Duke Energy CORP - Annual Report: 2019 (Form 10-K)

Registrant	Title of each class     Trading symbols    which registered

Duke Energy Corporation	Common Stock, $0.001 par value     DUK    New York Stock Exchange LLC

Duke Energy	5.125% Junior Subordinated Debentures due     DUKH    New York Stock Exchange LLC

Duke Energy	5.625% Junior Subordinated Debentures due     DUKB    New York Stock Exchange LLC

Duke Energy	Depositary Shares, each representing a 1/1,000th     DUK PR A    New York Stock Exchange LLC

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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 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 United States 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;

◦	The ability to obtain adequate insurance at acceptable costs;

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

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

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

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

◦	The impact of United States 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 14% for 2019 and 7% for 2018 and 2017 of total system requirements.

(b)	For 2019, 2018 and 2017 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 was filed with the NCUC and PSCSC in 2019. A new funding study was also completed and filed with the NCUC and PSCSC in 2019.

(d)	Duke Energy Progress' site-specific nuclear decommissioning cost study, which was completed in 2019, is expected to be filed with the NCUC and PSCSC during the first quarter of 2020. Duke Energy Progress is expected to file an updated funding study with NCUC and PSCSC in the third quarter of 2020.

(e)	During 2019, Duke Energy Florida reached an agreement to transfer decommissioning work for Crystal River Unit 3 to a third party. The agreement requires regulatory approval from the NRC and the FPSC.

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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.

(b)	Requests an increase of annualized retail revenues of $352 million beginning in July 2020, and an additional $44 million beginning in April 2021, which include the impacts of the Utility Receipt Tax.

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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.

•	Regulations of the EPA relate to the environment including proposed air emissions regulations that would expand to include emissions of methane.

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•	The Clean Air Act, 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.

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

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

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

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

•	The Toxic Substances Control Act , 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 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;

•	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% of the facility.

(b)	Jointly owned with NCEMC. Duke Energy Carolinas' ownership is 87.27% 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 IMPA. Duke Energy Indiana operates unit 5 and owns 50.05%.

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(d)	Includes Cayuga Internal Combustion.

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

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(a)	Certain projects, including projects within Other small solar, are in tax-equity structures where investors have differing interests in the project's economic attributes. 100% 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) growth in Commercial Renewables from new tax equity solar projects placed in service in 2019 (see Note 1 to the Consolidated Financial Statements, "Summary of Significant Accounting Policies"); (ii) 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, 12 and 13 to the Consolidated Financial Statements, "Regulatory Matters," "Goodwill and Intangible Assets" and "Investments in Unconsolidated Affiliates"); (iii) the sale of the International Disposal Group in 2016, including a loss on sale recorded within discontinued operations; and (iv) the acquisition of Piedmont in 2016, including losses on interest rate swaps related to the acquisition financing.

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

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•	Continuing to place the customer at the center of all that we do which includes providing customized products and solutions

•	Strengthening our relationships with all our vast stakeholders in the communities in which we operate and invest

•	Generating cleaner energy and working to achieve net-zero carbon emissions by 2050

•	Maintaining the safety of our communities and employees

•	Modernizing and strengthening the energy grid

•	Expanding the natural gas infrastructure

•	Deploying digital tools across our business

•	Impairment Charges in 2019 represents a reduction of a prior year impairment at Citrus County CC and an OTTI on the remaining investment in Constitution. For 2018, it represents an impairment at Citrus County CC, a goodwill impairment at Commercial Renewables and an OTTI of an investment in Constitution.

•	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.

•	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 expense of $3 million in 2019. Net of tax benefit of $27 million and Noncontrolling Interests of $2 million in 2018.

(b)	Net of tax benefit of $19 million.

(c)	Net of tax benefit of $63 million.

(d)	Net of $25 million tax benefit.

(e)

The Tax Act reduced the corporate income tax rate from 35% to 21%, 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. This amount represents a true up of existing regulatory liabilities related to the Tax Act. See Note 24 to the Consolidated Financial Statements, "Income Taxes" for more information.

(f)	Net of tax benefit of $43 million.

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•	a $603 million increase in retail pricing primarily due to the Duke Energy Carolinas and Duke Energy Progress North Carolina and South Carolina rate cases and Duke Energy Florida's base rate adjustments related to Citrus County CC being placed in service.

