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◦	State, federal and foreign legislative and regulatory initiatives, including costs of compliance with existing and future environmental requirements, including those related to climate change, as well as rulings that affect cost and investment recovery or have an impact on rate structures or market prices;

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

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

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

◦	Costs and effects of legal and administrative proceedings, settlements, investigations and claims;

◦	Industrial, commercial and residential growth or decline in service territories or customer bases resulting from sustained downturns of the economy and the economic health of our service territories or variations in customer usage patterns, including energy efficiency efforts and use of alternative energy sources, such as self-generation and distributed generation technologies;

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

◦	Advancements in technology;

◦	Additional competition in electric and natural gas markets and continued industry consolidation;

◦	The influence of weather and other natural phenomena on operations, including the economic, operational and other effects of severe storms, hurricanes, droughts, earthquakes and tornadoes, including extreme weather associated with climate change;

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

◦	The ability to obtain the necessary permits and approvals and to complete necessary or desirable pipeline expansion or infrastructure projects in our natural gas business;

◦	Operational interruptions to our natural gas distribution and transmission activities;

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

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

◦	The inherent risks associated with the operation of nuclear facilities, including environmental, health, safety, regulatory and financial risks, including the financial stability of third-party service providers;

◦	The timing and extent of changes in commodity prices and interest rates and the ability to recover such costs through the regulatory process, where appropriate, and their impact on liquidity positions and the value of underlying assets;

◦	The results of financing efforts, including the ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings, interest rate fluctuations, compliance with debt covenants and conditions and general market and economic conditions;

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

◦	Declines in the market prices of equity and fixed-income securities and resultant cash funding requirements for defined benefit pension plans, other post-retirement benefit plans and nuclear decommissioning trust funds;

◦

Construction and development risks associated with the completion of the Duke Energy Registrants’ capital investment projects, including risks related to financing, obtaining and complying with terms of permits, meeting construction budgets and schedules and satisfying operating and environmental performance standards, as well as the ability to recover costs from customers in a timely manner, or at all;

◦	Changes in rules for regional transmission organizations, including changes in rate designs and new and evolving capacity markets, and risks related to obligations created by the default of other participants;

◦	The ability to control operation and maintenance costs;

◦	The level of creditworthiness of counterparties to transactions;

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

◦	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;

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

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

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

◦	The ability to implement our business strategy.

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(a)	Cumulative-effect adjustment due to implementation of a new accounting standard related to stock-based compensation and the associated income taxes.

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

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

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

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

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(a)	Represents a non-cash settlement through equity of an intercompany payable from Duke Energy Ohio to its parent.

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(a)	All segments include adjustments to the December 31, 2017 estimate of the income tax effects of the Tax Act. See Note 17 for additional information.

(b)	Other includes costs to achieve the Piedmont acquisition.

(c)	Commercial Renewables includes an impairment charge related to goodwill. See Note 7 for additional information.

(d)	Electric Utilities and Infrastructure includes an impairment charge related to the unrecovered Levy Nuclear Project costs at Duke Energy Florida.

(e)	Commercial Renewables includes impairment charges related to certain wind projects.

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(a)	All segments include adjustments to the December 31, 2017 estimate of the income tax effects of the Tax Act. See Note 17 for additional information.

(b)	Electric Utilities and Infrastructure includes regulatory and legislative impairment charges related to rate case orders, settlements or other actions of regulators or legislative bodies. See Note 3 for additional information.

(c)	Other includes costs to achieve the Piedmont acquisition.

(d)	Gas Utilities and Infrastructure includes an impairment of the investment in Constitution Pipeline Company, LLC (Constitution). See Note 3 for additional information.

(e)	Other includes the loss on the sale of the retired Beckjord Generating Station (Beckjord) described below and a valuation allowance recorded against the alternative minimum tax credits subject to sequestration. See Note 17 for additional information on the valuation allowance.

(f)	Commercial Renewables includes an impairment charge related to goodwill. See Note 7 for additional information.

(g)	Electric Utilities and Infrastructure includes an impairment charge related to the unrecovered Levy Nuclear Project costs at Duke Energy Florida.

(h)	Commercial Renewables includes impairment charges related to certain wind projects.

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

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

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

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

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

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

•	Inclusion in rates of costs related to the Lee Combined Cycle Facility, two new solar facilities, and AMI deployment as requested;

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

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

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

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•	Recovery of the remaining $234 million of deferred coal ash basin closure costs over a five-year period with a return at Duke Energy Progress' WACC, excluding $9.5 million of retail deferred coal ash basin costs related to ash hauling at Duke Energy Progress' Asheville Plant;

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

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

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

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

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

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

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

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

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

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

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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 interest rate.

