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•	resolution of pending and future rate cases, formula rate proceedings and related negotiations, including various performance-based rate discussions, Entergy’s utility supply plan, and recovery of fuel and purchased power costs;

•	long-term risks and uncertainties associated with the termination of the System Agreement in 2016, including the potential absence of federal authority to resolve certain issues among the Utility operating companies and their retail regulators;

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regulatory and operating challenges and uncertainties and economic risks associated with the Utility operating companies’ participation in MISO, including the benefits of continued MISO participation, the effect of current or projected MISO market rules and market and system conditions in the MISO markets, the allocation of MISO system transmission upgrade costs, and the effect of planning decisions that MISO makes with respect to future transmission investments by the Utility operating companies;

•	changes in utility regulation, including with respect to retail and wholesale competition, the ability to recover net utility assets and other potential stranded costs, and the application of more stringent transmission reliability requirements or market power criteria by the FERC or the U.S. Department of Justice;

•	changes in the regulation or regulatory oversight of Entergy’s nuclear generating facilities and nuclear materials and fuel, including with respect to the planned, potential, or actual shutdown of nuclear generating facilities owned or operated by Entergy Wholesale Commodities, and the effects of new or existing safety or environmental concerns regarding nuclear power plants and nuclear fuel;

•	resolution of pending or future applications, and related regulatory proceedings and litigation, for license modifications or other authorizations required of nuclear generating facilities and the effect of public and political opposition on these applications, regulatory proceedings, and litigation;

•	the performance of and deliverability of power from Entergy’s generation resources, including the capacity factors at Entergy’s nuclear generating facilities;

•	increases in costs and capital expenditures that could result from changing regulatory requirements, emerging operating and industry issues, and the commitment of substantial human and capital resources required for the safe and reliable operation and maintenance of Entergy’s nuclear generating facilities;

•	Entergy’s ability to develop and execute on a point of view regarding future prices of electricity, natural gas, and other energy-related commodities;

•	prices for power generated by Entergy’s merchant generating facilities and the ability to hedge, meet credit support requirements for hedges, sell power forward or otherwise reduce the market price risk associated with those facilities, including the Entergy Wholesale Commodities nuclear plants, especially in light of the planned shutdown or sale of each of these nuclear plants;

•	the prices and availability of fuel and power Entergy must purchase for its Utility customers, and Entergy’s ability to meet credit support requirements for fuel and power supply contracts;

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•	volatility and changes in markets for electricity, natural gas, uranium, emissions allowances, and other energy-related commodities, and the effect of those changes on Entergy and its customers;

•	changes in law resulting from federal or state energy legislation or legislation subjecting energy derivatives used in hedging and risk management transactions to governmental regulation;

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changes in environmental laws and regulations, agency positions or associated litigation, including requirements for reduced emissions of sulfur dioxide, nitrogen oxide, greenhouse gases, mercury, particulate matter and other regulated air emissions, heat and other regulated discharges to water, requirements for waste management and disposal and for the remediation of contaminated sites, wetlands protection and permitting, and changes in costs of compliance with environmental laws and regulations;

•	changes in laws and regulations, agency positions, or associated litigation related to protected species and associated critical habitat designations;

•	the effects of changes in federal, state, or local laws and regulations, and other governmental actions or policies, including changes in monetary, fiscal, tax, environmental, trade/tariff, or energy policies;

•	the effects of full or partial shutdowns of the federal government or delays in obtaining government or regulatory actions or decisions;

•	uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel and nuclear waste storage and disposal and the level of spent fuel and nuclear waste disposal fees charged by the U.S. government or other providers related to such sites;

•	variations in weather and the occurrence of hurricanes and other storms and disasters, including uncertainties associated with efforts to remediate the effects of hurricanes, ice storms, or other weather events and the recovery of costs associated with restoration, including accessing funded storm reserves, federal and local cost recovery mechanisms, securitization, and insurance;

•	effects of climate change, including the potential for increases in extreme weather events and sea levels or coastal land and wetland loss;

•	changes in the quality and availability of water supplies and the related regulation of water use and diversion;

•	Entergy’s ability to manage its capital projects and operation and maintenance costs;

•	Entergy’s ability to purchase and sell assets at attractive prices and on other attractive terms;

•	the economic climate, and particularly economic conditions in Entergy’s Utility service area and the northern United States and events and circumstances that could influence economic conditions in those areas, including power prices, and the risk that anticipated load growth may not materialize;

•	federal income tax reform, including the enactment of the Tax Cuts and Jobs Act, and its intended and unintended consequences on financial results and future cash flows;

•	the effects of Entergy’s strategies to reduce tax payments, especially in light of federal income tax reform;

•	changes in the financial markets and regulatory requirements for the issuance of securities, particularly as they affect access to capital and Entergy’s ability to refinance existing securities, execute share repurchase programs, and fund investments and acquisitions;

•	actions of rating agencies, including changes in the ratings of debt and preferred stock, changes in general corporate ratings, and changes in the rating agencies’ ratings criteria;

•	changes in inflation and interest rates;

•	the effect of litigation and government investigations or proceedings;

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changes in technology, including (i) Entergy’s ability to implement new or emerging technologies, (ii) the impact of changes relating to new, developing, or alternative sources of generation such as distributed energy and energy storage, renewable energy, energy efficiency, demand side management and other measures that reduce load, and (iii) competition from other companies offering products and services to Entergy’s customers based on new or emerging technologies or alternative sources of generation;

•	the effects, including increased security costs, of threatened or actual terrorism, cyber-attacks or data security breaches, natural or man-made electromagnetic pulses that affect transmission or generation infrastructure, accidents, and war or a catastrophic event such as a nuclear accident or a natural gas pipeline explosion;

•	Entergy’s ability to attract and retain talented management, directors, and employees with specialized skills;

•	changes in accounting standards and corporate governance;

•	declines in the market prices of marketable securities and resulting funding requirements and the effects on benefits costs for Entergy’s defined benefit pension and other postretirement benefit plans;

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•	future wage and employee benefit costs, including changes in discount rates and returns on benefit plan assets;

•	changes in decommissioning trust fund values or earnings or in the timing of, requirements for, or cost to decommission Entergy’s nuclear plant sites and the implementation of decommissioning of such sites following shutdown;

•	the decision to cease merchant power generation at all Entergy Wholesale Commodities nuclear power plants by mid-2022, including the implementation of the planned shutdowns of Pilgrim, Indian Point 2, Indian Point 3, and Palisades;

•	the effectiveness of Entergy’s risk management policies and procedures and the ability and willingness of its counterparties to satisfy their financial and performance commitments;

•	factors that could lead to impairment of long-lived assets; and

•	the ability to successfully complete strategic transactions Entergy may undertake, including mergers, acquisitions, divestitures, or restructurings, regulatory or other limitations imposed as a result of any such strategic transaction, and the success of the business following any such strategic transaction.

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•	The Utility business segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operation of a small natural gas distribution business.

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The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” below for discussion of the operation and planned shutdown or sale of each of the Entergy Wholesale Commodities nuclear power plants.

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(a)	Parent & Other includes eliminations, which are primarily intersegment activity.

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•	an increase in formula rate plan rates effective with the first billing cycle of January 2018 at Entergy Arkansas, as approved by the APSC;

•	an increase in energy efficiency revenues primarily due to an increase in the Entergy Arkansas energy efficiency rider and a new Entergy Louisiana energy efficiency rider effective January 2018;

•	a base rate increase effective October 2018 at Entergy Texas, as approved by the PUCT;

•	an increase in formula rate plan revenues at Entergy Louisiana, implemented with the first billing cycle of September 2018; and

•	higher storm damage rider revenues at Entergy Mississippi.

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a decrease resulting from the reimbursement agreement with Exelon pursuant to which Exelon reimbursed Entergy in the first quarter 2017 for specified out-of-pocket costs associated with preparing for the refueling and operation of FitzPatrick that otherwise would have been avoided had Entergy shut down FitzPatrick in January 2017. Revenues received from Exelon under the reimbursement agreement were offset by other operation and maintenance expenses and taxes other than income taxes and had no effect on net income. See Note 14 to the financial statements for discussion of the sale of FitzPatrick and the reimbursement agreement with Exelon;

•	lower realized wholesale energy prices, partially offset by higher capacity prices; and

•	lower volume in the Entergy Wholesale Commodities nuclear fleet primarily due to more non-refueling outage days in 2018 compared to 2017.

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•	an increase of $33 million in energy efficiency expenses due to the timing of recovery from customers;

•	an increase of $23 million in fossil-fueled generation expenses primarily due to an overall higher scope of work performed in 2018 as compared to the prior year and higher long-term service agreement costs;

•	an increase of $15 million in transmission expenses primarily due to higher labor and contract costs to support industrial customers;

•	an increase of $14 million in information technology costs primarily due to higher software maintenance costs and higher labor costs, including contract labor;

•	an increase of $14 million in loss provisions, including an increase in asbestos loss provisions;

•	an increase of $6 million in storm damage provisions, primarily at Entergy Mississippi. See Note 2 to the financial statements for discussion of storm cost recovery;

•	a $6 million write-off of capitalized skylining tree hazard costs as a result of the settlement of the Entergy Texas rate case proceeding. See Note 2 to the financial statements for discussion of the rate case proceeding; and

•	a $6 million loss in 2018 on the sale of fuel oil inventory per an agreement approved by the MPSC in June 2018 resulting from the stipulation related to the effects of the Tax Cuts and Jobs Act. There is no effect on net income as the loss on the sale of fuel oil inventory is offset by a reduction in income tax expense. See Note 2 to the financial statements for discussion of the agreement.

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(a)	Parent & Other includes eliminations, which are primarily intersegment activity.

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•	the implementation of formula rate plan rates effective with the first billing cycle of January 2017 at Entergy Arkansas and an increase in base rates effective February 24, 2016, each as approved by the APSC. A significant portion of the base rate increase was related to the purchase of Power Block 2 of the Union Power Station in March 2016;

•	a provision recorded in 2016 related to the settlement of the Waterford 3 replacement steam generator prudence review proceeding;

•	the implementation of the transmission cost recovery factor rider at Entergy Texas, effective September 2016, and an increase in the transmission cost recovery factor rider rate, effective March 2017, as approved by the PUCT; and

•	an increase in rates at Entergy Mississippi, as approved by the MPSC, effective with the first billing cycle of July 2016.

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(a)	The reduction in owned capacity is due to Entergy’s sale of the 838 MW FitzPatrick plant to Exelon in March 2017. See Note 14 to the financial statements for discussion of the sale of FitzPatrick.

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an increase of $46 million in nuclear generation expenses primarily due to higher nuclear labor costs, including contract labor, to position the nuclear fleet to meet its operational goals, including additional training and initiatives to support management’s operational goals at Grand Gulf, partially offset by a decrease in regulatory compliance costs. The decrease in regulatory compliance costs is primarily related to additional NRC inspection activities in 2016 as a result of the NRC’s March 2015 decision to move ANO into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. See Note 8 to the financial statements for a discussion of the ANO stator incident and subsequent NRC reviews;

•	an increase of $24 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to the prior year;

•	an increase of $20 million in transmission and distribution expenses due to higher vegetation maintenance costs;

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the effects of recording in 2016 final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded included the reimbursement of approximately $19 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and

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the deferral in the first quarter 2016 of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC in February 2016 as part of the Entergy Arkansas 2015 rate case settlement. These costs are being amortized over a ten-year period beginning March 2016. See Note 2 to the financial statements for further discussion of the rate case settlement.