•	a $45 million decrease in weather-normal retail sales volumes.

•	a $428 million increase in depreciation and amortization expense primarily due to additional plant in service and new depreciation rates associated with the Duke Energy Carolinas and Duke Energy Progress North Carolina and South Carolina rate cases and Duke Energy Florida's Citrus County CC being placed in service; and

•	a $41 million increase in property and other taxes primarily due to higher property taxes for additional plant in service at Duke Energy Florida and current year property tax reassessments at Duke Energy Progress and Duke Energy Ohio.

•	a $317 million decrease in impairment charges primarily due to the impacts associated with the Duke Energy Carolinas and Duke Energy Progress North Carolina rate cases as well as impairment impacts related to Duke Energy Florida's Citrus County CC; and

•	a $134 million decrease in operation, maintenance and other expense primarily due to lower payroll and benefit costs resulting from prior year workforce reductions and lower storm costs at Duke Energy Progress and Duke Energy Carolinas in the current year.

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•	a $70 million decrease due to lower natural gas costs passed through to customers; and

•	a $13 million decrease due to rider revenues related to MGP and Accelerated Main Replacement Program.

•	a $37 million increase due to North Carolina and Kentucky base rate case increases;

•	a $19 million increase due to North Carolina and Tennessee IMR increases; and

•	an $11 million increase due to NCUC approval related to tax reform accounting from fixed rate contracts.

•	a $70 million decrease in the cost of natural gas due to lower natural gas prices.

•	a $25 million increase in operation, maintenance and other expense primarily due to increased labor, benefits and information technology costs; and

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

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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 the table above, 100% of the tax-equity project's capacity is included.

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•	a $178 million increase in retail pricing due to the impacts of the prior year North Carolina rate case and the current year South Carolina rate case.

•	a $41 million decrease in rider revenues primarily due to excess deferred taxes, partially offset by EE programs and a decrement rider relating to nuclear decommissioning that ended in the prior year;

•	a $14 million decrease in weather-normal retail sales volumes; and

•	a $7 million decrease in retail sales, net of fuel revenues, due to unfavorable weather in the current year.

•	a $262 million decrease in operation, maintenance and other expense primarily due to decreased labor and storm restoration costs; and

•	a $175 million decrease in impairment charges primarily due to impacts of the prior year North Carolina rate order, the repeal of the South Carolina Base Load Review Act and charges related to coal ash costs in South Carolina.

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•	a $187 million increase in depreciation and amortization expense primarily due to additional plant in service, new depreciation rates associated with the prior year North Carolina rate case and the current year South Carolina rate case and higher amortization of deferred coal ash costs associated with the prior year North Carolina rate case.

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•	a $366 million increase in retail pricing primarily due to the impacts of the prior year North Carolina rate case and current year South Carolina rate case at Duke Energy Progress, Duke Energy Florida's base rate adjustments related to Citrus County CC being placed in service and annual increases from the 2017 Settlement Agreement;

•	a $70 million increase in wholesale power revenues, net of fuel, primarily due to coal ash cost recovery in the current year at Duke Energy Progress and increased demand at Duke Energy Florida;

•	a $42 million increase in fuel revenues primarily related to increased fuel cost recovery due to extreme weather in the prior year at Duke Energy Progress, partially offset by a decrease in fuel and capacity rates billed to retail customers at Duke Energy Florida;

•	a $22 million increase in retail sales, net of fuel revenues, due to favorable weather in the current year at Duke Energy Florida; and

•	a $21 million increase in other revenues primarily due to increased transmission revenues and nonregulated products and services revenues at Duke Energy Florida.

•	a $47 million decrease in retail rider revenues primarily related to decreased revenue requirements in the current year; and

•	a $14 million decrease in weather-normal retail sales volumes at Duke Energy Florida.

•	a $226 million increase in depreciation and amortization expense primarily due to higher amortization of deferred coal ash costs, new depreciation rates associated with the prior year Duke Energy Progress North Carolina rate case and Duke Energy Florida's base rate adjustments related to Citrus County CC being placed in service;

•	a $48 million increase in fuel used in electric generation and purchased power primarily due to an increase in the North Carolina Renewable Energy and Energy Efficiency Portfolio Standard requirement from the prior year at Duke Energy Progress, partially offset by lower purchased power and lower fuel costs, net of deferrals, at Duke Energy Florida; and

•	a $32 million increase in property and other taxes primarily due to current year property tax reassessments and a favorable sales and use tax credit in the prior year at Duke Energy Progress and higher property taxes for additional plant in service at Duke Energy Florida.