(c)	Callable after September 2023 at par. 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 money-pool borrowing arrangement and for general corporate purposes.

(f)	Debt issued to repay short-term debt 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, 2018, 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 and nuclear decommissioning of Crystal River Unit 3.

(d)	Primarily relates to increases in groundwater monitoring estimates for closure of ash impoundments, partially offset by modifications to the timing of expected cash flows and a reduction for nuclear decommissioning at Crystal River Unit 3 compared to original estimates.

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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 Joint Dispatch Agreement (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. These intercompany revenues and expenses are eliminated in consolidation.

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(a)	Duke Energy includes amounts related to consolidated VIEs of $411 million in cash flow hedges and $200 million in undesignated contracts as of September 30, 2018, and $660 million in cash flow hedges as of December 31, 2017.

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(a)	Where regulatory accounting is applied, realized and unrealized gains and losses are deferred as regulatory assets or liabilities, and there is no impact to net income or other comprehensive income until the gain or loss is amortized or collected.

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(a)	Where regulatory accounting is applied, realized and unrealized gains and losses are deferred as regulatory assets or liabilities, and there is no impact to net income or other comprehensive income until the gain or loss is amortized or collected.

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(a)	Where regulatory accounting is applied, realized and unrealized gains and losses are deferred as regulatory assets or liabilities, and there is no impact to net income or other comprehensive income until the gain or loss is amortized or collected.

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(a)	Where regulatory accounting is applied, realized and unrealized gains and losses are deferred as regulatory assets or liabilities, and there is no impact to net income or other comprehensive income until the gain or loss is amortized or collected.

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(a)	Where regulatory accounting is applied, realized and unrealized gains and losses are deferred as regulatory assets or liabilities, and there is no impact to net income or other comprehensive income until the gain or loss is amortized or collected.

(b)	During the nine months ended September 30, 2018, Duke Energy Florida continued to receive reimbursements from the NDTF for costs related to ongoing decommissioning activity of the Crystal River Unit 3 nuclear plant.

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(a)	Realized and unrealized gains and losses where regulatory accounting is applied are deferred as regulatory assets or liabilities, and there is no impact to net income or other comprehensive income until the gain or loss is amortized or collected.

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(a)	Book value of long-term debt includes $1.6 billion as of September 30, 2018, and $1.7 billion as of December 31, 2017, of unamortized debt discount and premium, net in purchase accounting adjustments related to the mergers with Progress Energy and Piedmont that are excluded from fair value of long-term debt.

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(a)	See Pipeline Investments table below for further details regarding Investments in equity method unconsolidated affiliates.

(a)

At December 31, 2017, Sabal Trail was considered a VIE due to having insufficient equity to finance their own activities without subordinated financial support. However, Sabal Trail is now a fully operational, well capitalized entity. As a result, Sabal Trail has sufficient equity to finance its own activities, and therefore, is no longer considered a VIE. Duke Energy's investment in Sabal Trail was $112 million at September 30, 2018.

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(b)	During the nine months ended September 30, 2018, Duke Energy recorded an OTTI of $55 million related to Constitution within Equity in earnings of unconsolidated affiliates on Duke Energy's Condensed Consolidated Statements of Income. See Note 3 for additional information.

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

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

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•	Costs to Achieve Piedmont Merger represents charges that result from the Piedmont acquisition.

•	Regulatory and Legislative Impacts represents charges related to rate case orders, settlements or other actions of regulators or legislative bodies.

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

•	Impairment Charges represents an other-than-temporary impairment (OTTI) of an investment in Constitution Pipeline Company, LLC (Constitution) and Commercial Renewables impairments.

•	Impacts of the Tax Act represents an alternative minimum tax (AMT) valuation allowance recognized and a true up of prior year tax estimates related to the Tax Act.

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(a)	Net of $2 million Noncontrolling Interests in 2018 and $28 million tax benefit in 2017.

(b)	Net of $3 million tax benefit in 2018 and $9 million tax benefit in 2017.

(c)	Represents a true up of prior year tax estimates related to the Tax Act.

(d)	Net of $51 million tax benefit in 2017.

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(a)	Net of $63 million tax benefit.

