Duke Energy CORP - Quarter Report: 2020 September (Form 10-Q)

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Registrant	Title of each class    Trading symbols        which registered

Duke Energy	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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◦	The impact of the COVID-19 pandemic;

◦	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;

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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;

◦	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 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)	Net of income tax impacts of approximately $24 million for the three months ended September 30, 2020, and $43 million and $14 million for the nine months ended September 30, 2020, and 2019, respectively. All other periods presented include immaterial income tax impacts.

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

(b)	See Note 2 for additional discussion of the transaction.

(c)	Duke Energy issued 40 million depositary shares of preferred stock, Series A.

(d)	Relates to tax equity financing activity in the Commercial Renewables segment.

(e)	Amounts in Retained Earnings and Accumulated Other Comprehensive (Loss) Income 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.

(f)	Amounts in Retained earnings primarily represent impacts due to implementation of a new accounting standard related to Current Estimated Credit Losses. See Note 1 for additional discussion.

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(a)	Amounts primarily represent impacts due to implementation of a new accounting standard related to Current Estimated Credit Losses. See Note 1 for additional discussion.

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(a)	Amounts in Retained Earnings and Accumulated Other Comprehensive (Loss) Income 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)

Electric Utilities and Infrastructure includes $19 million recorded within Impairment charges and $8 million recorded within Operations, maintenance and other on the Duke Energy Carolinas' Condensed Consolidated Statements of Operations related to a partial settlement in the Duke Energy Carolinas' 2019 North Carolina rate case and $8 million recorded within Operations, maintenance and other on Duke Energy Progress' Condensed Consolidated Statements of Operation related to a partial settlement in the Duke Energy Progress' 2019 North Carolina rate case. See Note 3 for more information. Additionally, Electric Utilities and Infrastructure includes $5 million of Impairment charges related to gas pipeline assets recorded on Duke Energy Progress' Condensed Consolidated Statements of Operations.

(b)	Gas Utilities and Infrastructure includes $78 million recorded within Equity in (losses) earnings of unconsolidated affiliates on the Condensed Consolidated Statements of Operations and $7 million in Impairment charges recorded on the Piedmont Condensed Consolidated Statements of Operations related to gas pipeline investments.

(c)	Electric Utilities and Infrastructure includes a $25 million reduction of a prior year impairment recorded at Citrus County CC related to the plant's cost cap and is recorded within Impairment charges on Duke Energy Florida's Condensed Consolidated Statements of Operations.

(a)

Electric Utilities and Infrastructure includes $19 million recorded within Impairment charges and $8 million recorded within Operations, maintenance and other on the Duke Energy Carolinas' Condensed Consolidated Statements of Operations related to a partial settlement in the Duke Energy Carolinas' 2019 North Carolina rate case and $8 million recorded within Operations, maintenance and other on Duke Energy Progress' Condensed Consolidated Statements of Operation related to a partial settlement in the Duke Energy Progress' 2019 North Carolina rate case. See Note 3 for more information. Additionally, Electric Utilities and Infrastructure includes $5 million of Impairment charges related to gas pipeline assets recorded on Duke Energy Progress' Condensed Consolidated Statements of Operations.

(b)	Gas Utilities and Infrastructure includes $2.1 billion recorded within Equity in (losses) earnings of unconsolidated affiliates on the Condensed Consolidated Statements of Operations and $7 million of Impairment charges recorded on the Piedmont Condensed Consolidated Statements of Operations related to gas pipeline investments. See Notes 3 and 12 for additional information.

(c)	Other includes a $98 million reversal, included in Operations, maintenance and other on the Condensed Consolidated Statements of Operations, of 2018 severance costs due to a partial settlement in the Duke Energy Carolinas' 2019 North Carolina rate case. See Note 3 for additional information.

(d)	Electric Utilities and Infrastructure includes a $25 million reduction of a prior year impairment recorded at Citrus County CC related to the plant's costs cap and is recorded within Impairment charges on Duke Energy Florida's Condensed Consolidated Statements of Operations.