•	a $118 million decrease in operation, maintenance and other expense primarily due to lower storm costs, reduced outage costs, and lower employee benefit costs, partially offset by increased vegetation management costs at Duke Energy Florida; and

•	a $111 million decrease in impairment charges primarily due to prior year impacts associated with the North Carolina rate case at Duke Energy Progress as well as the impairment of Duke Energy Florida's Citrus County CC.

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•	a $110 million increase in retail pricing due to the impacts of the prior year North Carolina rate case and the current year South Carolina rate case;

•	a $101 million increase in fuel revenues primarily related to increased fuel cost recovery due to extreme weather in the prior year; and

•	a $54 million increase in wholesale power revenues, net of fuel, primarily due to coal ash cost recovery in the current year.

•	a $21 million decrease primarily due to the return of excess deferred incomes taxes created by the reduction in the corporate income tax rate, partially offset by an increase in rider revenues related to EE programs.

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a $152 million increase in depreciation and amortization expense primarily due to higher amortization of deferred coal ash costs and new depreciation rates associated with the prior year North Carolina and current year South Carolina rate cases, partially offset by the amortization credit for the North Carolina Renewable Energy and Energy Efficiency Portfolio Standard requirement increase from prior year;

•	a $120 million increase in fuel used in electric generation and purchased power primarily due to a higher deferred fuel balance and an increase in the North Carolina Renewable Energy and Energy Efficiency Portfolio Standard requirement from prior year, partially offset by lower demand and changes in generation mix; and

•	a $21 million increase in property and other taxes primarily due to current year property tax reassessments and a favorable sales and use tax credit in the prior year.

•	a $132 million decrease in operation, maintenance and other expense primarily due to lower storm costs in current year, reduced outage costs and lower employee benefit costs; and

•	a $21 million decrease in impairment charges primarily due to prior year impacts associated with the North Carolina rate case.

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•	a $256 million increase in retail pricing due to base rate adjustments related to Citrus County CC being placed in service, annual increases from the 2017 Settlement Agreement and the Solar Base Rate Adjustment;

•	a $22 million increase in retail sales, net of fuel revenues, due to favorable weather in the current year;

•	a $21 million increase in other revenues primarily due to increased transmission revenues and nonregulated products and services revenues; and

•	a $16 million increase in wholesale power revenues, net of fuel, primarily due to increased demand.

•	a $59 million decrease in fuel and capacity revenues primarily due to a decrease in fuel and capacity rates billed to retail customers;

•	a $33 million decrease in retail rider revenues primarily related to decreased revenue requirements in the current year; and

•	a $14 million decrease in weather-normal retail sales volumes.

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•	a $90 million decrease in impairment charges primarily due to a prior year impairment at Citrus County CC and a reduction of the impairment in the current year; and

•	a $73 million decrease in fuel used in electric generation and purchased power primarily due to lower purchased power and lower fuel costs, net of deferrals.

•	a $74 million increase in depreciation and amortization expense primarily due to base rate adjustments related to Citrus County CC being placed in service, other additional plant in service and increases resulting from the 2018 Crystal River Unit 3 nuclear decommissioning cost study;

•	an $18 million increase in property and other taxes primarily due to higher property taxes from additional plant in service; and

•	a $9 million increase in operation, maintenance and other expense primarily due to increased vegetation management costs and deregulation initiative costs, partially offset by lower severance charges.

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•	a $45 million decrease in fuel related revenues primarily due to a decrease in price;

•	a $31 million decrease in rider revenues primarily due to the cessation of the Smart Grid Rider in 2018 and the Tax Cut and Jobs Act Rider beginning in 2019, partially offset by new riders implemented in conjunction with rate cases including the Price Stabilization Rider, Electric Service Reliability Rider and the Environmental Surcharge Mechanism;

•	a $15 million decrease in FTR rider revenues; and

•	a $12 million decrease in electric and natural gas retail sales, net of fuel revenues, due to unfavorable weather in the current year.