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FitzPatrick’s nuclear refueling outage expenses and expenditures for capital assets being classified as other operation and maintenance expenses as a result of the sale and reimbursement agreements Entergy entered into with Exelon. These costs would have not been incurred absent the sale agreement with Exelon because Entergy planned to shut the plant down in January 2017. The expenses are offset by revenue realized pursuant to the reimbursement agreement and had no effect on net income. See Note 14 to the financial statements for discussion of the sale and reimbursement agreements;

•	the effect of recording in 2016 final court decisions in litigation against the DOE for the reimbursement of spent nuclear fuel storage costs, which reduced other operation and maintenance expenses in 2016 by $60 million. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and

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an increase of $37 million in severance and retention costs in 2017 as compared to the prior year due to management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” below for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet.

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(a)	Calculation excludes the Arkansas, Louisiana, New Orleans, and Texas securitization bonds, which are non-recourse to Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas, respectively.

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(a)	The interest rate is the estimated interest rate as of December 31, 2018 that would have been applied to outstanding borrowings under the facility.

(b)	Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable at Entergy Arkansas’s option.

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(c)	The credit facility includes fronting commitments for the issuance of letters of credit against a portion of the borrowing capacity of the facility as follows: $5 million for Entergy Arkansas; $15 million for Entergy Louisiana; $10 million for Entergy New Orleans; and $30 million for Entergy Texas.

(d)	Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option.

(a)	As of December 31, 2018, letters of credit posted with MISO covered financial transmission right exposure of $0.2 million for Entergy Mississippi and $4.1 million for Entergy Texas. See Note 15 to the financial statements for discussion of financial transmission rights.

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(a)	Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.

(b)	Lease obligations are discussed in Note 10 to the financial statements.

(c)	Does not include power purchase agreements that are accounted for as leases that are included in purchase obligations.

(d)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. Almost all of the total are fuel and purchased power obligations.

•	maintain System Energy’s equity capital at a minimum of 35% of its total capitalization (excluding short-term debt);

•	permit the continued commercial operation of Grand Gulf;

•	pay in full all System Energy indebtedness for borrowed money when due; and

•	enable System Energy to make payments on specific System Energy debt, under supplements to the agreement assigning System Energy’s rights in the agreement as security for the specific debt.

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•	Investments, including the St. Charles Power Station, Lake Charles Power Station, Washington Parish Energy Center, Choctaw Generating Station, Sunflower Solar Facility, New Orleans Power Station, and Montgomery County Power Station, each discussed below, and potential construction of additional generation.

•	Entergy Wholesale Commodities investments such as component replacements, software and security, and dry cask storage.

•	Investments in Entergy’s nuclear fleet.

•	Transmission spending to enhance reliability, reduce congestion, and enable economic growth.

•	Distribution spending to enhance reliability and improve service to customers, including investment to support advanced metering.

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•	internally generated funds;

•	cash on hand ($481 million as of December 31, 2018);

•	securities issuances;

•	bank financing under new or existing facilities or commercial paper; and

•	sales of assets.

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•	the return of unprotected excess accumulated deferred income taxes to Utility customers. See Note 2 to the financial statements for a discussion of the regulatory activity regarding the Tax Cuts and Jobs Act;

•	lower Entergy Wholesale Commodities net revenue in 2018 as compared to the same period in 2017 (except for revenues resulting from the FitzPatrick reimbursement agreement with Exelon). See Note 14 to the financial statements for discussion of the reimbursement agreement;

•	a decrease due to the timing of recovery of fuel and purchased power costs in 2018 as compared to the prior year. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;

•	an increase of $56 million in interest paid in 2018 as compared to the prior year resulting from an increase in interest expense;

•	income tax payments of $20 million in 2018 compared to income tax refunds of $13 million in 2017. Entergy made income tax payments in 2018 for estimated federal income taxes. Entergy received income tax refunds in 2017 resulting from the carryback of net operating losses; and

•	proceeds of $2 million received in 2018 compared to proceeds of $23 million received in 2017 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

•	the effect of favorable weather on billed Utility sales in 2018;

•	the timing of collection of receivables from Utility customers;

•	a refund to customers in January 2017 of approximately $71 million as a result of the settlement approved by the LPSC related to the Waterford 3 replacement steam generator project. See Note 2 to the financial statements for discussion of the settlement and refund;

•	a decrease of $58 million in spending on nuclear refueling outages in 2018 as compared to the prior year; and

•	a decrease of $57 million in severance and retention payments in 2018 as compared to the prior year. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” above for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet.

•	lower Entergy Wholesale Commodities net revenue (except for revenues resulting from the FitzPatrick reimbursement agreement with Exelon) in 2017 as compared to prior year, as discussed above. See Note 14 to the financial statements for discussion of the reimbursement agreement;

•	an increase of $141 million in spending on nuclear refueling outages in 2017 as compared to the prior year;

•	an increase of $94 million in severance and retention payments in 2017 as compared to the prior year. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” above for a discussion of management’s strategy to reduce the size of the Entergy Wholesale Commodities’ merchant fleet;

•	a refund to customers in January 2017 of approximately $71 million as a result of the settlement approved by the LPSC related to the Waterford 3 replacement steam generator project. See Note 2 to the financial statements for discussion of the settlement and refund;

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•	proceeds of $23 million received in 2017 compared to proceeds of $102 million received in 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and

•	an increase of $20 million in pension contributions in 2017. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates” below and Note 11 to the financial statements for discussion of qualified pension and other postretirement benefits funding.

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income tax refunds of $13 million in 2017 compared to income tax payments of $95 million in 2016. Entergy received income tax refunds in 2017 resulting from the carryback of net operating losses. Entergy made income tax payments in 2016 related to the effect of the 2006-2007 IRS audit and for jurisdictions that do not have net operating loss carryovers or jurisdictions in which the utilization of net operating loss carryovers are limited;

•	a decrease of $68 million in interest paid in 2017 as compared to the prior year primarily due to an interest payment of $60 million made in March 2016 related to the purchase of a beneficial interest in the Waterford 3 leased assets. See Note 10 to the financial statements for a discussion of Entergy Louisiana’s purchase of a beneficial interest in the Waterford 3 leased assets; and

•	an increase due to the timing of recovery of fuel and purchased power costs in 2017 as compared to the prior year. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery.

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an increase of $334 million in construction expenditures, primarily in the Utility business. The increase in construction expenditures in the Utility business is primarily due to an increase of $205 million in fossil-fueled generation construction expenditures primarily due to higher spending in 2018 on self-build projects in the Utility business and an increase of $88 million in nuclear construction expenditures primarily due to a higher scope of work performed during the Grand Gulf outage in 2018;

•	proceeds of $100 million from the sale in March 2017 of the FitzPatrick plant to Exelon. See Note 14 to the financial statements for a discussion of the sale of FitzPatrick; and

•	collateral posted to provide credit support to secure its obligations under agreements to sell power produced by Entergy Wholesale Commodities’ power plants.

•	changes in the decommissioning trust funds, including portfolio rebalancing of certain decommissioning trust funds in 2018;

•	a decrease of $75 million in nuclear fuel purchases due to variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and

•	an increase of $34 million in proceeds received from the DOE in 2018 as compared to the prior year resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

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an increase of $827 million in construction expenditures, primarily in the Utility business. The increase in construction expenditures in the Utility business is primarily due to an increase of $452 million in fossil-fueled generation construction expenditures primarily due to higher spending in 2017 on the St. Charles Power Station project and the Lake Charles Power Station project and a higher scope of work performed on various other fossil projects in 2017 as compared to 2016; an increase of $133 million in distribution construction expenditures primarily due to a higher scope of non-storm related work performed in 2017 as compared to 2016 and higher storm restoration spending in 2017; an increase of $102 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2017 as compared to 2016; an increase of $101 million in transmission construction expenditures primarily due to a higher scope of work performed on transmission projects in 2017 as compared to 2016; and an increase of $51 million due to increased spending on advanced metering infrastructure in 2017;

•	a decrease of $144 million in proceeds received from the DOE in 2017 as compared to the prior year resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and

•	a decrease of $63 million in nuclear fuel purchases due to variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle.

•	long-term debt activity providing approximately $1,070 million of cash in 2018 compared to $224 million in 2017. Borrowings and repayments of borrowings on Entergy’s long-term credit facility are included in long-term debt activity; and

•	proceeds from the issuance of common stock of $499 million as a result of the settlement of equity forwards in 2018. See Note 7 to the financial statements for discussion of the equity forward sale agreements.

•	Entergy’s net issuances of $1,123 million of commercial paper in 2017 compared to net repayments of $78 million of commercial paper in 2016;

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an increase of $95 million resulting from lower redemptions of preferred stock. In 2017, Entergy New Orleans redeemed its $7.8 million of 4.75% Series preferred stock, its $6 million of 5.56% Series preferred stock, and its $6 million of 4.36% Series preferred stock. In 2016, Entergy Arkansas redeemed its $75 million of 6.45% Series preferred stock and its $10 million of 6.08% Series preferred stock and Entergy Mississippi redeemed its $30 million of 6.25% Series preferred stock;

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•	an increase of $48 million in treasury stock issuances in 2017 primarily due to a larger amount of previously repurchased Entergy Corporation common stock issued in 2017 to satisfy stock option exercises; and

•	net borrowings of $41 million by the nuclear fuel company variable interest entities in 2017 compared to net repayments of $1 million in 2016.

(a)	Based on 2017 test year. Authorized return on common equity for 2018 and 2019 test years will be 9.2% - 10.4%.

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•	The commodity price risk associated with the sale of electricity by the Entergy Wholesale Commodities business.

•	The interest rate and equity price risk associated with Entergy’s investments in pension and other postretirement benefit trust funds. See Note 11 to the financial statements for details regarding Entergy’s pension and other postretirement benefit trust funds.

•	The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds, particularly in the Entergy Wholesale Commodities business. See Note 16 to the financial statements for details regarding Entergy’s decommissioning trust funds.

•	The interest rate risk associated with changes in interest rates as a result of Entergy’s outstanding indebtedness. Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization. See Notes 4 and 5 to the financial statements for the details of Entergy’s debt outstanding.

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(a)	Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts, or options that mitigate price uncertainty. Positions that are not classified as hedges are netted in the planned generation under contract.

(b)

Transaction under which power is supplied from a specific generation asset; if the asset is not operating, the seller is generally not liable to the buyer for any damages. Certain unit-contingent sales include a guarantee of availability. Availability guarantees provide for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of Entergy’s outstanding guarantees of availability provide for dollar limits on Entergy’s maximum liability under such guarantees.

(c)	Amount of output expected to be generated by Entergy Wholesale Commodities nuclear resources considering plant operating characteristics, outage schedules, and expected market conditions that affect dispatch.