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•	Removal of deferred storm costs from the rate case;

•	Filing a petition seeking to securitize the deferred storm costs within 120 days of a commission order in this rate case regarding the reasonableness and prudency of the storm costs;

•	Agreement of certain assumptions to demonstrate the quantifiable benefits to customers of a securitization financing; and

•	Agreement on certain accounting matters, including recovery of employee incentives, severance, aviation costs and executive compensation.

•	A return on equity of 9.6% and a capital structure of 52% equity and 48% debt;

•	Agreement on amortization over a five-year period for unprotected federal EDIT flowbacks to customers;

•	Agreement on the inclusion of plant in service and other revenue requirement updates through May 31, 2020, subject to Public Staff review. Annual revenue requirement associated with the May 31 update is estimated at $45 million; and

•	Settlement to allow the deferral of costs for certain grid projects placed in service between June 1, 2020, and December 31, 2022, totaling $0.8 billion.

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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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•	Removal of deferred storm costs from the rate case;

•	Filing a petition seeking to securitize the deferred storm costs within 120 days of a commission order in this rate case regarding the reasonableness and prudency of the storm costs;

•	Agreement of certain assumptions to demonstrate the quantifiable benefits to customers of a securitization financing;

•	Agreement that the Asheville CC project is complete and in service and agreement on the amount to be included in rate base; and

•	Agreement on certain accounting matters, including recovery of employee incentives, severance, aviation costs and executive compensation.

•	A return on equity of 9.6% and a capital structure of 52% equity and 48% debt;

•	Agreement on amortization over a five-year period for unprotected federal EDIT flowbacks to customers;

•	Agreement on the inclusion of plant in service and other revenue requirement updates through May 31, 2020, subject to Public Staff review. Annual revenue requirement associated with the May 31 update is estimated at $25 million; and

•	Settlement to allow the deferral of costs for certain grid projects placed in service between June 1, 2020, and December 31, 2022, of $0.5 billion.

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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;

•	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%;

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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)	As part of the 2015 resolution of a lawsuit involving alleged New Source Review violations, Duke Energy Carolinas must retire Allen Steam Station Units 1 through 3 by December 31, 2024. The long-term energy options considered in the IRP could result in retirement of these units earlier than their current estimated useful lives.

(b)

These units are included in the IRP filed by Duke Energy Carolinas and Duke Energy Progress in North Carolina and South Carolina on September 1, 2020. The long-term energy options considered in the IRP could result in retirement of these units earlier than their current estimated useful lives. In 2019, Duke Energy Carolinas and Duke Energy Progress filed North Carolina rate cases that included depreciation studies that accelerate end of life dates for these plants. A decision by NCUC is expected by the end of the first quarter 2021.

(c)	Duke Energy Indiana committed to either retire or stop burning coal at Gallagher units 2 and 4 by December 31, 2022, as part of the 2016 settlement of Edwardsport IGCC matters.

(d)

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, included proposed depreciation rates reflecting retirement dates from 2026 to 2038. The depreciation rates reflecting these updated retirement dates were approved by the IURC as part of the rate case order issued on June 29, 2020.

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(a)	Debt issued to repay $500 million borrowing made under Duke Energy (Parent) revolving credit facility in March 2020, and for general corporate purposes.

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

(c)	Debt issued to repay $700 million two-year term loan facility expiring in December 2020.

(d)	Debt issuance has a floating interest rate.

(e)	Debt issued to repay a portion of outstanding commercial paper, to repay a portion of Duke Energy (Parent)'s outstanding $1.7 billion term loan due March 2021 and for general corporate purposes.

(f)	Debt issued to repay at maturity $450 million first mortgage bonds due June 2020 and for general corporate purposes.

(g)	Debt issued to repay at maturity $500 million first mortgage bonds due July 2020 and to pay down short-term debt.

(h)	Debt issued to repay at maturity $300 million first mortgage bonds due September 2020 and for general corporate purposes.

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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 on the Condensed Consolidated Balance Sheets.

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

(b)	For the nine months ended September 30, 2020, substantially all accretion expense relates to Duke Energy's regulated operations and has been deferred in accordance with regulatory accounting treatment.