•	a $71 million increase in retail pricing primarily due to rate case impacts; and

•	an $18 million increase in PJM point-to-point transmission revenues due to an increase in the Network Integration Transmission Service rate primarily due to additional plant in service.

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•	a $40 million increase in operations, maintenance and other expense primarily due to the FERC approved settlement refund of certain transmission costs previously billed by PJM recorded in 2018 and increased PJM transmission expansion fees; and

•	an $18 million increase in property and other taxes primarily due to additional plant in service, partially offset by a negotiated reassessment of property values and property tax true ups for prior periods.

•	a $24 million decrease in fuel used in electric generation and purchased power expense due to the prior year outage at East Bend Station and the deferral of OVEC related purchased power costs; and

•	an $18 million decrease in the cost of natural gas primarily due to lower costs passed through to customers, as a result of a lower natural gas prices.

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•	a $21 million decrease in wholesale power revenues primarily due to the expiration of a contract with a wholesale customer;

•	a $16 million decrease in other transmission FTR revenues due to lower congestion; and

•	a $14 million decrease in weather-normal retail sales volume.

•	a $65 million decrease in fuel used in electric generation and purchased power expense primarily due to lower coal and natural gas costs, partially offset by higher purchase power fuel clause, higher amortization of deferred fuel costs and higher deferred MISO charges; and

•	a $30 million decrease in impairments primarily due to the prior year Edwardsport IGCC settlement agreement.

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•	a $24 million increase due to North Carolina base rate case increases;

•	a $19 million increase due to North Carolina and Tennessee IMR increases; and

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•	an $11 million increase due to NCUC approval related to tax reform accounting from fixed rate contracts.

•	a $52 million decrease due to lower natural gas costs passed through to customers.

•	a $52 million decrease in cost of natural gas due to lower natural gas prices; and

•	a $29 million decrease in operation, maintenance and other expense due to lower information technology outside services and labor costs.

•	a $13 million increase in depreciation and amortization expense due to additional plant in service.

•	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 $241 million increase in net income after adjustment for non-cash items primarily due to increases in revenues as a result of rate increases in the current year, partially offset by decreases in current year non-cash adjustments;

•	a $573 million refund of AMT credit carryforwards;

•	a $253 million decrease in cash outflows from working capital primarily due to fluctuations in accounts receivable balances, including a prior year increase for AMT refunds, and prior year increases in regulatory assets related to fuel costs, partially offset by fluctuations in inventory levels and current year decreases in property tax and severance accruals; and

•	a $105 million payment in the prior year for disposal of Beckjord.

•	a $213 million increase in payments for AROs.

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•	a $1,962 million increase in proceeds from the issuance of preferred stock;

•	a $1,222 million net increase in proceeds from issuances of long-term debt primarily due to timing of issuances and redemptions of long-term debt; and

•	an $802 million increase in contributions from noncontrolling interests, including $415 million related to the sale of a noncontrolling interest in the Commercial Renewables segment.

•	a $1,454 million decrease in proceeds from the issuance of common stock; and

•	a $1,551 million decrease in net borrowings from notes payable and commercial paper primarily due to the use of proceeds from the preferred stock issuance and increased long-term debt issuances used to pay down outstanding commercial paper.

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(a)	See Note 7 to the Consolidated Financial Statements, “Debt and Credit Facilities.”

(b)	Interest payments on variable rate debt instruments were calculated using December 31, 2019, interest rates and holding them constant for the life of the instruments.

(c)	See Note 6 to the Consolidated Financial Statements, “Leases.” Amounts in the table above include the interest component of finance 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, 2019, 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 PPA. See Note 18 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 10 to the Consolidated Financial Statements, "Asset Retirement Obligations."

(i)	Related to Commercial Renewables wind facilities.

(j)	Unrecognized tax benefits of $126 million are not reflected in this table as Duke Energy cannot predict when open income tax years will close with completed examinations. See Note 24 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 23 to the Consolidated Financial Statements, "Employee Benefit Plans"), AROs, including ash management expenditures (see Note 10 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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•	Clean Water Act

•	Steam Effluent Limitation Guidelines

•	Cross-State Air Pollution Rule

•	Clean Power Plan/ACE Rule

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•	We tested the effectiveness of controls over the accounting for the ACP equity method investment, including those over the development of the fair value estimate.