(d)

Assumes the planned shutdown of Pilgrim on May 31, 2019, planned shutdown of Indian Point 2 on April 30, 2020, planned shutdown of Indian Point 3 on April 30, 2021, and planned shutdown of Palisades on May 31, 2022. For a discussion regarding the planned shutdown of the Pilgrim, Indian Point 2, Indian Point 3, and Palisades plants, see “Entergy Wholesale Commodities Exit from the Merchant Power Business” above.

(e)	Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions.

(f)	A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold.

(g)	A contract for the sale of an installed capacity product in a regional market.

(h)	Includes assumptions on converting a portion of the portfolio to contracted with fixed price cost or discount and excludes non-cash revenue from the amortization of the Palisades below-market purchased power agreement, mark-to-market activity, and service revenues.

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Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant’s retirement must be estimated for those plants that do not have an announced shutdown date. The estimate may include assumptions regarding the possibility that the plant may have an operating life shorter than the operating license expiration. Second, an assumption must be made regarding whether all decommissioning activity will proceed immediately upon plant retirement, or whether the plant will be placed in SAFSTOR status. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations. A change of assumption

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Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2% to 3% annually. A 50-basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 6% to 18%. The timing assumption influences the significance of the effect of a change in the estimated inflation or cost escalation rate because the effect increases with the length of time assumed before decommissioning activity ends.

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Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy’s nuclear plant owners are continuing to pursue damage claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy’s decommissioning studies include cost estimates for spent fuel storage. These estimates could change in the future, however, based on the expected timing of when the DOE begins to fulfill its obligation to receive and store spent nuclear fuel. See Note 8 to the financial statements for further discussion of Entergy’s spent nuclear fuel litigation.

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Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of nuclear facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates. Given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could be gained, however, and affect current cost estimates. In addition, if regulations regarding nuclear decommissioning were to change, this could significantly affect cost estimates.

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Interest Rates - The estimated decommissioning costs that are the basis for the recorded decommissioning liability are discounted to present value using a credit-adjusted risk-free rate. When the decommissioning liability is revised, increases in cash flows are discounted using the current credit-adjusted risk-free rate. Decreases in estimated cash flows are discounted using the credit-adjusted risk-free rate used previously in estimating the decommissioning liability that is being revised. Therefore, to the extent that a revised cost study results in an increase in estimated cash flows, a change in interest rates from the time of the previous cost estimate will affect the calculation of the present value of the revised decommissioning liability.

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•	Future power and fuel prices - Electricity and gas prices can be very volatile. This volatility increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows.

•	Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets. While market transactions provide evidence for this valuation, these transactions are relatively infrequent, the market for such assets is volatile, and the value of individual assets is affected by factors unique to those assets.

•	Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant effect on operations could cause a significant change in these assumptions.

•	Timing and the life of the asset - Entergy assumes an expected life of the asset. A change in the timing assumption, whether due to management decisions regarding operation of the plant, the regulatory process, or operational or other factors, could have a significant effect on the expected future cash flows and result in a significant effect on operations.

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•	Changes to existing federal, state, or local regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.

•	The identification of additional impacts, sites, issues, or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party.

•	The resolution or progression of existing matters through the court system or resolution by the EPA or relevant state or local authority.

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(a)	“Total Megawatt Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.

(b)	Ouachita Units 1 and 2 are owned 100% by Entergy Arkansas and Ouachita Unit 3 is owned 100% by Entergy Louisiana.  The investment and accumulated depreciation numbers above are only for the common facilities and not for the generating units.

(c)	Union Unit 1 is owned 100% by Entergy New Orleans, Union Unit 2 is owned 100% by Entergy Arkansas, Union Units 3 and 4 are owned 100% by Entergy Louisiana.  The investment and accumulated depreciation numbers above are only for the specified common facilities and not for the generating units.

(d)	Includes a leasehold interest held by System Energy.  System Energy’s Grand Gulf lease obligations are discussed in Note 10 to the financial statements.

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(a)	Does not earn a return on investment, but is offset by related liabilities.

(b)	Does not earn a return on investment.

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(a)	Offset by related asset.

(b)

As a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, and the lowering of the federal corporate income tax rate from 35% to 21% effective January 2018, the Vidalia purchased power agreement regulatory liability was reduced by $30.5 million and the Louisiana Act 55 financing savings obligation regulatory liabilities were reduced by $25.0 million, with corresponding increases to Other regulatory credits on the income statement. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.

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(a)	Includes $67.3 million in 2018 and $67.1 million in 2017 of fuel and purchased power costs whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months.

(b)	Includes $168.1 million in both years for Entergy Louisiana and $4.1 million in both years for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months.

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•	Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.

•	Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.

•

Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.

•	Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

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•	a mid-point reset of formula rate plan revenues to a 9.95% earned return on common equity for the 2017 test year and for the St. Charles Power Station when it enters commercial operation;

•	a 9.8% target earned return on common equity for the 2018 and 2019 test years;

•	narrowing of the common equity bandwidth to plus or minus 60 basis points around the target earned return on common equity;

•	a cap on potential revenue increase of $35 million for the 2018 evaluation period, and $70 million for the cumulative 2018 and 2019 evaluation periods, on formula rate plan cost of service rate increases (the cap excludes rate changes associated with the transmission recovery mechanism described below and rate changes associated with additional capacity);

•	a framework for the flow back of certain tax benefits created by the Tax Act to customers, as described in “Regulatory activity regarding the Tax Cuts and Jobs Act” above; and

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•	a transmission recovery mechanism providing for the opportunity to recover certain transmission-related expenditures in excess of $100 million annually for projects placed in service up to one month prior to rate change outside of sharing that is designed to operate in a fashion similar to the additional capacity mechanism.

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•	Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.

•	Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.

•

Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.

•	Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

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•	Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.

•	Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.

•

Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc., in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.

•	Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

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•	The FERC’s conclusion that the System Agreement no longer roughly equalized total production costs among the Utility operating companies.

•	In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs would have to be within +/- 11% of Entergy System average total annual production costs.

•

In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant would not reflect the actual Vidalia price for the year but be priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs.

•	The remedy ordered by the FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs with the first reallocation payments made in 2007.

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(a)	See “Other Tax Matters - Tax Cuts and Jobs Act” below for discussion of the amortization of excess ADIT in 2018 and the tax legislation enactment in 2017.

(b)	See “Other Tax Matters - Entergy Arkansas and Entergy Mississippi Internal Restructuring” below for discussion of the Utility restructuring.

(c)	See “Income Tax Audits - 2012-2013 IRS Audit” below for discussion of the settlement.

(d)	See “Other Tax Matters - Entergy Wholesale Commodities Restructuring” below for discussion of the Entergy Wholesale Commodities nuclear decommissioning trust restructuring in 2018 and the Entergy Wholesale Commodities restructuring in 2016 and 2017.

(e)	See “Income Tax Audits - 2010-2011 IRS Audit” below for discussion of the settlement and the most significant items for 2016.

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(a)	See Note 2 to the financial statements for discussion of the Entergy Texas rate case settlement.

(b)	See “Other Tax Matters - Tax Cuts and Jobs Act” below for discussion of the amortization of excess ADIT in 2018 and the tax legislation enactment in 2017.

(c)	See “Income Tax Audits - 2012-2013 IRS Audit” below for discussion of the settlement for Entergy Louisiana.

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(d)	See “Income Tax Audits - 2010-2011 IRS Audit” below for discussion of the most significant items for Entergy Louisiana.

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(a)	Potential tax liability above what is payable on tax returns

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(a)

The primary additions for Entergy Mississippi in 2018, Entergy New Orleans in 2017 and Entergy Louisiana in 2016 are related to the mark-to-market treatment discussed in “Other Tax Matters - Tax Accounting Methods” below. The primary additions for Entergy Arkansas in 2018 are related to the nuclear decommissioning costs treatment and the mark-to-market treatment discussed in “Other Tax Matters - Tax Accounting Methods” below.

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•

Entergy and the IRS agreed that $148.6 million of the proceeds received by Entergy Louisiana in 2010 from the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, for the financing of Hurricane Gustav and Hurricane Ike storm costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55) were not taxable. Because the treatment of the financing is settled, Entergy recognized previously unrecognized tax benefits totaling $63.5 million, of which Entergy Louisiana recorded $61.6 million. In accordance with the terms of a previous settlement agreement approved by the LPSC, Entergy Louisiana has a regulatory liability of $13.5 million ($10 million net-of-tax) for Entergy Louisiana’s obligation to pay to customers savings associated with the Act 55 financing.

•	Entergy and the IRS agreed upon the tax treatment of Entergy Louisiana’s regulatory liability related to the Vidalia purchased power agreement. As a result, Entergy Louisiana recognized a previously unrecognized tax benefit of $74.5 million.

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•	repeal of the corporate alternative minimum tax (AMT),

•	modification to the capital contribution rules under Internal Revenue Code section 118,

•	repeal of domestic production activities deduction, and

•	fundamental changes to the taxation of multinational entities.

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(a)	The interest rate is the estimated interest rate as of December 31, 2018 that would have been applied to outstanding borrowings under the facility.

(b)	Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable at Entergy Arkansas’s option.

(c)	The credit facility includes fronting commitments for the issuance of letters of credit against a portion of the borrowing capacity of the facility as follows: $5 million for Entergy Arkansas; $15 million for Entergy Louisiana; $10 million for Entergy New Orleans; and $30 million for Entergy Texas.

(d)	Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option.

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(a)	As of December 31, 2018, letters of credit posted with MISO covered financial transmission right exposure of $0.2 million for Entergy Mississippi and $4.1 million for Entergy Texas. See Note 15 to the financial statements for discussion of financial transmission rights.

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(a)	Includes letter of credit fees and bank fronting fees on commercial paper issuances by the nuclear fuel company variable interest entities for Entergy Arkansas, Entergy Louisiana, and System Energy. The nuclear fuel company variable interest entity for Entergy Louisiana River Bend does not issue commercial paper, but borrows directly on its bank credit facility.

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(a)	Consists of pollution control revenue bonds and environmental revenue bonds, some of which are secured by collateral mortgage bonds.

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(b)

Pursuant to the Nuclear Waste Policy Act of 1982, Entergy’s nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service.  The contracts include a one-time fee for generation prior to April 7, 1983.  Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt.

(c)	The fair value excludes lease obligations of $34 million at System Energy and long-term DOE obligations of $187 million at Entergy Arkansas, and includes debt due within one year.  Fair values are classified as Level 2 in the fair value hierarchy discussed in Note 15 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported trades.

(d)	See Note 10 to the financial statements for detail of payments under the Grand Gulf lease obligation.

•	maintain System Energy’s equity capital at a minimum of 35% of its total capitalization (excluding short-term debt);

•	permit the continued commercial operation of Grand Gulf;

•	pay in full all System Energy indebtedness for borrowed money when due; and

•	enable System Energy to make payments on specific System Energy debt, under a supplement to the agreement assigning System Energy’s rights in the agreement as security for the specific debt.

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(a)	Consists of pollution control revenue bonds and environmental revenue bonds.

(b)

Pursuant to the Nuclear Waste Policy Act of 1982, Entergy’s nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service.  The contracts include a one-time fee for generation prior to April 7, 1983.  Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt.