(c)	Primarily relates to ash impoundment closures.

(d)

Primarily relates to increases in closure estimates for certain ash impoundments as a result of certain changes in estimates and the impact of Hoosier Environmental Council’s petition filed with the court challenging the Indiana Department of Environmental Management’s partial approval of Duke Energy Indiana’s ash pond closure plan, new closure plan approvals, as well as increased post closure maintenance, landfill and beneficiation costs. See Note 4 for more information on Hoosier Environmental Council's petition. The incremental amount recorded represents the discounted cash flows for estimated closure costs based upon the probability weightings of the potential closure methods as evaluated on a site-by-site basis.

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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 Condensed Consolidated Statements of Operations and Comprehensive Income.

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

(c)

Duke Energy Carolinas and Duke Energy Progress participate in a JDA, which allows the collective dispatch of power plants between the service territories to reduce customer rates. Revenues from the sale of power 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 Condensed 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 Condensed Consolidated Statements of Operations and Comprehensive Income.

(e)	Piedmont has related party transactions as a customer of its equity method investments in Pine Needle LNG Company, LLC, Hardy Storage Company, LLC and Cardinal Pipeline Company, LLC natural gas storage and transportation facilities. These expenses are included in Cost of natural gas on Piedmont's Condensed Consolidated Statements of Operations and Comprehensive Income.

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(a)	Duke Energy includes amounts related to consolidated VIEs of $653 million in cash flow hedges as of September 30, 2020, and $693 million in cash flow hedges as of December 31, 2019.

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(a)	Duke Energy includes 11,116 GWh that relates to cash flow hedges.

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(a)	During the nine months ended September 30, 2020, Duke Energy Florida continued to receive reimbursements from the NDTF for costs related to ongoing decommissioning activity of Crystal River Unit 3.

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(a)	Book value of long-term debt includes $1.4 billion at September 30, 2020, and $1.5 billion at December 31, 2019, of unamortized debt discount and premium, net of 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)	During the quarter ended June 30, 2020, Duke Energy determined that it would no longer continue its investment in ACP as described above. The current liability related to the cancellation of the ACP pipeline project represents Duke Energy's continuing obligation to fund its share of ACP's obligations. See Notes 1, 3 and 4 for more information.

(b)	During the year ended December 31, 2019, Duke Energy recorded an other-than-temporary impairment related to Constitution. This charge resulted in the full write-down of Duke Energy's investment in Constitution.

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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)	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.

(b)	5.75% Series A Cumulative Redeemable Perpetual Preferred Stock dividends are payable quarterly in arrears on the 16th day of March, June, September and December. The preferred stock has a $25 liquidation preference per depositary share.

(c)	4.875% Series B Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock dividends are payable semiannually in arrears on the 16th day of March and September. The preferred stock has a $1,000 liquidation preference per share.

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Employees. The health of our employees is of paramount importance. Power plants and electricity and natural gas delivery facilities are staffed. Employees who are not involved with power generation, power delivery, customer service or certain other functions have been performing their work duties remotely from home. Employees who need to interact with customers in person are following the Centers for Disease Control and Prevention’s safety guidelines, including social distancing and use of face masks. Operating procedure changes include additional cleaning and disinfection procedures at our facilities.

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Customers. The Duke Energy Subsidiary Registrants have resumed certain standard billing and credit practices, disconnections for nonpayment and late payment charges, all of which were previously suspended in the first quarter of 2020 in order to give customers experiencing financial hardship extra time to make payments. See Note 3 to the Condensed Consolidated Financial Statements, "Regulatory Matters," for additional information. The COVID-19 pandemic and stay-at-home orders caused many commercial and industrial customers to reduce or suspend operations beginning in late March and April, which has impacted the Duke Energy Registrants’ volumes during the nine months ended September 30, 2020. Many of these customers have begun to restart their businesses.

•	Communities. The Duke Energy Foundation announced approximately $6.5 million in donations and grants during the nine months ended September 30, 2020, to support hunger relief, local health and human services nonprofits, and education initiatives across the Duke Energy Registrants’ service territories.