•	We evaluated the likelihood of the various outcomes used by management to develop the probability-weighted scenarios of future cash flows by:

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◦	Obtaining letters and making inquiries from the ACP’s internal and external legal counsel regarding likely outcomes of future court rulings

◦	Reading information included in the Company’s and the project manager’s press releases, regulatory filings and orders, legal briefs and orders, and analyst and industry reports

◦	Reading internal communications to management and the Board of Directors

◦	Comparing the various scenarios to scenarios previously developed by management

•	We evaluated the reasonableness of the key assumptions used to develop the scenarios of future cash flows by comparing key assumptions to:

◦	Internal communications and schedules to management and the Board of Directors

◦	Information included in the Company’s and the project manager’s press releases, regulatory filings and related orders

◦	Industry reports and external transaction data

◦	Executed contracts and invoices

•	With the assistance of our fair value specialists, we evaluated the reasonableness of the (1) valuation methodology and (2) discount rate used to develop the fair value estimate by:

◦	Determining the appropriateness of the valuation methodology by comparing management’s methodology to generally accepted valuation practice

◦	Testing the mathematical accuracy of the fair value estimate

◦	Testing the source information underlying the determination of the discount rate

◦	Developing a range of independent estimates of the discount rate and comparing those to the discount rate selected by management

•	We tested the effectiveness of management’s controls over the evaluation of the likelihood of the recovery in future rates of regulatory assets and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates.

•	We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

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We read relevant regulatory orders issued by the Commissions, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates based on precedence of the Commission’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset balances for completeness.

•	For regulatory matters in process, we inspected the Company’s and intervenors’ filings with the Commissions that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.

•	We performed audit procedures on the incurred costs requested for recovery to confirm their completeness and accuracy.

•	We obtained an analysis from management and letters from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery.

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(a)	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.

(b)	Amounts in Retained Earnings and AOCI 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.

(c)	Duke Energy issued 40 million depositary shares of preferred stock, series A, in the first quarter of 2019.

(d)	Duke Energy issued 1 million shares of preferred stock, series B, in the third quarter of 2019.

(e)	See Note 3 for additional discussion of the transaction.

(f)	Amounts in Retained Earnings and AOCI primarily represent impacts to accumulated other comprehensive income due to implementation of a new accounting standard related to Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.

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

(b)	Amounts in Retained Earnings and AOCI 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.

(c)	Amounts in Retained Earnings and AOCI primarily represent impacts to accumulated other comprehensive income due to implementation of a new accounting standard related to Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.

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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)	Electric Utilities and Infrastructure includes a $27 million reduction of a prior year impairment at Citrus County CC related to the plant's cost cap. See Note 4 for additional information.

(b)	Gas Utilities and Infrastructure includes an after-tax impairment charge of $19 million for the remaining investment in Constitution. See Note 13 for additional information.

(c)	Includes the allocation of losses to noncontrolling tax equity members. See Note 1 for additional information.

(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 24 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 13 for additional information.

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(d)	Commercial Renewables includes an impairment charge of $91 million, net of $2 million Noncontrolling interests, related to goodwill. See Note 12 for additional information.

(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 Beckjord described below. For additional information, see Note 2 for the Piedmont Merger and Note 21 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.

(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 11 and 12 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)	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 24.

(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 23 for additional detail.

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•	Approval of cancellation of the Lee Nuclear Project, with Duke Energy Carolinas maintaining the Combined Operating License;

•	Approval of recovery of $125 million (South Carolina retail portion) of Lee Nuclear Project development costs (including AFUDC through December 2017) over a 12-year period, but denial of a return on the deferred balance of costs;

•	Approval of recovery of $96 million of coal ash costs over a five-year period with a return at Duke Energy Carolinas' WACC;

•	Denial of recovery of $115 million of certain coal ash costs deemed to be related to the Coal Ash Act and incremental to the federal CCR rule;

•	Approval of a $66 million decrease to base rates to reflect the change in ongoing tax expense, primarily the reduction in the federal income tax rate from 35% to 21%;

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Approval of a $45 million decrease through the EDIT Rider to return EDIT resulting from the federal tax rate change and deferred revenues since January 2018 related to the change, to be returned in accordance with the Average Rate Assumption Method (ARAM) for protected EDIT, over a 20-year period for unprotected EDIT associated with Property, Plant and Equipment, over a five-year period for unprotected EDIT not associated with Property, Plant and Equipment and over a five-year period for the deferred revenues; and

•	Approval of a $17 million decrease through the EDIT Rider related to reductions in the North Carolina state income tax rate from 6.9% to 2.5% to be returned over a five-year 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)	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 23 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.