(c)	The fair value excludes lease obligations of $34 million at System Energy and long-term DOE obligations of $187 million at Entergy Arkansas, and includes debt due within one year.  Fair values are classified as Level 2 in the fair value hierarchy discussed in Note 15 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported trades.

(d)	The bonds are secured by a series of collateral mortgage bonds.

(e)	See Note 10 to the financial statements for detail of payments under the Grand Gulf lease obligation.

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(a)

In October 2015, Entergy Utility Holding Company, LLC issued 110,000 units of $1,000 liquidation value 7.5% Series A Preferred Membership Interests, all of which are outstanding as of December 31, 2018. The distributions are cumulative and payable quarterly. These units are redeemable on or after January 1, 2036, at Entergy Utility Holding Company, LLC’s option, at the fixed redemption price of $1,000 per unit. Dollar amount outstanding is net of $2,575 thousand of preferred stock issuance costs.

(b)

In November 2017, Entergy Utility Holding Company, LLC issued 15,000 units of $1,000 liquidation value 6.25% Series B Preferred Membership Interests, all of which are outstanding as of December 31, 2018. The distributions are cumulative and payable quarterly. These units are redeemable on or after February 28, 2038, at Entergy Utility Holding Company, LLC’s option, at the fixed redemption price of $1,000 per unit. Dollar amount outstanding is net of $634 thousand of preferred stock issuance costs.

(c)

In November 2018, Entergy Utility Holding Company, LLC issued 75,000 units of $1,000 liquidation value 6.75% Series C Preferred Membership Interests, all of which are outstanding as of December 31, 2018. The distributions are cumulative and payable quarterly. These units are redeemable on or after February 28, 2039, at Entergy Utility Holding Company, LLC’s option, at the fixed redemption price of $1,000 per unit. Dollar amount outstanding is net of $1,638 thousand of preferred stock issuance costs.

(d)	In December 2013, Entergy Finance Holding, Inc. issued 250,000 shares of $100 par value 8.75% Series Preferred Stock, all of which are outstanding as of December 31, 2017. The dividends are cumulative and payable quarterly. The preferred stock is redeemable on or after December 16, 2023, at Entergy Finance

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(a)	In November 2018, Entergy Arkansas redeemed all of its preferred membership interests as part of a multi-step internal restructuring. See Note 2 to the financial statements for a discussion of Entergy Arkansas’s internal restructuring.

(b)	In November 2018, Entergy Mississippi redeemed all of its preferred membership interests as part of a multi-step internal restructuring. See Note 2 to the financial statements for a discussion of Entergy Mississippi’s internal restructuring.

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1.

The primary level is private insurance underwritten by American Nuclear Insurers (ANI) and provides public liability insurance coverage of $450 million for each operating reactor (prior to January 1, 2017, the primary level of insurance was $375 million).  If this amount is not sufficient to cover claims arising from an accident, the second level, Secondary Financial Protection, applies. In 2016 the NRC approved Vermont Yankee’s exemption request to lower their limits from $375 million to $100 million effective April 15, 2016.

2.

Within the Secondary Financial Protection level, each nuclear reactor has a contingent obligation to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary level, regardless of proximity to the incident or fault, up to a maximum of approximately $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.238 billion).  This retrospective premium is payable at a rate currently set at approximately $21 million per year per incident per nuclear power reactor.

3.

In the event that one or more acts of terrorism cause a nuclear power plant accident, which results in third-party damages – off-site property and environmental damage, off-site bodily injury, and on-site third-party bodily injury (i.e. contractors), the primary level provided by ANI combined with the Secondary Financial Protection would provide approximately $14 billion in coverage.  The Terrorism Risk Insurance

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•	100% of the weekly indemnity for each week for the first payment period of 52 weeks; then

•	80% of the weekly indemnity for each week for the second payment period of 52 weeks; and thereafter

•	80% of the weekly indemnity for an additional 58 weeks for the third and final payment period.

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(a)	See “Coal Combustion Residuals” below for additional discussion regarding the asset retirement obligations related to coal combustion residuals management.

(b)	The Vermont Yankee asset retirement obligation was classified as held for sale within other non-current liabilities on the consolidated balance sheet as of December 31, 2018. See Note 14 to the financial statements for discussion of the sale of the Vermont Yankee plant to NorthStar in January 2019.

(c)	The FitzPatrick asset retirement obligation was classified as held for sale within other non-current liabilities on the consolidated balance sheet as of December 31, 2016. See Note 14 to the financial statements for discussion of the sale of the FitzPatrick plant to Exelon in March 2017.

(d)	See Note 14 to the financial statements for discussion of the sale of the FitzPatrick plant to Exelon in March 2017.

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(a)	Amounts reflect 100% of minimum payments. Under a separate contract, which expires May 31, 2022, Entergy Louisiana purchases 50% of the capacity and energy from the power purchase agreement from Entergy Texas.

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•	Level 1 - Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in active markets that the Plan has the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

•

Level 2 - Level 2 inputs are inputs other than quoted prices included in Level 1 that are, either directly or indirectly, observable for the asset or liability at the measurement date.  Assets are valued based on prices derived by an independent party that uses inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads.  Prices are reviewed and can be challenged with the independent parties and/or overridden if it is believed such would be more reflective of fair value.  Level 2 inputs include the following:

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•	Level 3 - Level 3 refers to securities valued based on significant unobservable inputs.

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(a)	Certain preferred stocks and certain fixed income debt securities (corporate, government, and securitized) are stated at fair value as determined by broker quotes.

(b)	Common stocks, certain preferred stocks, and certain fixed income debt securities (government) are stated at fair value determined by quoted market prices.

(c)

The common collective trusts hold investments in accordance with stated objectives.  The investment strategy of the trusts is to capture the growth potential of equity markets by replicating the performance of a specified index.  Net asset value per share of common collective trusts estimate fair value. Certain of these common collective trusts are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table.

(d)	Registered investment companies are money market mutual funds with a stable net asset value of one dollar per share. Registered investment companies may hold investments in domestic and international bond markets or domestic equities and estimate fair value using net asset value per share.

(e)	Certain of these registered investment companies are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table.

(f)	The other remaining assets are U.S. municipal and foreign government bonds stated at fair value as determined by broker quotes.

(g)	The unallocated insurance contract investments are recorded at contract value, which approximates fair value.  The contract value represents contributions made under the contract, plus interest, less funds used to pay benefits and contract expenses, and less distributions to the master trust.

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(a)	The cash flows extending through the 2021 shutdown at Indian Point 3 were assigned a higher discount factor to incorporate the increased risk associated with longer operations.

(b)	Most of the Palisades output is sold under a 15-year power purchase agreement, entered at the plant’s acquisition in 2007, that expires in 2022. The power purchase agreement prices currently exceed market prices and escalate each year, up to $61.50/MWh in 2022.

(c)	The fair value of Palisades at December 31, 2016 is based on the probability weighting of whether the PPA will terminate before the originally scheduled termination in 2022.

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(a)	Represents the gross amounts of recognized assets/liabilities

(b)	Represents the netting of fair value balances with the same counterparty

(c)	Represents the net amounts of assets/liabilities presented on the Entergy Corporation and Subsidiaries’ Consolidated Balance Sheet

(d)	Excludes cash collateral in the amount of $19 million posted as of December 31, 2018 and $1 million posted and $4 million held as of December 31, 2017. Also excludes letters of credit in the amount of $4 million posted as of December 31, 2018 and $34 million in letters of credit held as of December 31, 2017.

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(a)	Before taxes of ($14) million, $38 million, and $103 million, for the years ended December 31, 2018, 2017, and 2016, respectively

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(a)

Due to regulatory treatment, the natural gas swaps and options are marked-to-market through fuel, fuel-related expenses, and gas purchased for resale and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability.  The gains or losses recorded as fuel expenses when the swaps and options are settled are recovered or refunded through fuel cost recovery mechanisms.

(b)

Due to regulatory treatment, the changes in the estimated fair value of financial transmission rights for the Utility operating companies are recorded through purchased power expense and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability.  The gains or losses recorded as purchased power expense when the financial transmission rights for the Utility operating companies are settled are recovered or refunded through fuel cost recovery mechanisms.

(c)	Amount of gain recognized in accumulated other comprehensive income from electricity swaps and options de-designated as hedged items.

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(a)	Represents the gross amounts of recognized assets/liabilities

(b)	Represents the netting of fair value balances with the same counterparty

(c)	Represents the net amounts of assets/liabilities presented on the Registrant Subsidiaries’ balance sheets

(d)

As of December 31, 2018, letters of credit posted with MISO covered financial transmission rights exposure of $0.2 million for Entergy Mississippi, and $4.1 million for Entergy Texas. As of December 31, 2017, letters of credit posted with MISO covered financial transmission rights exposure of $0.2 million for Entergy Arkansas, $0.1 million for Entergy Mississippi, and $0.05 million for Entergy Texas.

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(a)

Due to regulatory treatment, the natural gas swaps and options are marked-to-market through fuel, fuel-related expenses, and gas purchased for resale and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability.  The gains or losses recorded as fuel expenses when the swaps and options are settled are recovered or refunded through fuel cost recovery mechanisms.

(b)

Due to regulatory treatment, the changes in the estimated fair value of financial transmission rights for the Utility operating companies are recorded through purchased power expense and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability.  The gains or losses recorded as purchased power expense when the financial transmission rights for the Utility operating companies are settled are recovered or refunded through fuel cost recovery mechanisms.

•

Level 1 - Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the entity has the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.  Level 1 primarily consists of individually owned common stocks, cash equivalents (temporary cash investments, securitization recovery trust account, and escrow accounts), debt instruments, and gas swaps traded on exchanges with active markets.  Cash equivalents includes all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at the date of purchase.

•

Level 2 - Level 2 inputs are inputs other than quoted prices included in Level 1 that are, either directly or indirectly, observable for the asset or liability at the measurement date.  Assets are valued based on prices derived by independent third parties that use inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads.  Prices are reviewed and can be challenged with the independent parties and/or overridden by Entergy if it is believed such would be more reflective of fair value.  Level 2 inputs include the following:

–	quoted prices for similar assets or liabilities in active markets;

–	quoted prices for identical assets or liabilities in inactive markets;

–	inputs other than quoted prices that are observable for the asset or liability; or

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–	inputs that are derived principally from or corroborated by observable market data by correlation or other means.

•

Level 3 - Level 3 inputs are pricing inputs that are generally less observable or unobservable from objective sources.  These inputs are used with internally developed methodologies to produce management’s best estimate of fair value for the asset or liability.  Level 3 consists primarily of financial transmission rights and derivative power contracts used as cash flow hedges of power sales at merchant power plants.

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(a)	The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices.  Fixed income securities are held in various governmental and corporate securities.  See Note 9 to the financial statements for additional information on the investment portfolios.

(b)	Common trust funds are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date.

(a)	Change in unrealized gains or losses for the period included in earnings for derivatives held at the end of the reporting period is ($3.5) million, $0.9 million, and $0.2 million for the years ended December 31, 2018, 2017, and 2016, respectively.

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(a)	The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices.  Fixed income securities are held in various governmental and corporate securities.  See Note 9 to the financial statements for additional information on the investment portfolios.

