a $684 million increase in net income after adjustment for non-cash items primarily due to favorable weather and increased pricing and volumes in the current period; and

•	a $38 million decrease in payments to AROs.

•	a $122 million increase in contributions to qualified pension plans; and

•	a $105 million payment for disposal of Beckjord.

•	a $1,381 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.

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•	a $1,470 million increase in capital, investment and acquisition expenditures in all reportable business segments, including expenditures related to W.S. Lee CC, Asheville and Citrus County CC at Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida, respectively.

•	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 $1,838 million increase in proceeds from the issuance of common stock; and

•	a $1,533 million increase in net borrowings from notes payable and commercial paper primarily due to increased funding requirements for capital expenditures and storm costs.

•	a $2,200 million net decrease in proceeds from issuances of long-term debt primarily due to timing related to refinancing of existing maturities, fund growth and general corporate needs.

•

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.

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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, 2018, 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 NPNS. For contracts where the price paid is based on an index, the amount is based on market prices at December 31, 2018, 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 EPC 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)	Related to Commercial Renewables wind and solar facilities.

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(j)	Unrecognized tax benefits of $24 million are not reflected in this table as Duke Energy cannot predict when open income tax years will close with completed examinations. See Note 23 to the Consolidated Financial Statements, "Income Taxes."

(k)

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 22 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)	In November 2018, the closure deadline for these basins was extended to December 31, 2029 as a result of the completion of certain dam improvement projects and alternative drinking water source projects by October 15, 2018.

(b)	The Coal Ash Act requires the installation and operation of three large-scale coal ash beneficiation projects to produce reprocessed ash for use in the concrete industry. Duke Energy has selected the Buck, H.F. Lee and Cape Fear plants for these projects. Closure at these sites is required to be completed no later than December 31, 2029.

•	Clean Water Act

•	Steam Effluent Limitation Guidelines

•	Cross-State Air Pollution Rule

•	Carbon Pollution Standards for New, Modified and Reconstructed Power Plants

•	Clean Power Plan/ACE Rule

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(a)	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.

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

(c)	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.

(d)	Amounts in Retained Earnings and Accumulated Other Comprehensive Loss represent a cumulative-effect adjustment due to implementation of a new accounting standard related to Financial Instruments Classification and Measurement. See Note 1 for more information. Amount in Noncontrolling Interests primarily relates to tax equity financing activity in the Commercial Renewables segment.

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(a)	Includes a $547 million non-cash dividend related to a legal entity restructuring.

(b)	Amounts in Retained Earnings and Accumulated Other Comprehensive Loss represent a cumulative-effect adjustment due to implementation of a new accounting standard related to Financial Instruments Classification and Measurement. See Note 1 for more information.

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(a)	Amounts represent a cumulative-effect adjustment due to implementation of a new accounting standard related to Financial Instruments Classification and Measurement. See Note 1 for more information.

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

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

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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 charges.

(a)	Amount represents an income tax benefit resulting from immaterial out of period deferred tax liability adjustments for previously sold businesses not related to the International Disposal Group.

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•

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.

(a)	Upon meeting the criteria for assets held for sale, beginning in the fourth quarter of 2016 depreciation expense 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 attributable to Duke Energy Corporation was $(445) million for the year ended December 31, 2016.

(e)	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)	Amount includes an income tax benefit of $95 million. See Note 23, "Income Taxes," for additional information.

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(a)	All segments include adjustments to the December 31, 2017 estimate of the income tax effects of the Tax Act. Electric Utilities and Infrastructure includes a $24 million expense, Gas Utilities and Infrastructure includes a $1 million expense, Commercial Renewables includes a $3 million benefit and Other includes a $2 million benefit. See Note 23 for additional information.

(b)	Electric Utilities and Infrastructure includes after-tax regulatory and legislative impairment charges of $202 million related to rate case orders, settlements or other actions of regulators or legislative bodies and an after-tax impairment charge of $46 million related to the Citrus County CC at Duke Energy Florida. See Note 4 for additional information.