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Policymaker actions. The CARES Act was signed by President Trump on March 27, 2020. Duke Energy Registrants are benefiting from certain provisions such as the accelerated refund of AMT credits, which resulted in receipt of a $572 million refund and $19 million of interest income in September 2020, and deferral of certain payroll taxes through December 31, 2020. See Note 16 to the Condensed Consolidated Financial Statements, “Income Taxes,” for additional information.

•	Cost mitigation. Duke Energy has developed and executed a significant cost containment plan during 2020 to offset a portion of the revenue decline experienced as a result of the COVID-19 pandemic. This plan includes a variety of cost efficiency measures, including managing plant costs due to lower production, lower employee expenses and lower financing costs due to favorable market conditions.

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On July 31, 2020, Duke Energy Carolinas, Duke Energy Progress and the Public Staff filed a Second Agreement and Stipulation of Partial Settlement, which is subject to review and approval of the NCUC, resolving certain remaining issues in the 2019 base rate proceeding. The Duke Energy Carolinas hearing concluded on September 18, 2020 and the Duke Energy Progress hearing concluded on October 6, 2020. Duke Energy Carolinas and Duke Energy Progress expect the NCUC to issue an order on each net rate increase in early 2021. On August 4, 2020, and August 7, 2020, respectively, Duke Energy Carolinas and Duke Energy Progress filed a motion for approval of notice required to implement temporary rates, seeking to exercise its statutory right to implement temporary rates subject to refund. The NCUC approved these requests and rates were effective on August 24, 2020, and September 1, 2020, for Duke Energy Carolinas and Duke Energy Progress, respectively.

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On October 26, 2020, Duke Energy Carolinas and Duke Energy Progress filed a joint petition with the NCUC seeking authorization for the financing of each utilities' storm recovery activities as a result of Hurricane Florence, Hurricane Michael, Hurricane Dorian and Winter Storm Diego. The total revenue requirement over the proposed 15-year bond period for the storm recovery charges is approximately $262 million for Duke Energy Carolinas and $842 million for Duke Energy Progress. The utilities estimate that securitization of the respective storm recovery costs will result in expected customer savings of 32% for Duke Energy Carolinas customers and 33% for Duke Energy Progress customers.

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Duke Energy Indiana filed a general rate case with the IURC on July 2, 2019. The IURC issued its order June 29, 2020, approving a revenue increase of approximately $146 million, before utility receipt taxes. Step one rates are estimated to be approximately 75% of the total and became effective on July 30, 2020. Step two rates are estimated to be the remaining 25% of the total rate increase and will be effective in the first quarter of 2021. Several groups filed notices of appeal of the IURC order on July 29, 2020.

•	COVID-19 deferral requests

◦	Duke Energy Carolinas and Duke Energy Progress filed a joint petition with the NCUC for deferral treatment of incremental costs and waived customer fees due to the COVID-19 pandemic on August 7, 2020. Duke Energy Carolinas and Duke Energy Progress filed a similar request with the PSCSC on August 14, 2020.

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Duke Energy Ohio on May 11, 2020, filed with the PUCO a request seeking deferral of incremental costs incurred due to the COVID-19 pandemic, as well as specific miscellaneous lost revenues. The request seeks to use existing bad debts and uncollectible riders already in place for both electric and natural gas operations. Duke Energy Ohio would subsequently file for rider recovery at a later date. On June 17, 2020, the PUCO approved Duke Energy Ohio’s deferral application.

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On May 8, 2020, Duke Energy Indiana, along with other Indiana utilities, filed a request with the IURC for approval of deferral treatment for costs associated with the COVID-19 pandemic. On June 29, 2020, the IURC issued its order permitting jurisdictional utilities to use regulatory accounting for any impacts associated with the prohibition on utility disconnections, waiver or exclusion of certain utility fees, the use of expanded payment arrangements to aid customers, and for COVID-19 related uncollectible and incremental bad debt expense.

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•	Gas Pipeline Investments represents costs related to the cancellation of the ACP pipeline and additional exit costs related to Constitution.