(b)	Common trust funds are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date.

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(a)	Debt securities presented herein do not include the $389 million of debt securities held in the wholly-owned registered investment company, which are not accounted for as available-for-sale.

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(a)

Sales for resale and competitive businesses sales include day-ahead sales of energy in a market administered by an ISO. These sales represent financially binding commitments for the sale of physical energy the next day. These sales are adjusted to actual power generated and delivered in the real time market. Given the short duration of these transactions, Entergy does not consider them to be derivatives subject to fair value adjustments, and includes them as part of customer revenues.

(b)	Other electric revenues consist primarily of transmission and ancillary services provided to participants of an ISO-administered market and unbilled revenue.

(c)	Non-customer revenues include the settlement of financial hedges, occasional sales of inventory, alternative revenue programs, provisions for revenue subject to refund, and late fees.

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•	The Utility business segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operation of a small natural gas distribution business.

•

The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” for discussion of the operation and planned shutdown or sale of each of the Entergy Wholesale Commodities nuclear power plants.

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(a)	Includes the effect of intercompany eliminations.

(a)	Major industrial customers are primarily in the petroleum refining and chemical industries.

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(a)	Based on 2019 forward test year.

(b)	Based on December 31, 2017 test year and excludes approximately $520 million transmission plant through August 31, 2018, included in transmission rider.

(c)	Authorized return on common equity for 2018 and 2019 test years will be 9.8%.

(d)	Based on September 30, 2017 test year.

(e)	Based on 2018 forward test year.

(f)	Based on December 31, 2011 test year and excludes approximately $228 million first-year average rate base for Union.

(g)	Based on December 31, 2011 test year.

(h)	Based on December 31, 2017 adjusted test year

(i)	Based on calculation as of December 31, 2018.

(j)	See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy’s authorized return on common equity.

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(a)	“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.

•	Entergy Louisiana’s June 2005 purchase of the 718 MW, gas-fired Perryville plant, of which 35% of the output is sold to Entergy Texas;

•	Entergy Arkansas’s September 2008 purchase of the 789 MW, combined-cycle, gas-fired Ouachita Generating Facility. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns one-third of the facility;

•	Entergy Arkansas’s November 2012 purchase of the 620 MW, combined-cycle, gas-fired Hot Spring Energy facility;

•	Entergy Mississippi’s November 2012 purchase of the 450 MW, combined-cycle, gas-fired Hinds Energy facility;

•	Entergy Louisiana’s construction of the 560 MW, combined-cycle, gas turbine Ninemile 6 generating facility at its existing Ninemile Point electric generating station. The facility reached commercial operation in December 2014;

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•	Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine St. Charles generating facility at its existing Little Gypsy electric generating station. Entergy Louisiana received regulatory approval from the LPSC in December 2016 and the facility is scheduled to be in service by mid-2019;

•	Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County generating facility at its existing Lewis Creek electric generating station. Entergy Texas received regulatory approval from the PUCT in July 2017 and the facility is scheduled to be in service by mid-2021;

•	Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station. Entergy Louisiana received regulatory approval from the LPSC in July 2017 and the facility is scheduled to be in service by mid-2020;

•

In August 2018, Entergy New Orleans executed an asset acquisition agreement, subject to applicable regulatory approvals and closing conditions, structured as a build-own-transfer for a 50 MW solar photovoltaic electric generating facility located in Washington Parish, Louisiana. Entergy New Orleans also executed an agreement to purchase a project that will be developed. The New Orleans Solar Station is expected to be a 20 MW solar photovoltaic electric generating facility. Both the build-own-transfer and the New Orleans Solar Station were filed, in July 2018, as a package with the agreement with St. James Solar, LLC, discussed below, for regulatory approval in an effort to satisfy the commitment to transact for 100 MW of renewable resources; and

•	In October 2018, Entergy Mississippi signed an asset acquisition agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic facility located in Sunflower County, Mississippi. In December 2018, Entergy Mississippi filed for regulatory approval.

•	River Bend 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;

•	Entergy Arkansas wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);

•	In December 2009, Entergy Texas and Exelon Generation Company, LLC executed a 10-year agreement for 150-300 MW from the Frontier Generating Station located in Grimes County, Texas;

•	In May 2011, Entergy Texas and Calpine Energy Services, L.P. executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. Entergy Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;

•

In September 2012, Entergy Gulf States Louisiana executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from Rain CII Carbon LLC’s pet coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with the facility;

•	In March 2013, Entergy Gulf States Louisiana executed a 20-year agreement for 8.5 MW from Agrilectric Power Partners, LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with Agrilectric;

•	In September 2013, Entergy Louisiana executed a 10-year agreement with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;

•	Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;

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•	In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;

•	In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. The transaction received regulatory approval and will begin in June 2022;

•	In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;

•	In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and will begin in May 2020;

•	In November 2017, Entergy Louisiana and LA3 West Baton Rouge, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the agreement is expected to begin in March 2020; and

•	In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. As discussed above, the purchased power agreement was filed as a package for regulatory approval in July 2018 and the application is pending approval.

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(a)	Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2018 and is expected to provide about less than 1% of its generation in 2019.

(b)	Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2018 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2019.

(c)

Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%.  Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

(d)	Excludes MISO purchases.

(e)	In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. The MISO purchases metric provided for 2018 is not projected for 2019.

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•	mining and milling of uranium ore to produce a concentrate;

•	conversion of the concentrate to uranium hexafluoride gas;

•	enrichment of the uranium hexafluoride gas;

•	fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and

•	disposal of spent fuel.

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•	Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.

•	Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.

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Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.

•	Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

•	Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.

•	Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.

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Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.

•	Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

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•	Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.

•	Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.

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Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.

•	Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

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(a)	The Pilgrim plant is expected to cease operations on May 31, 2019, at the end of its current fuel cycle.

(b)	The Indian Point 2 and Indian Point 3 plants are expected to cease operation by April 30, 2020 and April 30, 2021, respectively.

(c)	On December 29, 2014, the Vermont Yankee plant ceased power production. In January 2019, the Vermont Yankee plant was sold to NorthStar.

(d)	The Palisades plant is expected to cease operations on May 31, 2022.

(a)	“Net Owned Capacity” refers to the nameplate rating on the generating unit.

(b)	The owned MW capacity is the portion of the plant capacity owned by Entergy Wholesale Commodities.  For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.

(c)	Indirectly owned through interests in unconsolidated joint ventures.

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•	the transmission and wholesale sale of electric energy in interstate commerce;

•	the reliability of the high voltage interstate transmission system through reliability standards;

•	sale or acquisition of certain assets;

•	securities issuances;

•	the licensing of certain hydroelectric projects;

•	certain other activities, including accounting policies and practices of electric and gas utilities; and

•	changes in control of FERC jurisdictional entities or rate schedules.

•	utility service;

•	retail rates;

•	fuel cost recovery;

•	reasonable and adequate service;

•	leasing;

•	the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;

•	depreciation rates;

•	certificates of convenience and necessity and certificates of environmental compatibility and public need; and

•	the issuance and sale of certain securities.

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•	utility service;

•	retail rates and charges;

•	standards of service;

•	certification of generating facilities and certain transmission projects;

•	certification of power or capacity purchase contracts;

•	audit of the fuel adjustment charge, environmental adjustment charge, avoided cost payment to Qualifying Facilities, energy efficiency rider, and purchased gas adjustment charge;

•	integrated resource planning;

•	utility mergers and acquisitions and other changes of control; and

•	depreciation and other matters.

•	utility service;

•	service areas;

•	facilities;

•	certification of generating facilities and certain transmission projects;

•	retail rates;

•	fuel cost recovery;

•	depreciation rates; and

•	mergers and changes of control.

•	utility service;

•	retail rates and charges;

•	standards of service;

•	depreciation and other matters;

•	integrated resource planning;

•	audit of fuel adjustment charge, environmental adjustment charge, and purchased gas adjustment charge;

•	issuance and sale of certain securities; and

•	mergers and changes of control.

•	retail rates and service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;

•	customer service standards;

•	certification of certain transmission and generation projects; and

•	extensions of service into new areas.

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•	New source review and preconstruction permits for new sources of criteria air pollutants, greenhouse gases, and significant modifications to existing facilities;

•	Acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx);

•	Nonattainment area programs for control of criteria air pollutants, which could include fee assessments for air pollutant emission sources under Section 185 of the Clean Air Act if attainment is not reached in a timely manner;

•	Hazardous air pollutant emissions reduction programs;

•	Interstate Air Transport;

•	Operating permit programs and enforcement of these and other Clean Air Act programs;

•	Regional Haze programs; and

•	New and existing source standards for greenhouse gas and other air emissions.

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•	designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;

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introduction of bills in Congress and development of regulations by the EPA proposing further limits on NOx, SO2, mercury, and carbon dioxide and other air emissions.  New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;

•	efforts in Congress or at the EPA to establish a federal carbon dioxide emission tax, control structure or unit performance standards;

•	revisions to the estimates of the Social Cost of Carbon and its use for regulatory impact analysis of Federal laws and regulations;

•	implementation of the Regional Greenhouse Gas Initiative by several states in the northeastern United States and similar actions in other regions of the United States;

•	efforts on the state and federal level to codify renewable portfolio standards, a clean energy standard, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;

•	efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;

•	efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of PCBs;

•	efforts by certain external groups to encourage reporting and disclosure of carbon dioxide emissions and risk;

•	the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the legal protection of eagles and migratory birds; and

•	the regulation of the management, disposal, and beneficial reuse of coal combustion residuals.

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•	prevailing market prices for natural gas, uranium (and its conversion, enrichment, and fabrication), coal, oil, and other fuels used in electric generation plants, including associated transportation costs, and supplies of such commodities;

•	seasonality and realized weather deviations compared to normalized weather forecasts;

•	availability of competitively priced alternative energy sources and the requirements of a renewable portfolio standard;

•	changes in production and storage levels of natural gas, lignite, coal and crude oil, and refined products;

•	liquidity in the general wholesale electricity market, including the number of creditworthy counterparties available and interested in entering into forward sales agreements for Entergy’s full hedging term;

•	the actions of external parties, such as the FERC and local independent system operators and other state or Federal energy regulatory bodies, that may impose price limitations and other mechanisms to address some of the volatility in the energy markets;

•	electricity transmission, competing generation or fuel transportation constraints, inoperability, or inefficiencies;

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•	the general demand for electricity, which may be significantly affected by national and regional economic conditions;

•	weather conditions affecting demand for electricity or availability of hydroelectric power or fuel supplies;

•	the rate of growth in demand for electricity as a result of population changes, regional economic conditions, and the implementation of conservation programs or distributed generation;

•	regulatory policies of state agencies that affect the willingness of Entergy Wholesale Commodities customers to enter into long-term contracts generally, and contracts for energy in particular;

•	increases in supplies due to actions of current Entergy Wholesale Commodities competitors or new market entrants, including the development of new generation facilities, expansion of existing generation facilities, the disaggregation of vertically integrated utilities, and improvements in transmission that allow additional supply to reach Entergy Wholesale Commodities’ nuclear markets;

•	union and labor relations;

•	changes in Federal and state energy and environmental laws and regulations and other initiatives, such as the Regional Greenhouse Gas Initiative, including but not limited to, the price impacts of proposed emission controls;

•	changes in law resulting from federal or state energy legislation or legislation subjecting energy derivatives used in hedging and risk management transactions to governmental regulation; and

•	natural disasters, terrorist actions, wars, embargoes, and other catastrophic events.