(c)	Gas Utilities and Infrastructure includes an after-tax impairment charge of $42 million for the investment in Constitution. See Note 12 for additional information.

(d)	Commercial Renewables includes an impairment charge of $91 million, net of $2 million Noncontrolling interests, related to goodwill. See Note 11 for additional information.

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(e)	Other includes $65 million of after-tax costs to achieve the Piedmont merger, $144 million of after-tax severance charges related to a companywide initiative and an $82 million after-tax loss on the sale of the retired Beckjord Generating Station described below. For additional information, see Note 2 for the Piedmont Merger and Note 20 for severance charges.

(a)	All segments include impacts of 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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(a)	Commercial Renewables includes a pretax impairment charge of $71 million. See Note 12 for additional information.

(b)	Other includes $329 million of after-tax costs to achieve mergers. See 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. See Note 20 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 investment expenditures related to the International Disposal Group. Gas Utilities and Infrastructure includes the Piedmont acquisition of $5 billion. See Note 2 for more information on the Piedmont acquisition.

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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 federal tax rate as a result of the Tax Act and the change in the North Carolina tax rate, both discussed in Note 23.

(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 and equity return on coal ash expenditures for North Carolina and South Carolina retail customers as permitted by various regulatory orders.

(j)	Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 for additional detail.

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•	Duke Energy Carolinas would recover grid improvement costs through a pilot, three-year Grid Rider except for costs related to targeted undergrounding of power lines, cable and conduit replacement, and power pole replacement;

•	Excluded costs were to be deferred with a return until Duke Energy Carolinas’ next base rate case proceeding; and

•	Costs incurred during the three-year pilot, both rider recoverable and deferred, were subject to a 4.5 percent cumulative cap of total annual electric service revenue.

•	Recovery of $554 million of deferred coal ash basin closure costs over a five-year period with a return at Duke Energy Carolinas' WACC;

•	Assessment of a $70 million management penalty ratably over a five-year period by reducing the annual recovery of the deferred coal ash costs;

•	Denial of Duke Energy Carolinas' request for recovery of future estimated ongoing annual coal ash costs of $201 million with approval to defer such costs with a return at Duke Energy Carolinas' WACC, to be considered for recovery in the next rate case;

•	Inclusion in rates of costs related to the W.S. Lee CC, two new solar facilities, and AMI deployment as requested;

•	Recovery of Lee Nuclear Station licensing and development cost of $347 million over a 12-year period, but denial of a return on the deferred balance of costs;

•	Reduction in revenue related to lower income tax expense resulting from the Tax Act, and a requirement to maintain all excess deferred income tax (EDIT) resulting from the Tax Act in a regulatory liability account pending flow back to customers as approved by the commission at the earlier of three years or Duke Energy Carolinas’ next general rate case proceeding; and

•

Denial of the proposed Grid Rider Stipulation related to grid improvement costs and denial of deferral accounting treatment of the costs at this time. Duke Energy Carolinas may petition for deferral of grid modernization costs outside of a general rate case proceeding if it can show financial hardship or a stipulation that includes greater consensus among intervening parties on costs being classified as grid modernization.

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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)	South Carolina storm costs are included in rate base.

(e)	Included in rate base.

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

(h)	Earns a debt and equity return on coal ash expenditures for North Carolina and South Carolina retail customers as permitted by various regulatory orders.

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

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

(k)	Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 for additional detail.

(l)	Includes regulatory liabilities related to the change in the federal tax rate as a result of the Tax Act and the change in the North Carolina tax rate, both discussed in Note 23.

•	Recovery of the remaining $234 million of deferred coal ash basin closure costs over a five-year period with a return at Duke Energy Progress' WACC, excluding $10 million of retail deferred coal ash basin costs related to ash hauling at Duke Energy Progress' Asheville Plant;

•	Assessment of a $30 million management penalty ratably over a five-year period by reducing the annual recovery of the deferred coal ash costs;

•	Denial of Duke Energy Progress' request for recovery of future estimated ongoing annual coal ash costs of $129 million with approval to defer such costs with a return at Duke Energy Progress' WACC, to be considered for recovery in the next rate case; and

•	Approval to recover $51 million of the approximately $80 million deferred storm costs over a five-year period with amortization beginning in October 2016. The order did not allow the deferral of the associated capital costs or a return on the deferred balance during the deferral period.