(b)	Net of $13 million tax benefit and $2 million Noncontrolling Interest in 2018 and $28 million tax benefit in 2017.

(c)	Net of $25 million tax benefit.

(d)	Represents a recognition of AMT valuation allowance and true up of prior year tax estimates related to the Tax Act.

(e)	Net of $12 million tax benefit in 2018 and $26 million tax benefit in 2017.

(f)	Net of $51 million tax benefit in 2017.

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•	a $90 million increase in fuel related revenues due to higher sales volumes and increases in fuel rates billed to customers;

•	a $54 million increase in weather-normal retail sales volumes;

•	a $59 million increase in retail pricing primarily due to the Duke Energy Progress and Duke Energy Carolinas North Carolina rate cases;

•	a $38 million increase in retail sales, net of fuel revenues, due to favorable weather in the current year; and

•	a $23 million increase in Joint Asset Agency Rider (JAAR) revenues at Duke Energy Progress in conjunction with implementation of new base rates.

•	a $143 million decrease in retail revenues associated with the lower statutory federal corporate tax rate under the Tax Act.

•	a $120 million increase in depreciation and amortization expense primarily due to higher amortization of deferred coal ash costs, additional plant in service and new depreciation rates associated with the Duke Energy Progress and Duke Energy Carolinas North Carolina rate cases;

•	a $99 million increase in operation, maintenance and other expense primarily due to higher storm costs due to Hurricane Florence and higher operational costs that are recoverable in rates, partially offset by a FERC approved settlement refund of certain transmission costs previously billed by PJM; and

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•	a $63 million increase in fuel used in electric generation and purchased power primarily due to higher sales and higher deferred fuel expenses.

•	a $101 million decrease in impairment charges primarily due to the write-off of remaining unrecovered Levy Nuclear Project costs in 2017.

•	a $398 million increase in fuel related revenues due to higher sales volumes, changes in generation mix and increases in fuel rates billed to customers;

•	a $288 million increase in retail sales, net of fuel revenues, due to favorable weather in the current year;

•	a $125 million increase in retail pricing primarily due to the Duke Energy Progress and Duke Energy Carolinas North Carolina rate cases and Duke Energy Florida base rate adjustments for the Osprey acquisition and the completion of the Hines Energy Complex Chiller Uprate Project;

•	an $80 million increase in weather-normal retail sales volumes; and

•	a $52 million increase in JAAR revenues at Duke Energy Progress in conjunction with implementation of new base rates.

•	a $401 million decrease in retail revenues associated with the lower statutory federal corporate tax rate under the Tax Act.

•	a $342 million increase in depreciation and amortization expense primarily due to higher amortization of deferred coal ash costs, additional plant in service and new depreciation rates per the Duke Energy Progress and Duke Energy Carolinas North Carolina rate cases;

•	a $327 million increase in fuel used in electric generation and purchased power, due to higher sales and higher deferred fuel expenses;

•	a $216 million increase in operation, maintenance and other expense primarily due to impacts associated with the Duke Energy Progress North Carolina rate case, the impacts of Hurricane Florence and higher storm cost amortization at Duke Energy Florida, partially offset by a FERC approved settlement refund of certain transmission costs previously billed by PJM; and

•	a $112 million increase in impairment charges primarily due to the impacts associated with the Duke Energy Carolinas and Duke Energy Progress North Carolina rate cases, offset by the write-off of remaining unrecovered Levy Nuclear project costs at Duke Energy Florida in the prior year.

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•	an $11 million decrease due to revenues subject to refund to customers associated with the lower statutory federal corporate tax rate under the Tax Act; and

•	a $10 million decrease primarily due to lower natural gas costs passed through to customers from lower retail volumes sold, partially offset by higher natural gas prices.

•	a $6 million increase primarily due to residential and commercial customer revenue, net of natural gas costs passed through to customers, due to customer growth and Integrity Management Rider (IMR) rate adjustments at Piedmont.

•	a $10 million decrease in cost of natural gas primarily due to lower retail volumes sold, partially offset by slightly higher natural gas prices.

•	a $7 million increase in operations, maintenance and other primarily due to increased shared services and customer operations expense.

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•	a $58 million increase primarily due to higher natural gas costs passed through to customers due to higher retail volumes sold and higher natural gas prices;

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

•	a $10 million increase primarily due to favorable weather in the current year and higher volumes sold in the Midwest.

•	a $49 million decrease due to revenues subject to refund to customers associated with the lower statutory federal corporate tax rate under the Tax Act.