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•	the disposition of a business or asset may involve continued financial involvement in the divested business, such as through continuing equity ownership, transition service agreements, guarantees, indemnities, or other current or contingent financial obligations;

•

Entergy may encounter difficulty in finding buyers or executing alternative exit strategies on acceptable terms in a timely manner when it decides to sell an asset or a business, which could delay the accomplishment of its strategic objectives. Alternatively, Entergy may dispose of a business or asset at a price or on terms that are less than what it had anticipated, or with the exclusion of assets that must be divested or run off separately;

•	the disposition of a business could result in impairments and related write-offs of the carrying values of the relevant assets;

•	acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;

•	acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;

•	Entergy and/or its subsidiaries may assume liabilities that were not disclosed to them, that exceed their estimates, or for which their rights to indemnification from the seller are limited;

•	the disposition of a business, including Entergy’s planned exit from the merchant power business, could divert management’s attention from other business concerns;

•	Entergy and/or its subsidiaries may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable

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•	Entergy or its subsidiaries otherwise may be unable to achieve the full strategic and financial benefits that they anticipate from the transaction, or such benefits may be delayed or may not occur at all.

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•	Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.

•	Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.

•

Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.

•	Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

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•	an increase of $16 million in energy efficiency costs;

•	an increase of $10.4 million in fossil-fueled generation expenses primarily due to higher long-term service agreement costs and higher labor costs in 2018 as compared to 2017;

•	an increase of $4.4 million in information technology expenses primarily due to higher labor costs and higher contract costs; and

•	an increase of $4 million as a result of the amount of transmission costs allocated by MISO.

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the deferral in the first quarter 2016 of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC as part of the 2015 rate case settlement. These costs are being amortized over a ten-year period beginning March 2016. See Note 2 to the financial statements for further discussion of the rate case settlement;

•	an increase of $9.5 million in transmission and distribution expenses primarily due to higher vegetation maintenance costs and higher labor costs, including contract labor;

•	an increase of $5.9 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to 2016; and

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the effect of recording in July 2016 the final court decision in a lawsuit against the DOE related to spent nuclear fuel storage costs. The damages awarded included the reimbursement of $5.5 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for further discussion of Entergy Arkansas’s spent nuclear fuel litigation.

•

a decrease of $16 million in nuclear generation expenses primarily due to a decrease in regulatory compliance costs compared to the prior year, partially offset by higher nuclear labor costs, including contract labor, to position the nuclear fleet to meet its operational goals. The decrease in regulatory compliance costs is primarily related to NRC inspection activities in 2016 as a result of the NRC’s March 2015 decision to move ANO into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. See Note 8 to the financial statements for a discussion of the ANO stator incident and subsequent NRC reviews;

•	a decrease of $11.5 million in energy efficiency expenses primarily due to the timing of recovery from customers; and

•	a decrease of $5.2 million in fossil-fueled generation expenses primarily due to lower long-term service agreement costs, partially offset by an overall higher scope of work including plant outages in 2017 as compared to 2016.

•	an increase of $3.3 million in estimated interest expense recorded in connection with the opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding;

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the issuance in May 2017 of $220 million of 3.5% Series first mortgage bonds and the issuance in June 2016 of $55 million of 3.5% Series first mortgage bonds, partially offset by the redemption in July 2016 of $60 million of 6.38% Series first mortgage bonds and the redemption in February 2016 of $175 million of 5.66% Series first mortgage bonds. See Note 5 to the financial statements for further discussion of long-term debt.

•	the return of unprotected excess accumulated deferred income taxes to customers. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act;

•	payments of $135 million to the other Utility operating companies as a result of a compliance filing made in response to the FERC’s October 2018 order in the opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding; and

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income tax payments of $44.4 million in 2018 compared to income tax refunds of $8.1 million in 2017. Entergy Arkansas had income tax payments in 2018 and income tax refunds in 2017 in accordance with an intercompany income tax allocation agreement. The income tax payments in 2018 primarily resulted from the settlement of the 2012-2013 audit. The income tax refunds in 2017 resulted from the utilization of Entergy Arkansas’s net operating losses.

•	the timing of recovery of fuel and purchased power costs;

•	the effect of favorable weather on billed sales;

•	the timing of collection of receivables from customers; and

•	a decrease of $15.6 million in pension contributions in 2018. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

•	a decrease of $62.4 million in nuclear construction expenditures primarily due to a lower scope of work performed on various nuclear projects in 2018 as compared to 2017;

•	a decrease of $55.8 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle; and

•	a decrease of $23.5 million in fossil-fueled generation construction expenditures primarily due to the timing of outages and a lower scope of work performed on various projects in 2018 as compared to 2017.

•	an increase of $50.4 million in nuclear construction expenditures primarily due to a higher scope of work performed on various nuclear projects in 2017 as compared to 2016;

•	an increase of $37.7 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle;

•	an increase of $32.9 million in information technology construction expenditures primarily due to increased spending on substation technology upgrades;

•	an increase of $22.3 million in fossil-fueled generation construction expenditures primarily due to a higher scope of work performed on various projects in 2017 as compared to 2016; and

•	an increase of $11.2 million due to increased spending on advanced metering infrastructure.

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•	a $350 million capital contribution from Entergy Corporation in May 2018 in anticipation of the return of unprotected excess accumulated deferred income taxes to customers and upcoming planned capital investments;

•	the repayment, in 2017, of Entergy Arkansas nuclear fuel company variable interest entity’s $60 million of 2.62% Series K notes;

•	the repayment, in 2017, of $54.7 million of 1.55% pollution control revenue bonds;

•	net long-term borrowings of $34.7 million in 2018 on the Entergy Arkansas nuclear fuel company variable interest entity credit facility; and

•	the issuance of $250 million of 4.0% Series first mortgage bonds in May 2018 as compared to the issuance of $220 million of 3.5% Series first mortgage bonds in May 2017.

•	net repayments of short-term borrowings of $50 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2018 as compared to net short-term borrowings of $50 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2017;

•	money pool activity;

•	an increase of $76.8 million in common equity distributions paid in 2018 primarily to maintain Entergy Arkansas’s target capital structure; and

•	the redemption of $31 million of preferred stock in 2018 in connection with the internal restructuring. See Note 2 to the financial statements for further discussion of the internal restructuring and Note 6 to the financial statements for details of preferred stock activity.

•	a $200 million capital contribution received from Entergy Corporation in March 2016 primarily in anticipation of Entergy Arkansas’s purchase of Power Block 2 of the Union Power Station;

•	the net issuance of $119.1 million of long-term debt in 2017 compared to the net issuance of $189.1 million of long-term debt in 2016; and

•	$15 million in common stock dividends paid in 2017 primarily to maintain Entergy Arkansas’s target capital structure. There were no common stock dividends paid in 2016 in anticipation of the purchase of Power Block 2 of the Union Power Station.

•	money pool activity;

•	the redemptions of $75 million of 6.45% Series preferred stock and $10 million of 6.08% Series preferred stock in 2016; and

•	net short-term borrowings of $50 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2017 compared to net repayments of $11.7 million in 2016.

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(a)	Calculation excludes the securitization bonds, which are non-recourse to Entergy Arkansas.

•	construction and other capital investments;

•	debt maturities or retirements;

•	working capital purposes, including the financing of fuel and purchased power costs; and

•	distribution and interest payments.

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(a)	Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.

(b)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services.  For Entergy Arkansas, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which are discussed in Note 8 to the financial statements.

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•	internally generated funds;

•	cash on hand;

•	debt or preferred membership interest issuances;

•	capital contributions; and

•	bank financing under new or existing facilities.

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•	an increase of $11.9 million in fossil-fueled generation expenses primarily due to an overall higher scope of work performed during plant outages in 2018 as compared to 2017;

•	an increase of $11.7 million in energy efficiency costs primarily due to the implementation of a new energy efficiency program in January 2018;

•	an increase of $9 million in information technology expenses primarily due to higher software maintenance costs and higher contract costs;

•	an increase of $8.3 million in transmission expenses primarily due to higher labor and contract costs to support industrial customers;

•	an increase of $7.2 million in loss provisions; and

•	an increase of $7 million in nuclear generation expenses primarily due to higher nuclear labor costs to position the nuclear fleet to meet its operational goals and a higher scope of work performed during plant outages in 2018 as compared to 2017.

•	a $14.8 million gain as a result of the sale of Willow Glen Power Plant

•	a decrease of $7.4 million as a result of the amortization through November 2017 of deferred MISO implementation costs, as approved by the LPSC;

•	higher nuclear insurance refunds of $4.2 million in 2018; and

•	a decrease of $3.7 million in compensation and benefits costs primarily due to lower incentive-based compensation accruals in 2018 as compared to 2017.

•	an increase of $17.8 million in nuclear generation expenses primarily due to higher nuclear labor costs, including contract labor, to position the nuclear fleet to meet its operational goals, partially offset by a lower scope of work performed during plant outages in 2017;

•	an increase of $9.5 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to the prior year;

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•	an increase of $4.1 million as a result of the amount of transmission costs allocated by MISO. See Note 2 to the financial statements for further information on the recovery of these costs;

•	an increase of $3.6 million in transmission and distribution expenses due to higher vegetation maintenance costs; and

•	an increase of $3.2 million in write-offs of customer accounts.

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•	a decrease of $76.5 million in spending on nuclear fueling outages;

•	a refund to customers in January 2017 of approximately $71 million as a result of the settlement approved by the LPSC related to the Waterford 3 replacement steam generator project. See Note 2 to the financial statements for discussion of the settlement and refund;

•	the receipt of $58.6 million from Entergy Arkansas as a result of a compliance filing made in response to the FERC’s October 2018 order in the Entergy Arkansas opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding; and

•	the timing of collection of receivables from customers.

•	a decrease of $129 million in income tax refunds in 2018 as compared to the same period in 2017. Entergy Louisiana received income tax refunds in 2018 and 2017 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2018 and 2017 resulted from the utilization of Entergy Louisiana’s net operating loss;

•	the return of unprotected excess accumulated deferred income taxes to customers. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act; and

•	the timing of recovery of fuel and purchased power costs.

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income tax refunds of $234.2 million in 2017 compared to income tax payments of $156.6 million in 2016. Entergy Louisiana received income tax refunds in 2017 and made income tax payments in 2016 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2017 resulted from the utilization of Entergy Louisiana’s net operating losses. The income tax payments in 2016 resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit, payments for state taxes resulting from the effect of the final settlement of the 2006-2007 IRS audit, and the effect of net operating loss limitations. See Note 3 to the financial statements for a discussion of the 2010-2011 IRS audit;

•	an increase due to the timing of recovery of fuel and purchased power costs; and

•	an interest payment of $60 million made in March 2016 related to the purchase of a beneficial interest in the Waterford 3 leased assets.