•	Severance represents the reversal of 2018 costs, which were deferred as a result of a partial settlement in the Duke Energy Carolinas and the Duke Energy Progress 2019 North Carolina rate cases.

•	Regulatory Settlements represents charges related to Duke Energy Carolinas' and Duke Energy Progress' partial settlements in the 2019 North Carolina rate cases.

•	Impairment Charges represents a reduction of a prior year impairment at Citrus County CC.

(a)	Net of tax benefit of $21 million.

(b)	Net of tax benefit of $8 million.

(c)	Net of $6 million tax expense.

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(a)	Net of tax benefit of $395 million.

(b)	Net of tax expense of $23 million.

(c)	Net of tax benefit of $8 million.

(d)	Net of tax expense of $6 million.

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•	a $168 million decrease in fuel revenues driven by lower sales volumes as well as an accelerated refund of fuel costs at Duke Energy Florida in response to the COVID-19 pandemic;

•	a $75 million decrease in retail sales, net of fuel revenues, due to unfavorable weather compared to prior year; and

•	a $62 million decrease in rider revenues primarily due to energy efficiency programs.

•	a $75 million increase due to higher pricing from the Indiana retail rate case, net of rider revenues; and

•	a $28 million increase in retail pricing due to Duke Energy Florida's base rate adjustments related to annual increases from the 2017 Settlement Agreement and the Solar Base Rate Adjustment.

•	a $125 million decrease in fuel used in electric generation and purchased power primarily due to lower generation demand and lower fuel costs;

•	a $31 million decrease in operation, maintenance and other expense primarily driven by the deferral of 2018 severance costs due to the partial settlement agreement between Duke Energy Carolinas and the Public Staff of the NCUC related to the 2019 North Carolina retail rate case; and

•	a $15 million decrease in property and other taxes primarily due to prior year property tax reassessments.

•	a $40 million increase in impairment charges primarily due to an impairment of Duke Energy Carolina's Clemson assets and a prior year reduction of an impairment at Duke Energy Florida's Citrus County CC; and

•	a $27 million increase in depreciation and amortization expense primarily due to additional plant in service and change in depreciation rates due to the Indiana retail rate case.

•	a $642 million decrease in fuel revenues driven by lower sales volumes as well as an accelerated refund of fuel costs at Duke Energy Florida in response to the COVID-19 pandemic;

•	a $199 million decrease in retail sales, net of fuel revenues, due to unfavorable weather in the current year;

•	a $58 million decrease in wholesale revenues, net of fuel, primarily due to higher recovery of coal ash cost in the prior year and lower capacity volumes at Duke Energy Progress;

•	a $40 million decrease in rider revenues from energy efficiency programs; and

•	a $24 million decrease in weather-normal retail sale volumes due to lower nonresidential customer demand driven by impacts from the COVID-19 pandemic.

•	a $75 million increase due to higher pricing from the Indiana retail rate case, net of rider revenues;

•	a $67 million increase in retail pricing due to Duke Energy Florida's base rate adjustments related to annual increases from the 2017 Settlement Agreement and the Solar Base Rate Adjustment; and

•	a $32 million increase due to higher pricing from South Carolina retail rate case, net of a return of EDIT to customers.

•	a $583 million decrease in fuel used in electric generation and purchased power primarily due to lower generation demand and lower fuel, coal, and natural gas costs;

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•	a $66 million decrease in operation, maintenance and other expense primarily driven by the deferral of 2018 severance costs due to the partial settlement agreement between Duke Energy Carolinas and the Public Staff of the NCUC related to the 2019 North Carolina retail rate case; and

•	a $14 million decrease in property and other taxes primarily due to prior year property tax reassessments.

•	a $99 million increase in depreciation and amortization expense primarily due to additional plant in service and a change in depreciation rates from the Indiana and South Carolina retail rate cases; and

•	a $39 million increase in impairment charges primarily due to an impairment of Duke Energy Carolina's Clemson assets and a prior year reduction of an impairment at Duke Energy Florida's Citrus County CC.