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•	Approval of recovery of $4 million of coal ash costs over a five-year period with a return at Duke Energy Progress' WACC;

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•	Denial of recovery of $65 million of certain coal ash costs deemed to be related to the Coal Ash Act and incremental to the federal CCR rule;

•	Approval of a $17 million decrease to base rates to reflect the change in ongoing tax expense, primarily the reduction in the federal income tax rate from 35% to 21%;

•

Approval of a $12 million decrease through the EDIT Tax Savings Rider resulting from the federal tax rate change and deferred revenues since January 2018 related to the change, to be returned in accordance with ARAM for protected EDIT, over a 20-year period for unprotected EDIT associated with Property, Plant and Equipment, over a five-year period for unprotected EDIT not associated with Property, Plant and Equipment and over a three-year period for the deferred revenues; and

•	Approval of a $12 million increase due to the expiration of EDIT related to reductions in the North Carolina state income tax rate from 6.9% to 2.5%.

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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/pay 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 23 for additional detail.

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

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

(c)	Included in rate base.

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

(e)	Recovered via a rider mechanism.

(f)	Includes incentives on DSM/EE investments.

(g)	Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 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)	Refunded 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 23 for additional detail.

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

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

(c)	Included in rate base.

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

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

(f)	Recovered primarily over the average remaining service periods or life expectancies of employees covered by the benefit plans. See Note 23 for additional detail.

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•	An annual increase in revenues of $109 million before consideration of riders associated with federal and state tax reform;

•	A decrease through a rider mechanism of $23 million per year to return unprotected federal EDIT over a five-year period and deferred revenues related to the federal rate reduction of $37 million to be returned over one year;

•	A decrease through a rider mechanism of $21 million per year related to reductions in the North Carolina state income tax rate to be returned over a three-year period;

•	An overall cap on net revenue increase of $83 million. This will impact Piedmont beginning November 1, 2022, only if the company does not file another general rate case in the interim;

•	Continuation of the IMR mechanism; and

•	Establishment of a new deferral mechanism for certain Distribution Integrity Management Program (DIMP) operations and maintenance expenses incurred effective November 1, 2019, and thereafter.

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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.

(c)	On July 1, 2019, Duke Energy Indiana filed its 2018 IRP with the IURC. The 2018 IRP included scenarios evaluating the potential retirement of coal-fired generating units at Gibson and Cayuga. The rate case filed July 2, 2019, includes proposed depreciation rates reflecting retirement dates from 2026 to 2038.

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(a)	Contracts represent either 100% of net plant output or vary.

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

(c)	Contracts represent between 1% and 9% of net plant output.

(d)	Excludes PPA with OVEC. See Note 18 for additional information.

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(a)	Included in Operations, maintenance and other or, for barges and railcars, Fuel used in electric generation and purchased power on the Consolidated Statements of Operations.

(b)	Included in Depreciation and amortization on the Consolidated Statements of Operations.

(c)	Included in Interest Expense on the Consolidated Statements of Operations.

(a)	Certain operating lease payments include renewal options that are reasonably certain to be exercised.

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(a)	No amounts were classified as investing cash flows from operating leases for the year ended December 31, 2019.

(b)	Does not include ROU assets recorded as a result of the adoption of the new lease standard.

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(a)

The discount rate is calculated using the rate implicit in a lease if it is readily determinable. Generally, the rate used by the lessor is not provided to Duke Energy and in these cases the incremental borrowing rate is used. Duke Energy will typically use its fully collateralized incremental borrowing rate as of the commencement date to calculate and record the lease. The incremental borrowing rate is influenced by the lessee’s credit rating and lease term and as such may differ for individual leases, embedded leases or portfolios of leased assets.

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

(b)	Duke Energy includes $44 million and $419 million of finance lease purchase accounting adjustments related to Duke Energy Progress and Duke Energy Florida, respectively, related to PPAs that are not accounted for as finance 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 classified as Long-Term Debt on the Consolidated Balance Sheets due to the existence of long-term credit facilities that backstop these commercial paper balances, along with Duke Energy’s ability and intent to refinance these balances on a long-term basis. The weighted average days to maturity for Duke Energy's commercial paper program was 14 days.