•	a refund to customers in January 2017 of approximately $71 million as a result of the settlement approved by the LPSC related to the Waterford 3 replacement steam generator project. See Note 2 to the financial statements for discussion of the settlement and refund;

•	an increase of $62.8 million in spending on nuclear refueling outages; and

•	proceeds of $37.8 million received in August 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for a discussion of the spent nuclear fuel litigation.

•	an increase of $67.8 million in transmission construction expenditures primarily due to a higher scope of work performed in 2018 as compared to 2017;

•	an increase of $65.5 million in fossil-fueled generation expenditures primarily due to higher spending on the Lake Charles Power Station project in 2018, partially offset by lower spending on the St. Charles Power Station project in 2018; and

•	money pool activity.

•	an increase of $364.3 million in fossil-fueled generation construction expenditures primarily due to higher spending on the St. Charles Power Station and Lake Charles Power Station projects in 2017;

•	an increase of $148.9 million in transmission construction expenditures due to a higher scope of work performed in 2017;

•	an increase of $144.9 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle;

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•	proceeds of $57.9 million received in 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;

•	an increase of $53.6 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2017;

•	an increase of $30.4 million in distribution construction expenditures due to increased spending on digital technology improvements within the customer contact centers;

•	an increase of $19.9 million due to increased spending on advanced metering infrastructure; and

•	an increase of $12.3 million due to various information technology projects and upgrades in 2017.

•	the purchase of Power Blocks 3 and 4 of the Union Power Station for an aggregate purchase price of approximately $475 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;

•	money pool activity; and

•	an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2017.

•	the issuance of $750 million of 4.00% Series collateral trust mortgage bonds in March 2018. A portion of the proceeds was used to repay $375 million of 6.0% Series first mortgage bonds in May 2018;

•	the issuance of $600 million of 4.20% collateral trust mortgage bonds in August 2018. A portion of the proceeds was used to repay $300 million of 6.5% Series first mortgage bonds in September 2018;

•	the redemption of $25 million of 3.25% Series G nuclear fuel company variable interest entity notes payable in June 2017;

•	the redemption of $75 million of 3.25% Series Q nuclear fuel company variable interest entity notes payable in July 2017; and

•	the termination of $57.5 million of the Waterford 3 lease obligation and $42.7 million of Waterford Series collateral trust mortgage notes in 2017.

•	the issuance of $450 million of 3.12% collateral trust mortgage bonds in May 2017. A portion of the proceeds was used to repay $45.3 million of Waterford Series collateral trust mortgage bonds;

•	net repayments of short-term borrowings of $43.5 million on the nuclear fuel company variable interest entities’ credit facilities in 2018 compared to net short-term borrowings of $39.7 million in 2017;

•	net repayments of long-term borrowings of $18.6 million on the nuclear fuel company variable interest entities’ credit facilities in 2018 compared to net long-term borrowings of $102 million in 2017; and

•	an increase of $36.8 million in common equity distributions in 2018 primarily to maintain Entergy Louisiana’s targeted capital structure.

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•	a decrease of $194.3 million of common equity distributions primarily as a result of higher construction expenditures and higher nuclear fuel purchases in 2017; and

•	net borrowings of $39.7 million on the nuclear fuel company variable interest entities’ credit facilities in 2017 compared to net repayments of $56.6 million in 2016

(a)	Calculation excludes the securitization bonds, which are non-recourse to Entergy Louisiana.

•	construction and other capital investments;

•	debt maturities or retirements;

•	working capital purposes, including the financing of fuel and purchased power costs; and

•	distribution and interest payments.

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(a)	Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.

(b)

Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services.  For Entergy Louisiana, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Vidalia purchased power agreement and the Unit Power Sales Agreement, both of which are discussed in Note 8 to the financial statements.

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•	internally generated funds;

•	cash on hand;

•	debt or preferred membership interest issuances;

•	capital contributions; and

•	bank financing under new or existing facilities.

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•	short-term borrowings not to exceed an aggregate amount of $450 million at any time outstanding;

•	long-term borrowings and security issuances; and

•	borrowings by its nuclear fuel company variable interest entities.

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•	a mid-point reset of formula rate plan revenues to a 9.95% earned return on common equity for the 2017 test year and for the St. Charles Power Station when it enters commercial operation;

•	a 9.8% target earned return on common equity for the 2018 and 2019 test years;

•	narrowing of the common equity bandwidth to plus or minus 60 basis points around the earned return on common equity;

•	a cap on potential revenue increase of $35 million for the 2018 evaluation period, and $70 million for the cumulative 2018 and 2019 evaluation periods, on formula rate plan cost of service rate increases (the cap excludes rate changes associated with the transmission recovery mechanism described below and rate changes associated with additional capacity);

•	a framework for the flow back of certain tax benefits created by the Tax Act to customers; and

•	a transmission recovery mechanism providing for the opportunity to recover certain transmission related expenditures in excess of $100 million for projects placed in service up to one month prior to rate change outside of sharing that is designed to operate in a fashion similar to the additional capacity mechanism.

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•	Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.

•	Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.

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Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.

•	Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

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•	a $5.8 million loss on the sale of fuel oil inventory per an agreement approved by the MPSC in June 2018 resulting from the stipulation related to the effects of the Tax Act. There is no effect on net income as the loss on the sale of fuel oil inventory is offset by a reduction in income tax expense. See Note 2 to the financial statements for discussion of the agreement;

•	an increase of $5.2 million in storm damage provisions. See Note 2 to the financial statements for a discussion of storm cost recovery;

•	an increase of $3.1 million in fossil-fueled generation expenses primarily due to an overall higher scope of work done during plant outages;

•	an increase of $2.7 million in customer service costs primarily due to write-offs of customer accounts and higher contract costs; and

•	an increase of $2.1 million in vegetation maintenance costs.

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•	a decrease of $12 million in fossil-fueled generation expenses primarily due to lower long-term service agreement costs and a lower scope of work done during plant outages in 2017 as compared to the same period in 2016; and

•	a decrease of $3.6 million in storm damage provisions. See Note 2 to the financial statements for a discussion of storm cost recovery.

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•	the receipt of $36.2 million from Entergy Arkansas as a result of a compliance filing made in response to the FERC’s October 2018 order in the Entergy Arkansas opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding;

•	the timing of collection of receivables from customers;

•	the timing of recovery of fuel and purchased power costs;

•	$26.2 million in proceeds from the sale of fuel oil inventory in 2018;

•	the effect of favorable weather on billed sales; and

•	the timing of collection of storm damage rider revenues. See Note 2 to the financial statements for further discussion of the storm damage rider.

•	money pool activity;

•	an increase of $9 million in information technology construction expenditures primarily due to increased spending on various technology projects;

•	an increase of $8.4 million in distribution construction expenditures primarily due to increased spending on advanced metering infrastructure; and

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•	several individually insignificant items.

•	a decrease of $35.7 million in transmission construction expenditures primarily due to a lower scope of work performed in 2018;

•	a decrease of $17.1 million in fossil-fueled generation construction expenditures primarily due to a lower scope of work performed in 2018; and

•	a decrease of $15.2 million in storm spending in 2018.

•	an increase of $48.4 million in transmission construction expenditures primarily due to a higher scope of work performed in 2017 as compared to 2016;

•	an increase of $39.2 million in fossil-fueled generation construction expenditures primarily due to a higher scope of work performed in 2017 as compared to 2016; and

•	an increase of $30.2 million in distribution construction expenditures primarily due to an increase in storm spending in 2017 as compared to 2016 and increased spending on digital technology improvements within the customer contact centers.

•	the issuance of $150 million of 3.25% Series first mortgage bonds in November 2017; and

•	the redemption of $20 million of preferred stock in 2018 in connection with the internal restructuring. See Note 2 to the financial statements for further discussion of the internal restructuring and Note 6 to the financial statements for details of preferred stock activity.

•	the issuance of $55 million of 4.52% Series first mortgage bonds in December 2018;

•	a decrease of $16 million in common equity distributions paid in 2018 resulting from Entergy Mississippi’s historical and planned capital investments; and

•	an increase in advances received from customers for transmission projects.

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•	construction and other capital investments;

•	debt maturities or retirements;

•	working capital purposes, including the financing of fuel and purchased power costs; and

•	distributions and interest payments.

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(a)	Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.

(b)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services.  For Entergy Mississippi, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements.

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•	internally generated funds;

•	cash on hand;

•	debt or preferred membership interest issuances;

•	capital contributions; and

•	bank financing under new or existing facilities.

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•	an increase of $2.9 million in distribution expenses primarily due to higher contract labor costs;

•	an increase of $2.8 million in energy efficiency costs;

•	an increase of $2.2 million in gas operation expenses primarily due to higher labor costs, including contract labor;

•	an increase of $2.1 million in loss provisions;

•	an increase of $2.1 million in information technology costs primarily due to higher software maintenance costs and higher contract costs; and

•	an increase of $1.9 million in customer service costs primarily due to higher write-offs of customer accounts in 2018.

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•	a decrease of $7.9 million in fossil-fueled generation expenses primarily due to lower outage costs at Power Block 1 of the Union Power Station in 2017 as compared to 2016, the deactivation of Michoud Units 2 and 3 effective May 2016, and asbestos loss provisions in 2016;

•	a decrease of $4.5 million in other loss provisions; and

•	a decrease of $2.8 million due to lower write-offs of uncollectible customer accounts.

•	an increase of $4 million in distribution expenses primarily due to higher labor costs, including contract labor, and higher vegetation maintenance costs; and

•	an increase of $1.3 million in energy efficiency costs.

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•	an increase of $31.1 million in 2018 of income tax refunds. Entergy New Orleans had income tax refunds in 2018 and 2017 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2018 resulted from the utilization of Entergy New Orleans’s net operating loss; and

•	the receipt of $7 million from Entergy Arkansas as a result of a compliance filing made in response to the FERC’s October 2018 order in the Entergy Arkansas opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding.

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•	the issuance of $60 million of 4.51% Series first mortgage bonds in September 2018;

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a decrease of $50.5 million in common equity distributions in 2018 as compared to 2017. Common equity distributions were lower in 2018 primarily as a result of the construction of the New Orleans Power Station, as discussed below, and the excess accumulated deferred income taxes being returned to customers as a result of the enactment of the Tax Cuts and Jobs act in December 2017. See Note 2 to the financial statements for discussion of regulatory proceedings related to the enactment of the Tax Cuts and Jobs Act;

•	$20 million in capital contributions received from Entergy Corporation in 2017. The 2017 contribution was made in consideration of Entergy New Orleans’s upcoming capital requirements; and

•	the redemption of $19.8 million of preferred stock in 2017 in connection with the internal restructuring, as discussed below.

•	the issuance of $110 million of 5.50% Series first mortgage bonds in March 2016;

•	an increase of $55.5 million in common equity distributions in 2017 as compared to 2016. Common equity distributions in 2017 increased primarily as a result of Entergy New Orleans’s cash position in excess of its working capital requirements. There were no common equity distributions in first quarter 2016 in anticipation of the purchase of Power Block 1 of the Union Power Station in March 2016;

•	a decrease of $27.8 million in capital contributions received from Entergy Corporation in 2017 compared to 2016. The 2017 contribution was made in consideration of Entergy New Orleans’s upcoming capital requirements. The 2016 contribution was made in anticipation of Entergy New Orleans’s purchase of Power Block 1 of the Union Power Station; and

•	the redemptions of $7.8 million of 4.75% Series preferred stock, $6 million of 5.56% Series preferred stock, and $6 million of 4.36% Series preferred stock in 2017 in connection with the internal restructuring, as discussed below.