•	a $58 million increase in cost of natural gas primarily due to higher retail volumes sold and higher natural gas prices;

•	a $19 million increase in operations, maintenance and other primarily due to increased shared services and gas operations expense; and

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

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•	a $197 million decrease in retail sales due to revenues subject to refund to customers associated with the lower statutory federal corporate tax rate under the Tax Act;

•	a $48 million decrease in rider revenues primarily related to energy efficiency programs; and

•	a $25 million decrease in wholesale power revenues, net of sharing and fuel, primarily due to wholesale customer refunds in the current year related to a FERC order on a complaint filed by Piedmont Municipal Power Agency (PMPA), partially offset by higher revenues related to recovery of coal ash costs.

•	a $141 million increase in retail sales, net of fuel revenues, due to favorable weather in the current year;

•	a $39 million increase in weather-normal retail sales volumes; and

•	a $29 million increase in retail pricing due to the impacts of the North Carolina rate case.

•	a $191 million increase in impairment charges, primarily due to the impacts of the North Carolina rate order and charges related to coal ash costs in South Carolina; and

•	a $62 million increase in depreciation and amortization primarily due to additional plant in service and higher amortization of deferred coal ash costs, partially offset by lower amortization of certain regulatory assets.

•	a $24 million decrease in fuel used in electric generation and purchased power primarily due to decreased coal ash beneficial reuse costs, partially offset by higher sales volumes.

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•	a $467 million increase in fuel related revenues due to higher sales volumes, increases in fuel and capacity rates billed to customers and increased demand at Duke Energy Florida;

•	a $103 million increase in retail sales, net of fuel revenues, due to favorable weather in the current year and impacts of lost revenue resulting from Hurricane Irma in the prior year at Duke Energy Florida;

•	an $89 million increase in JAAR revenues, primarily due to the implementation of new base rates and weather normalized volumes at Duke Energy Progress;

•	a $79 million increase in retail pricing due to the impacts of the Duke Energy Progress North Carolina and South Carolina rate cases; and

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•	a $73 million increase in wholesale power revenues, net of fuel, primarily due to the recovery of coal ash costs and higher peak demand at Duke Energy Progress.

•	a $98 million decrease in retail sales due to revenues subject to refund to customers associated with the lower statutory federal corporate tax rate under the Tax Act at Duke Energy Progress; and

•	a $35 million decrease in rider revenues in conjunction with implementation of new base rate and impacts of Hurricane Florence at Duke Energy Progress.

•	a $431 million increase in fuel used in electric generation and purchased power primarily due to higher sales, higher deferred fuel and capacity expenses, and increased purchased power;

•	a $225 million increase in depreciation and amortization primarily due to higher amortization of deferred coal ash costs and new depreciation rates associated with the North Carolina rate case at Duke Energy Progress, and accelerated depreciation of Crystal River Units 4 and 5 and additional plant in service at Duke Energy Florida;

•	a $216 million increase in operation, maintenance and other primarily due to impacts associated with the North Carolina rate case at Duke Energy Progress and storm cost amortization at Duke Energy Florida; and

•	a $13 million increase in property and other taxes primarily due to higher revenue related taxes.

•	a $103 million decrease in impairment charges primarily due to the write-off of remaining unrecovered Levy Nuclear Project costs in the prior year at Duke Energy Florida.

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•	a $268 million increase in fuel related revenues due to higher retail sales and changes in generation mix;

•	a $79 million increase in pricing due to the impacts of the North Carolina and South Carolina rate cases;

•	a $73 million increase in wholesale power revenues, net of fuel, primarily due to recovery of coal ash costs and higher peak demand;

•	a $72 million increase in retail sales due to favorable weather conditions;

•	a $52 million increase in JAAR revenues in conjunction with implementation of new base rates; and

•	a $37 million increase in weather normalized volumes.

•	a $98 million decrease in retail sales due to revenues subject to refund to customers associated with the lower statutory federal corporate tax rate under the Tax Act;

•	a $25 million decrease in certain rider revenues in conjunction with implementation of new base rates; and

•	a $10 million decrease in revenues due to the impacts of Hurricane Florence.

•	a $238 million increase in fuel used in electric generation and purchased power primarily due higher retail sales and changes in generation mix;

•	a $187 million increase in depreciation and amortization primarily due to higher amortization of deferred coal ash costs and new depreciation rates per the North Carolina rate case;

•	a $118 million increase in operation, maintenance and other expense primarily due to higher storm contingency costs, impacts associated with the North Carolina rate case and higher operational costs that are recoverable in rates; and

•	a $33 million increase in impairment charges associated with the North Carolina rate case.