•	an $8 million decrease due to lower natural gas costs passed through to customers and decreased off-system sales natural gas costs; and

•	a $4 million decrease due to return of EDIT to customers.

•	a $5 million increase due to North Carolina base rate case increases.

•	a $7 million decrease in cost of natural gas primarily due to lower natural gas prices and decreased off-system sales natural gas costs.

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•	a $7 million increase in impairment charges due to Piedmont ACP project materials write-off.

•	a $151 million decrease due to lower natural gas costs passed through to customers, lower volumes, and decreased off-system sales natural gas costs; and

•	a $31 million decrease due to return of EDIT to customers.

•	a $65 million increase due to North Carolina base rate case increases.

•	a $151 million decrease in cost of natural gas due to lower natural gas prices, lower volumes and decreased off-system sales natural gas costs; and

•	a $13 million decrease in operation, maintenance and other due to deferral of previously expensed IT project costs and employee labor and benefits costs.

•	a $7 million increase in impairment charges due to Piedmont ACP project materials write-off.

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

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•	a $131 million decrease in retail sales due to unfavorable weather in the current year;

•	an $86 million decrease in fuel revenues due to lower prices and retail sales volumes; and

•	a $22 million decrease in rider revenues primarily due to energy efficiency programs.

•	a $19 million increase in weather-normal retail sales volumes; and

•	a $17 million increase due to higher pricing from the South Carolina and North Carolina retail rate case, net of a return of EDIT to customers.

•	a $106 million decrease in operation, maintenance and other expense primarily driven by the deferral of 2018 severance costs due to the partial settlement agreement between Duke Energy Carolinas and the Public Staff of the NCUC related to the 2019 North Carolina retail rate case, partially offset by higher storm restoration costs; and

•	a $45 million decrease in fuel used in electric generation and purchased power primarily due to lower retail sales volumes, net of a prior period true up.

•	a $77 million increase in depreciation and amortization expense primarily due to additional plant in service and new depreciation rates associated with the South Carolina rate case.

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•	a $485 million decrease in fuel revenues driven by lower sales volumes as well as an accelerated refund of fuel costs in response to the COVID-19 pandemic at Duke Energy Florida and lower fuel prices, volumes and native load transfer sales in the current year at Duke Energy Progress;

•	a $47 million decrease in wholesale power revenues, net of fuel, primarily due to higher recovery of coal ash cost in the prior year and lower capacity volumes at Duke Energy Progress, partially offset by increased demand at Duke Energy Florida;

•	a $47 million decrease in retail sales, net of fuel revenues, due to unfavorable weather in the current year at Duke Energy Progress, partially offset by favorable weather in the current year at Duke Energy Florida;

•	a $44 million decrease in rider revenues primarily due to the Crystal River 3 uprate regulatory asset being fully recovered in 2019 at Duke Energy Florida; and

•	a $24 million decrease in weather-normal retail sales volume.

•	a $107 million increase in storm revenues due to Hurricane Dorian collections at Duke Energy Florida;

•	a $67 million increase in retail pricing due to base rate adjustments related to annual increases from the 2017 Settlement Agreement and the Solar Base Rate Adjustment at Duke Energy Florida;

•	a $15 million increase due to higher pricing from the South Carolina retail rate case, net of a return of EDIT to customers at Duke Energy Progress; and

•	an $8 million increase in other revenues primarily due to increased transmission and lighting equipment revenues at Duke Energy Florida.

•	a $472 million decrease in fuel used in electric generation and purchased power primarily due to lower demand and changes in generation mix at Duke Energy Progress and lower fuel costs at Duke Energy Florida;

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a $24 million decrease in operation, maintenance and other expense at Duke Energy Progress primarily driven by the deferral of 2018 severance costs due to the partial settlement agreement between Duke Energy Carolinas and the Public Staff of the NCUC related to the 2019 North Carolina retail rate case, reduced outage costs and energy efficiency program costs, partially offset by storm cost amortizations at Duke Energy Florida;

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•	a $21 million decrease in depreciation and amortization expense primarily driven by a decrease in coal ash amortization, partially offset by a higher depreciable base and impacts from North Carolina and the South Carolina rate cases at Duke Energy Progress; and

•	a $20 million decrease in property and other taxes driven by lower gross receipts taxes due to decreased fuel revenues and lower accrued property taxes at Duke Energy Florida.