(e)	Duke Energy includes $1,275 million and $137 million in purchase accounting adjustments related to Progress Energy and Piedmont, respectively.

(f)	Duke Energy includes $37 million in purchase accounting adjustments primarily related to the merger with Progress Energy.

(g)	Refer to Note 18 for additional information on amounts from consolidated VIEs.

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

(b)	Duke Energy includes $63 million and $531 million of finance lease purchase accounting adjustments related to Duke Energy Progress and Duke Energy Florida, respectively, related to PPAs that are not accounted for as finance 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 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 18 for additional information on amounts from consolidated VIEs.

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(a)	Debt has a floating interest rate.

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

(a)	Excludes $1,448 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 and for general corporate purposes.

(b)	Debt issuance has a floating interest rate.

(c)	Debt issued to repay at maturity $450 million first mortgage bonds due April 2019, pay down short-term debt and for general corporate purposes.

(d)	Debt issued to fund eligible green energy projects in the Carolinas.

(e)	Debt issued to repay in full the outstanding $350 million Piedmont unsecured term loan due September 2019, pay down short-term debt and for general corporate purposes.

(f)	Debt issued to retire $150 million of pollution control bonds, pay down short-term debt and for general corporate purposes.

(g)	Debt issued to repay at maturity $100 million debentures due October 2019, pay down short-term debt and for general corporate purposes.

(h)	Debt issued to fund storm restoration costs and for general corporate purposes.

(i)	Debt issued to reimburse the payment of existing and new Eligible Green Expenditures in Florida.

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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 purposes.

(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.

(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 IMPA.

(d)	Jointly owned with WVPA.

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

(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 was filed with the NCUC and PSCSC in 2019. A new funding study was also completed and filed with the NCUC and PSCSC in 2019.

(d)	Duke Energy Progress' site-specific nuclear decommissioning cost study completed in 2019 is expected to be filed with the NCUC and PSCSC during the first quarter 2020. Duke Energy Progress will also complete a new funding study, which will be completed and filed with the NCUC and PSCSC in July 2020.

(e)	During 2019, Duke Energy Florida reached an agreement to transfer decommissioning work for Crystal River Unit 3 to a third party. The agreement requires regulatory approval from the NRC and the FPSC. See Note 4 for more information.

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(a)	Substantially all accretion expense for the years ended December 31, 2019, and 2018, 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 closure estimates for certain ash impoundments as a result of the NCDEQ's April 1 Order and the related settlement agreement dated December 31, 2019. See Note 5 for more information. The amount recorded in the fourth quarter of 2019 for coal ash closures as a result of the settlement was not material.

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(a)

Includes finance leases of $952 million, $211 million, $443 million, $308 million, $135 million and $10 million at Duke Energy, Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida and Duke Energy Indiana, respectively, primarily within Plant – Regulated. The Progress Energy, Duke Energy Progress and Duke Energy Florida amounts are net of $143 million, $17 million and $126 million, respectively, of accumulated amortization of finance leases.

(b)	Includes $1,807 million, $1,082 million, $725 million and $725 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 finance leases of $6 million, $13 million and $3 million at Duke Energy, Duke Energy Carolinas and Duke Energy Indiana, respectively.

(d)	Includes accumulated amortization of finance leases of $20 million at Duke Energy.

(e)	Includes gross property, plant and equipment cost of consolidated VIEs of $5,747 million and accumulated depreciation of consolidated VIEs of $1,041 million at Duke Energy.

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(a)

Includes finance 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 finance 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 finance 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)

Duke Energy evaluated the recoverability of goodwill during 2018 and 2017 and recorded impairment charges of $93 million and $29 million, respectively, related to the Commercial Renewables reporting unit included in Impairment charges on Duke Energy’s Consolidated Statements of Operations. The fair value of the reporting unit was determined based on the income approach and market approach in 2018 and 2017, respectively. See "Goodwill Impairment Testing" below for the results of the 2019 goodwill impairment test.

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

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

(c)	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.

(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.

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(a)	Duke Energy includes amounts related to consolidated VIEs of $693 million in cash flow hedges as of December 31, 2019, and $422 million in cash flow hedges and $194 million in undesignated contracts as of December 31, 2018.