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•	a $199 million increase in fuel and capacity revenues primarily due to an increase in fuel and capacity rates billed to retail customers, as well as increased demand; and

•	a $31 million increase in retail sales, net of fuel revenues, due to favorable weather in the current year and impacts of lost revenue resulting from Hurricane Irma in the prior year.

•	a $193 million increase in fuel used in electric generation and purchased power primarily due to higher deferred fuel and capacity expenses, increased purchased power and increased demand;

•	a $96 million increase in operations, maintenance and other expense primarily due to storm cost amortizations, partially offset by lower storm restoration costs in the current year;

•	a $37 million increase in depreciation and amortization primarily due to accelerated depreciation of Crystal River Units 4 and 5 and additional plant in service, partially offset by decreased ARO depreciation due to the updated Crystal River Unit 3 nuclear decommissioning cost study; and

•	a $19 million increase in property and other taxes primarily due to higher revenue related taxes.

•	a $136 million decrease in impairment charges primarily due to the write-off of remaining unrecovered Levy Nuclear Project costs in the prior year.

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•	a $39 million increase in electric and natural gas retail sales, net of fuel revenues, due to favorable weather in the current year;

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

•	a $5 million increase in other revenues related to OVEC;

•	a $5 million increase in fuel revenues due to higher natural gas costs; and

•	a $4 million increase in rider revenue primarily due to increased rates.

•	a $38 million decrease in regulated revenues due to revenues subject to refund to customers associated with the lower statutory federal corporate tax rate under the Tax Act; and

•	a $51 million decrease in operations, maintenance and other expense primarily due to the FERC approved settlement refund of certain transmission costs previously billed by PJM.

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•	an $83 million decrease due to revenues subject to refund to customers associated with the lower statutory federal corporate tax rate under the Tax Act; and

•	a $22 million decrease in wholesale power revenues, net of fuel, primarily due to contracts that expired in the prior year.

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•	a $53 million increase in rate rider revenues primarily related to the Edwardsport Integrated Gasification Combined Cycle (IGCC) plant and the Transmission, Distribution and Storage System Improvement Charge rider;

•	a $24 million increase in electric sales to retail customers due to favorable weather in the current year;

•	a $7 million increase in weather-normal sales volumes to retail customers in the current year; and

•	a $6 million increase in fuel and other revenues primarily due to higher Midcontinent Independent System Operator rider revenue, partially offset by a decrease in retail and wholesale fuel revenues.

•	a $50 million increase in depreciation and amortization primarily due to additional plant in service and the deferral of certain asset retirement obligations in the prior year;

•	a $30 million increase in operation, maintenance and other expense primarily due to higher amortizations of previously deferred expenses, higher transmission and customer related costs; and

•	a $30 million increase in impairment charges primarily due to the reduction of a regulatory asset pertaining to the Edwardsport IGCC settlement agreement.

•	a $14 million decrease in fuel used in electric generation and purchased power primarily due to the net benefit to expense of lower purchased power and an increase in internal generation, and lower fuel prices.

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•	a $54 million increase primarily due to higher natural gas costs passed through to customers due to higher retail volumes sold and higher natural gas prices; and

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

•	a $34 million decrease due to revenues subject to refund to customers associated with the lower statutory federal corporate tax rate under the Tax Act.

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•	a $54 million increase in cost of natural gas primarily due to higher retail volumes sold and higher natural gas prices;

•	a $26 million increase in operation, maintenance and other primarily due to increased shared services, costs to achieve merger expenses and natural gas operations; and

•	a $9 million increase in depreciation and amortization due to additional plant in service.

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

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•	a $1,098 million increase in net income after adjustment for non-cash items primarily due to favorable weather and increased pricing and volumes in the current period.

•	a $133 million increase in contributions to qualified pension plans; and

•	a $105 million payment for disposal of Beckjord.

•	an $834 million increase in proceeds from the issuance of common stock; and

•	a $1,293 million increase in net proceeds from issuances of notes payable and commercial paper primarily due to increased capital expenditures and the timing of debt and common stock issuances.

•	a $1,843 million decrease in proceeds from net issuances of long-term debt primarily due to prior year financings of $820 million in the Commercial Renewables segment and the timing of issuances and redemptions of long-term debt.

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