•	a $26 million increase in impairment charges primarily due to the prior year's impairment reduction related to Citrus County CC at Duke Energy Florida.

•	a $230 million decrease in fuel cost recovery driven by lower fuel prices and volumes as well as less native load transfer sales in the current year;

•	a $73 million decrease in retail sales due to unfavorable weather in the current year;

•	a $58 million decrease in wholesale power revenues, net of fuel, primarily due to higher recovery of coal ash cost in the prior year and decreased volumes, partially offset by increased capacity rates; and

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

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•	a $15 million increase due to higher pricing from the South Carolina and North Carolina retail rate cases, net of a return of EDIT to customers.

•	a $234 million decrease in fuel used in electric generation and purchased power primarily due to lower demand and changes in generation mix; and

•	a $100 million decrease in operation, maintenance and other expense primarily driven by the deferral of 2018 severance costs due to the partial settlement agreement between Duke Energy Carolinas and the Public Staff of the NCUC related to the 2019 North Carolina retail rate case, reduced outage costs and energy efficiency program costs; and

•	a $22 million decrease in depreciation and amortization expense primarily driven by a decrease in coal ash amortization, partially offset by a higher depreciable base and impacts from North Carolina and the South Carolina rate cases.

•	a $255 million decrease in fuel revenues driven by lower sales volumes as well as an accelerated refund of fuel costs in response to the COVID-19 pandemic;

•	a $44 million decrease in rider revenues primarily due to full recovery of the Crystal River 3 uprate regulatory asset in 2019; and

•	a $10 million decrease in weather-normal retail sales volumes.

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•	a $107 million increase in storm revenues due to Hurricane Dorian collections;

•	a $67 million increase in retail pricing due to base rate adjustments related to annual increases from the 2017 Settlement Agreement and the Solar Base Rate Adjustment;

•	a $26 million increase in retail sales, net of fuel revenues, due to favorable weather in the current year;

•	an $11 million increase in wholesale power revenues, net of fuel, primarily due to increased demand; and

•	an $8 million increase in other revenues primarily due to increased transmission revenues and lighting equipment rentals, partially offset by lower late payment and service charge revenues due to a moratorium during the COVID-19 pandemic.

•	a $238 million decrease in fuel used in electric generation and purchased power primarily due to lower fuel costs; and

•	a $19 million decrease in property and other taxes driven by lower gross receipts taxes due to decreased fuel revenues and lower accrued property taxes.

•	a $76 million increase in operation, maintenance and other expense primarily due to storm cost amortizations; and

•	a $21 million increase in impairment charges primarily due to the prior year's impairment reduction related to Citrus County CC.

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•	a $46 million decrease in fuel related revenues primarily due to lower prices and decreased volumes;

•	a $13 million decrease in revenues due to unfavorable weather in the current year;

•	a $10 million decrease in other revenues due to lower OVEC sales into PJM;

•	a $7 million decrease in revenues primarily due to the suspension of the Manufactured Gas Plant rider and lower energy efficiency riders, partially offset by the Distribution Capital Investment rider; and

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

•	a $17 million increase in retail pricing primarily due to rate case impacts in Kentucky; and

•	an $11 million increase in PJM transmission revenues as a result of increased capital spend.

•	a $57 million decrease in fuel expense, primarily driven by lower retail prices, decreased volumes and lower OVEC costs; and

•	a $45 million decrease in operations, maintenance and other expense primarily due to Customer Connect and Network Integration Transmission Services deferrals, the timing of energy efficiency programs and outage costs, lower employee benefit expenses and lower vegetation and pole maintenance costs.

•	a $15 million increase in property and other taxes primarily due to higher property taxes primarily due to increased plant in service, partially offset by lower kilowatt taxes and franchise taxes; and

•	a $9 million increase in depreciation and amortization primarily driven by an increase in distribution plant, partially offset by lower amortization due to the suspension of the MGP rider in Ohio and environmental surcharge mechanism amortization of deferred coal ash pond ARO.