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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)	Certain costs earn a return.

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

(f)	Earns commercial paper rate.

(g)	Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 for additional detail.

(h)	Balance includes $165 million for Hurricane Michael. Duke Energy Florida expects to seek recovery of these costs in the first half of 2019.

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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 22 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)	Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 22 for additional detail.

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•	Riders to reflect the change in the statutory federal tax rate from 35 to 21 percent as they are filed in 2018;

•	Base rates to reflect the change in the statutory federal tax rate from 35 to 21 percent upon IURC approval, but no later than September 1, 2018;

•	Duke Energy Indiana to continue to defer protected federal EDIT until January 1, 2020, at which time it will be returned to customers according to the Average Rate Assumption Method required by the Internal Revenue Service over approximately 26 years; and

•	Duke Energy Indiana to begin returning unprotected federal EDIT upon IURC approval, over 10 years. In order to mitigate the negative impacts to cash flow and credit metrics, the Settlement Agreement allows Duke Energy Indiana to return $7 million per year over the first five years, with a step up to $35 million per year in the following five years.

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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 22 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 Indiana committed to either retire or stop burning coal at Gallagher Units 2 and 4 by December 31, 2022, as part of the 2016 settlement of Edwardsport IGCC matters.

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(a)	Contracts represent 100 percent of net plant output.

(b)	Contracts represent between 81 percent and 100 percent of net plant output.

(c)	Contracts represent between 1 percent and 8 percent of net plant output.

(d)	Excludes PPA with OVEC. See Note 17 for additional information.

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

(b)	Duke Energy includes $63 million and $531 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, letters of credit or the Master Credit Facility.

(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 16 days.

(e)	Duke Energy includes $1,380 million and $156 million in purchase accounting adjustments related to Progress Energy and Piedmont, respectively.

(f)	Duke Energy includes $41 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.

(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, letters of credit or the Master Credit Facility.

(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 programs was 14 days.

(e)	Duke Energy includes $1,509 million and $176 million purchase accounting adjustments related to the mergers with 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)	Includes capital lease obligations, amortizing debt and small bullet maturities.

(b)	Debt has a floating interest rate.

(a)	Excludes $1,578 million in purchase accounting adjustments related to the Progress Energy merger and the Piedmont acquisition.

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

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(a)	Debt issued to pay down short-term debt.

(b)	Debt issued to pay down short-term debt. Debt issuance has a floating debt rate.

(c)	Callable after September 2023 at par. Junior subordinated hybrid debt issued to pay down short-term debt and for general corporate

(d)	Debt issued to repay at maturity a $300 million first mortgage bond due April 2018, pay down intercompany short-term debt and for general corporate purposes.

(e)	Debt issued to repay a portion of intercompany short-term debt under the money pool borrowing arrangement and for general corporate purposes.

(f)	Debt issued to repay short-term debt and for general corporate purposes.

(g)	Debt issued to fund eligible green energy projects, including zero-carbon solar and energy storage, in the Carolinas.

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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)	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 PMPA.

(b)	Jointly owned with NCEMC.

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

(d)	Jointly owned with WVPA.

(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.

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

(b)	Decommissioning cost for Duke Energy Carolinas reflects its ownership interest in jointly owned reactors. Other joint owners are responsible for decommissioning costs related to their interest in the reactors.

(c)	Duke Energy Carolinas' site-specific nuclear decommissioning cost study completed in 2018 is expected to be filed with the NCUC and PSCSC by the second quarter 2019. Duke Energy Carolinas will also complete a new funding study, which will be completed and filed with the NCUC and PSCSC in 2019.

(d)	Duke Energy Florida's site-specific nuclear decommissioning cost study and a new funding study were completed and filed with the FPSC in 2018.