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(a)	During the year ended December 31, 2019, Duke Energy Florida continued to receive reimbursements from the NDTF for costs related to ongoing decommissioning activity of the Crystal River Unit 3.

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(a)	Book value of long-term debt includes $1.5 billion as of December 31, 2019, and $1.6 billion as of December 31, 2018, 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)

Duke Energy holds a 50% equity interest in Pioneer. As of December 31, 2018, Pioneer was considered a VIE due to having insufficient equity to finance its own activities without subordinated financial support. In October 2019, Pioneer closed on a private placement debt offering that gave Pioneer sufficient equity to finance its own activities and, therefore, is no longer considered a VIE. Duke Energy's investment in Pioneer was $57 million at December 31, 2019.

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(a)	Duke Energy evaluated this investment for impairment as of December 31, 2019, and 2018, and determined that fair value approximated carrying value and therefore no impairment was necessary.

(b)

During the years ended December 31, 2019, and 2018, Duke Energy recorded an OTTI of $25 million and $55 million, respectively, related to Constitution within Equity in earnings of unconsolidated affiliates on Duke Energy's Consolidated Statements of Income. The current year charge resulted in the full write-down of Duke Energy's investment in Constitution. See Notes 4 and 13 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)	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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•	senior to Common Stock and to each other class or series of capital stock established after the original issue date of the Series A and Series B Preferred Stock that is expressly made subordinated to the Series A and Series B Preferred Stock;

•	on a parity with any class or series of capital stock established after the original issue date of the Series A and Series B Preferred Stock that is not expressly made senior or subordinated to the Series A or Series B Preferred Stock;

•	junior to any class or series of capital stock established after the original issue date of the Series A and Series B Preferred Stock that is expressly made senior to the Series A or Series B Preferred Stock;

•	junior to all existing and future indebtedness (including indebtedness outstanding under Duke Energy's credit facilities, unsecured senior notes, junior subordinated debentures and commercial paper) and other liabilities with respect to assets available to satisfy claims against Duke Energy; and

•	structurally subordinated to existing and future indebtedness and other liabilities of Duke Energy's subsidiaries and future preferred stock of subsidiaries.

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(a)	Duke Energy amounts exclude $4 million, $5 million and $7 million for the years ended December 2019, 2018 and 2017, respectively, of regulatory asset amortization resulting from purchase accounting adjustments associated with Duke Energy's merger with Cinergy in April 2006.

(b)	Duke Energy Ohio amounts exclude $2 million, $2 million and $3 million for the years ended December 2019, 2018 and 2017, 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 $6 million, $7 million and $7 million for the years ended December 2019, 2018 and 2017, 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 2019, 2018 and 2017, 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 26%, 31%, 15%, 17%, 5%, 7%, and 4%, respectively, of the Duke Energy Master Retirement Trust at December 31, 2019. 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)

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

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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)

Total deferred income taxes includes the generation of tax credit carryforwards of $8 million at Duke Energy Carolinas. In addition, total deferred income taxes includes utilization of NOL carryforwards and tax credit carryforwards of $243 million at Progress Energy, $35 million at Duke Energy Progress, $152 million at Duke Energy Florida, $25 million at Duke Energy Ohio, $60 million at Duke Energy Indiana, $90 million at Piedmont and $775 million at Duke Energy.

(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.

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(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.

(a)	Includes a $16 million expense in 2017 related to the Tax Act impact on equity earnings included within Equity in earnings 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 NOLs, and valuation allowance on foreign tax credits.

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

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

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(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 $97 million has been recorded on the state NOL and credit 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 $387 million has been recorded on the foreign tax credits, as presented in the Net Deferred Income Tax Liability Components table.

(e)	A valuation allowance of $87 million has been recorded on the Federal capital loss carryforward, as presented in the Net Deferred Income Tax Liability Components table.

(f)	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.

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

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(a)	The Duke Energy Registrants are unable to estimate the specific amounts that would affect the effective tax rate versus the regulatory liability.

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(1)	As of December 31, 2019, no options were outstanding under equity compensation plans.

(2)	Includes RSUs 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 Duke Energy Corporation Executive Savings Plan (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 the Duke Energy Corporation Directors' Savings Plan (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.

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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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