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•	a $157 million decrease in fuel revenues primarily due to lower fuel cost recovery driven by customer demand and fuel prices;

•	a $91 million decrease primarily due to IGCC rider revenues as a result of lower Edwardsport sales volumes and credit adjustment rider refunds related to IGCC Settlements;

•	a $20 million decrease in weather-normal retail sales volumes driven by lower nonresidential customer demand;

•	an $11 million decrease in retail sales due to unfavorable weather in the current year; and

•	an $11 million decrease in wholesale revenues primarily related to the true up of wholesale transmission revenues and lower rates in the current year.

•	a $75 million increase primarily due to higher pricing from the Indiana retail rate case, net of certain rider revenues moving to base.

•	a $143 million decrease in fuel used in electric generation and purchased power expense primarily due to lower coal and natural gas costs, lower amortization of deferred fuel costs and lower purchased power expense.

•	a $22 million increase in depreciation and amortization primarily due to a change in depreciation rates from the Indiana retail rate case and additional plant in service.

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•	a $130 million decrease due to lower natural gas costs passed through to customers, lower volumes, and decreased off-system sales natural gas costs;

•	a $31 million decrease due to return of EDIT to customers; and

•	a $7 million decrease due to NCUC approval related to tax reform accounting from fixed-rate contracts in the prior year.

•	a $65 million increase due to North Carolina base rate case increases; and

•	a $16 million increase due to North Carolina IMR increases.

•	a $130 million decrease in cost of natural gas due to lower natural gas prices, lower volumes, and decreased off-system sales natural gas costs.

•	a $7 million increase in impairment charges due to Piedmont ACP project materials write-off.

•	Duke Energy drew down the remaining $500 million of availability under the existing $1 billion Three-Year Revolving Credit Facility. That additional borrowing was subsequently repaid during the second quarter of 2020; and

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Duke Energy entered into and borrowed the full amount under a $1.5 billion, 364-day Term Loan Credit Agreement. The Term Loan Credit Agreement contained a provision for additional borrowing capacity of $500 million. Duke Energy exercised the provision and borrowed an additional $188 million, for a total borrowing of approximately $1.7 billion. In the third quarter of 2020, Duke Energy repaid $844 million of the 364-day Term Loan.

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•	a $572 million refund of AMT credit carryforwards;

•	a $119 million decrease in payments for asset retirement obligations;

•	a $77 million decrease in contributions to qualified pension plans; and

•	timing of payments of property taxes and higher Nuclear Electric Insurance Limited (NEIL) refunds in the current year.

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•	a $1,963 million decrease in proceeds from the issuance of preferred stock;

•	a $700 million decrease in proceeds from net issuances of long-term debt primarily due to the timing of issuances and redemptions of long-term debt; and

•	a $415 million decrease related to the sale of a noncontrolling interest in the Commercial Renewables segment.

•	a $1,279 million increase in net proceeds from issuances of notes payable and commercial paper including borrowings of $844 million under the 364-day Term Loan Credit Agreement; and

•	a $200 million increase related to contributions from noncontrolling interests for tax equity financing activity in the Commercial Renewables segment.

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•	Decreased demand for electricity and natural gas;

•	Delays in rate cases and other legal proceedings;

•	The health and availability of our critical personnel and their ability to perform business functions; and

•	Actions of state utility commissions or federal or state governments to allow customers to suspend or delay payment of bills related to the provision of electric or natural gas services.

•	An inability to procure satisfactory levels of fuels or other necessary equipment to continue production of electricity and delivery of natural gas;

•	An inability to obtain labor or equipment necessary for the construction of generation projects or pipeline expansion;

•	An inability to maintain information technology systems and protections from cyberattack;

•	An inability to obtain financing in volatile financial markets;

•	Additional federal regulation tied to stimulus and other aid packages; and

•	Impairment charges, which could include real estate as options for working remotely are evaluated and goodwill.

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