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(a)	Substantially all accretion expense for the years ended December 31, 2018, and 2017 relates to Duke Energy’s regulated operations and has been deferred in accordance with regulatory accounting treatment.

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

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

(d)

Amounts primarily relate to increases in groundwater monitoring estimates for closure of ash impoundments and an increase for nuclear decommissioning costs at Duke Energy Carolinas' nuclear sites compared to original estimates, partially offset by a reduction for nuclear decommissioning at Crystal River Unit 3 compared to original estimates and modifications to the timing of expected cash flows for coal ash AROs.

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(a)

Includes capitalized leases of $1,237 million, $135 million, $257 million, $137 million, $120 million, $73 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 $131 million, $14 million and $117 million, respectively, of accumulated amortization of capitalized leases.

(b)	Includes $1,947 million, $1,087 million, $860 million and $860 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 $61 million, $12 million, $20 million and $10 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 $4,007 million and accumulated depreciation of consolidated VIEs of $698 million at Duke Energy.

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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.

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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. See "Goodwill Impairment Testing" below for the results of the 2018 goodwill impairment test.

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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.

(d)	Sabal Trail returned capital of $112 million during the year ended December 31, 2018.

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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 Operating Revenues, and Duke Energy Carolinas and Duke Energy Progress record the related purchases as a component of Fuel used in electric generation and purchased power on their respective Consolidated Statements of Operations and Comprehensive Income. These intercompany revenues and expenses are eliminated in consolidation. 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, Piedmont recorded $74 million of natural gas sales with Duke Energy.

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(e)

Piedmont has related party transactions as a customer of its equity method investments in Pine Needle, Hardy Storage, and Cardinal natural gas storage and transportation facilities. These expenses are included in Cost of natural gas on Piedmont's Consolidated Statements of Operations and Comprehensive Income. For the two months ended December 31, 2016, and for the year ended October 31, 2016, Piedmont recorded $6 million and $29 million, respectively, of natural gas storage and transportation costs.

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(a)	Duke Energy includes amounts related to consolidated VIEs of $422 million in cash flow hedges and $194 million in undesignated contracts as of December 31, 2018, and $660 million in cash flow hedges as of December 31, 2017.

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(a)	During the year ended December 31, 2018, 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)	Book value of long-term debt includes $1.6 billion as of December 31, 2018, and $1.7 billion as of December 31, 2017, of unamortized debt discount and premium, net in purchase accounting adjustments related to the mergers with Progress Energy and Piedmont that are excluded from fair value of long-term debt.

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(a)

At December 31, 2017, Sabal Trail was considered a VIE due to having insufficient equity to finance their own activities without subordinated financial support. However, Sabal Trail is now a fully operational, well capitalized entity. As a result, Sabal Trail has sufficient equity to finance its own activities, and therefore, is no longer considered a VIE. Duke Energy's investment in Sabal Trail was $112 million at December 31, 2018.

(b)	During the year ended December 31, 2018, Duke Energy recorded an OTTI of $55 million related to Constitution within Equity in earnings of unconsolidated affiliates on Duke Energy's Consolidated Statements of Income. See Note 4 for additional information.

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(a)	Other revenue sources include revenues from leases, derivatives and alternative revenue programs that are not considered revenues from contracts with customers. Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over or under collection of related revenues.

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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 charges were $3 million for the two months ended December 31, 2016, and $19 million for the year ended October 31, 2016.

(a)	Piedmont's stock-based compensation costs were not material for the two months ended December 31, 2016. See discussion below for information on Piedmont's pre-merger stock-based compensation plans.

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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 $10 million for the year ended October 31, 2016.

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(a)	Duke Energy amounts exclude $5 million, $7 million and $8 million for the years ended December 2018, 2017 and 2016, 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, $3 million and $4 million for the years ended December 2018, 2017 and 2016, 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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(a)	Duke Energy amounts exclude $7 million, $7 million and $8 million for the years ended December 2018, 2017 and 2016, 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 $2 million for the years ended December 2018, 2017 and 2016, 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)

Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio, Duke Energy Indiana, and Piedmont were allocated approximately 27 percent, 31 percent, 15 percent, 16 percent, 5 percent, 7 percent, and 4 percent, respectively, of the Duke Energy Master Retirement Trust at December 31, 2018. 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, 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 and Piedmont's Pension assets 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.

(a)	Balance at January 1 includes $9 million associated with Piedmont pension assets.

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

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•	Additional tax expense of $23 million related to the completion of the analysis of Duke Energy’s existing regulatory liability related to deferred taxes;

•	A $10 million tax benefit for the remeasurement of deferred tax assets and deferred tax liabilities primarily related to the guidance on bonus depreciation issued by the IRS in August 2018 affecting the computation of the Company's 2017 Federal income tax liability;

•	Additional tax expense of $7 million related to the portion of the deferred tax asset as of December 31, 2017, that represents nondeductible long-term incentives under the Tax Act’s limitation on the deductibility of executive compensation; and

•	During the fourth quarter of 2018, the Company released the $76 million valuation allowance that it recorded in the first quarter of 2018 as a result of additional guidance published by the IRS that stated refundable AMT credits would not be subject to sequestration.

•

The majority of Duke Energy’s operations are regulated and it is expected that the Subsidiary Registrants will ultimately pass on the savings associated with the amount representing the remeasurement of deferred tax balances related to regulated operations to customers. For Duke Energy's regulated operations, where the reduction is expected to be returned to customers in future rates, the remeasurement has been deferred as a regulatory liability. During 2018, Duke Energy recorded an additional regulatory liability of $83 million, representing the revaluation of those deferred tax balances. The Subsidiary Registrants continue to respond to requests from regulators in various jurisdictions to determine the timing and magnitude of savings they will pass on to customers.

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(a)

Includes benefits of NOL carryforwards and tax credit carryforwards of $22 million at Duke Energy Carolinas, $293 million at Progress Energy, $59 million at Duke Energy Progress, $219 million at Duke Energy Florida, $17 million at Duke Energy Ohio, $21 million at Duke Energy Indiana and $39 million at Piedmont. In addition, total deferred income taxes includes utilization of NOL carryforwards and tax credit carryforwards of $18 million at Duke Energy.

(b)	For the year ended December 31, 2018, the Company has revised the December 31, 2017, estimates of the income tax effects of the Tax Act, in accordance with SAB 118. See the Statutory Rate Reconciliation section below for additional information on the Tax Act's impact on income tax expense.

(a)

Includes utilization of NOL 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, 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 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.

(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)

For the year ended December 31, 2018, the Company revised the December 31, 2017 estimates of the income tax effects of the Tax Act, in accordance with SAB 118. Amounts primarily include but are not limited to items that are excluded for ratemaking purposes related certain wholesale fixed rate contracts, remeasurement of nonregulated net deferred tax liabilities, Federal net operating losses, and valuation allowance on foreign tax credits.

(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.

(a)	A valuation allowance of $4 million has been recorded on the Federal NOL carryforwards, as presented in the Net Deferred Income Tax Liability Components table.

(b)	A valuation allowance of $85 million has been recorded on the state NOL carryforwards, as presented in the Net Deferred Income Tax Liability Components table.

(c)	A valuation allowance of $12 million has been recorded on the foreign NOL carryforwards, as presented in the Net Deferred Income Tax Liability Components table.

(d)	A valuation allowance of $383 million has been recorded on the foreign tax credits, as presented in the Net Deferred Income Tax Liability Components table.

(e)	Indefinite carryforward for Federal NOLs, and NOLs for states that have adopted the Tax Act's NOL provisions, generated in tax years beginning after December 31, 2017.

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

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(a)	Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio, 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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(a)	Amounts for Piedmont for the two months ended December 31, 2016, and for the year ended October 31, 2016, were not material.

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(1)	As of December 31, 2018, no options were outstanding under equity compensation plans.

(2)	Includes restricted stock units and performance shares (assuming the maximum payout level) granted under 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 Executive Savings Plan or the 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 non-qualified deferred compensation plan described in more detail below.

(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.

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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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