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•	construction and other capital investments;

•	working capital purposes, including the financing of fuel and purchased power costs;

•	debt maturities or retirements; and

•	distribution and interest payments.

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(a)	Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.

(b)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services.  For Entergy New Orleans, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements.

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•	internally generated funds;

•	cash on hand;

•	debt and preferred membership interest issuances;

•	capital contributions; and

•	bank financing under new or existing facilities.

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•	Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.

•	Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.

•

Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.

•	Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

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•	the write-off of $6 million in capitalized skylining tree hazard costs as a result of the settlement of the rate case proceeding. See Note 2 to the financial statements for further discussion of the rate case proceeding;

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•	an increase of $3.5 million in energy efficiency costs primarily due to the timing of recovery from customers; and

•	an increase of $1.4 million in transmission expenses primarily due to higher labor and contract costs to support industrial customers.

•	an increase of $5.1 million in transmission and distribution expenses primarily due to higher vegetation maintenance costs;

•	an increase of $4.3 million in fossil-fueled generation expenses primarily due to a higher scope of work performed during plant outages in 2017 as compared to 2016; and

•	an increase of $2.8 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to 2016.

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•	the receipt of $33.2 million from Entergy Arkansas as a result of a compliance filing made in response to the FERC’s October 2018 order in the Entergy Arkansas opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the Entergy Arkansas opportunity sales proceeding;

•	the effect of favorable weather on billed sales;

•	a decrease of $18.4 million in storm spending in 2018 as compared to 2017 primarily as a result of Hurricane Harvey in 2017; and

•	a decrease of $6.1 million in pension contributions in 2018 as compared to 2017. See “Critical Accounting Estimates” below and in Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

•

income tax payments of $20.8 million in 2018 compared to income tax refunds of $21.1 million in 2017. The income tax payments in 2018 and the income tax refunds in 2017 were in accordance with an intercompany income tax allocation agreement.  The income tax payments in 2018 primarily resulted from the settlement of the 2012-2013 IRS audit. The income tax refunds in 2017 primarily resulted from deductible temporary differences;

•	the timing of recovery of fuel and purchased power costs; and

•	the return of unprotected excess accumulated deferred income taxes to customers. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.

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•	money pool activity;

•	an increase of $34.9 million in distribution construction expenditures primarily due to increased storm spending primarily as a result of Hurricane Harvey and spending on digital technology improvements within the customer contact centers;

•	an increase of $24.4 million in fossil-fueled generation construction expenditures primarily due to a higher scope of work performed in 2017 as compared to 2016; and

•	an increase of $8.5 million in spending on advanced metering infrastructure.

•	a $115 million capital contribution received from Entergy Corporation in December 2017 in anticipation of upcoming construction expenditures;

•	the issuance of $150 million of 3.45% Series first mortgage bonds in November 2017 compared to the issuance of $125 million of 2.55% Series first mortgage bonds in March 2016; and

•	money pool activity.

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•	construction and other capital investments;

•	debt maturities or retirements;

•	working capital purposes, including the financing of fuel and purchased power costs; and

•	dividend and interest payments.

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(a)	Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.

(b)	Does not include power purchase agreements that are accounted for as leases that are included in purchase obligations.

(c)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services.  For Entergy Texas, it primarily includes unconditional fuel and purchased power obligations.

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•	internally generated funds;

•	cash on hand;

•	debt or preferred stock issuances;

•	capital contributions; and

•	bank financing under new or existing facilities.

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•	the return of unprotected excess accumulated deferred income taxes;

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income tax payments of $54 million in 2018 compared to income tax refunds of $2.2 million in 2017. System Energy made income tax payments in 2018 and received income tax refunds in 2017 in accordance with an intercompany income tax allocation agreement. The income tax payments in 2018 were from the results of operations and the inclusion of taxable temporary differences in the computation of taxable income; and

•	an increase in spending of $51.5 million on nuclear refueling outages in 2018 as compared to the prior year.

•	a decrease in spending of $35.7 million on nuclear refueling outages in 2017 as compared to the prior year;

•	the timing of collection of receivables; and

•	a decrease of $9.9 million in interest paid in 2017.

•	proceeds of $28.4 million received in August 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for a discussion of the spent nuclear fuel litigation; and

•

a decrease of $21.3 million in income tax refunds in 2017. System Energy received income tax refunds in 2017 and 2016 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2017 and 2016 resulted primarily from the adoption of a new accounting method for income tax purposes in which System Energy will treat its nuclear decommissioning costs as production costs of electricity includable in cost of goods sold. See Note 3 to the financial statements for further discussion of the adoption of the new accounting method.

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•	an increase of $114.4 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and

•	an increase of $110.4 million in nuclear construction expenditures primarily as a result of a higher scope of work performed during the Grand Gulf outage in 2018.

•	the issuance in March 2018 of $100 million of 3.42% Series J notes by the System Energy nuclear fuel company variable interest entity;

•	an increase of net long-term borrowings of $63.9 million in 2018 on the nuclear fuel company variable interest entity’s credit facility;

•	the payment in February 2017, at maturity, of $50 million of the System Energy nuclear fuel company variable interest entity’s 4.02% Series H notes;

•	a decrease of $38.9 million in common stock dividends and distributions in 2018 in order to maintain the targeted capital structure; and

•	net repayments of short-term borrowings of $17.8 million on the nuclear fuel company variable interest entity’s credit facility in 2018 compared to net repayments of short-term borrowings of $49.1 million on the nuclear fuel variable interest entity’s credit facility in 2017.

•	the payment in October 2018, at maturity, of $85 million of the System Energy nuclear fuel company variable interest entity’s 3.78% Series I notes; and

•	net long-term borrowings of $50 million in 2017 on the nuclear fuel company variable interest entity’s credit facility.

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•	net repayments of short-term borrowings of $49.1 million on the nuclear fuel company variable interest entity’s credit facility in 2017 as compared to net short-term borrowings of $66.9 million on the nuclear fuel variable interest entity’s credit facility in 2016; and

•	the payment in February 2017, at maturity, of $50 million of the System Energy nuclear fuel company variable interest entity’s 4.02% Series H notes.

•	net long-term borrowings of $50 million in 2017 on the nuclear fuel company variable interest entity’s credit facility;

•	a decrease of $32.4 million in common stock dividends and distributions in 2017 in order to maintain System Energy’s targeted capital structure; and

•	the repayment in May 2016 of $22 million of 5.875% pollution control revenue bonds due 2022 issued on behalf of System Energy.

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•	construction and other capital investments;

•	debt maturities or retirements;

•	working capital purposes, including the financing of fuel costs; and

•	dividend, distribution, and interest payments.

(a)	Includes estimated interest payments.  Long-term debt is discussed in Note 5 to the financial statements.

(b)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For System Energy, it includes nuclear fuel purchase obligations.

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•	internally generated funds;

•	cash on hand;

•	debt issuances; and

•	bank financing under new or existing facilities.

•	short-term borrowings not to exceed an aggregate amount of $200 million at any time outstanding;

•	long-term borrowings and security issuances; and

•	borrowings by its nuclear fuel company variable interest entity.

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(a)	In addition, this officer is an executive officer and/or director of various other wholly owned subsidiaries of Entergy Corporation and its operating companies.

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(1)	See Note 12 to the financial statements for additional discussion of the stock-based compensation plans.

(2)	Maximum amount of shares that may yet be repurchased relates only to the $500 million plan does not include an estimate of the amount of shares that may be purchased to fund the exercise of grants under the stock-based compensation plans.

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•	the number of shares of Entergy Corporation stock held by the shareholder;

•	the name and address of the candidate;

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•	a brief biographical description of the candidate, including his or her occupation for at least the last five years, and a statement of the qualifications of the candidate, taking into account the qualification requirements discussed in the Proxy Statement under “Board of Directors - Identifying Director Candidates”; and

•	the candidate’s signed consent to be named in the Proxy Statement and a representation of such candidates’ intent to serve as a director for the entire term if elected.

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(1)	Messrs. Bakken, Brown, Denault, Marsh, and West hold the positions referenced above as executive officers of Entergy Corporation and are members of Entergy Corporation’s Office of the Chief Executive. No additional compensation was paid in 2018 to any of these officers for their service as Named Executive Officers of the Utility operating companies.

(2)	Mr. Rice is included in the Executive Compensation section of this Form 10-K because he served as President and Chief Executive Officer, Entergy New Orleans for a portion of 2018. Mr. Ellis became President and Chief Executive Officer, New Orleans in December 2018, and for a portion of 2018, Mr. West served as interim President and Chief Executive Officer, Entergy New Orleans.

(3)	Mr. Riley is included in the Executive Compensation section of this Form 10-K because he served as President and Chief Executive Officer, Entergy Arkansas for a portion of 2018. Ms. Landreaux succeeded Mr. Riley as President and Chief Executive Officer, Entergy Arkansas in July 2018.

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•	Annual Incentive Plan incentivizes and rewards the achievement of financial metrics that are deemed by the Entergy Corporation Personnel Committee to be consistent with the overall goals and strategic direction that the Entergy Corporation Board has approved for Entergy Corporation.

•

Long-term incentive programs further align the interests of the executives and Entergy Corporation’s shareholders by directly tying the value of equity awards granted to executives under these programs to Entergy Corporation’s stock price performance, relative total shareholder return, and beginning in 2018, cumulative adjusted utility earnings growth. The long-term incentives consist of three components - performance units, stock options and restricted stock.

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Long-Term Performance Unit Program - Units are granted with performance measured over a three-year period based on Entergy Corporation’s total shareholder return in relation to the total shareholder return of the companies included in the Philadelphia Utility Index, and beginning with the 2018-2020 performance period, a cumulative utility earnings metric. Payouts, if any, are based on Entergy Corporation’s performance on these measures against pre-established performance goals.

•	Stock Options - Incentivizes executives to take actions that increase the market value of Entergy Corporation’s common stock and directly aligns with the value shareholders receive over the same period of time; and

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•	Restricted Stock - Increases executive stock ownership and is an effective retention mechanism.

•	Published and private compensation survey data compiled by Pay Governance;

•	Both utility and general industry data to determine total cash compensation (base salary and annual incentive) for non-industry specific roles;

•	Data from utility companies to determine total cash compensation for management roles that are utility-specific, such as Group President, Utility Operations; and

•	Utility market data to determine long-term incentives for all positions.

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(1)	When Mr. Ellis joined Entergy in December 2018, his base salary was set at $305,000 based on competitive market data discussed above, as well as internal pay equity considerations.

(2)	In July 2018, Ms. Landreaux’s salary was increased when she became President and Chief Executive Officer, Entergy Arkansas and assumed the increased responsibilities of that role.

(3)	Mr. Rice’s salary was adjusted when he transitioned into Entergy Corporation’s legal department.

(4)	Mr. Riley’s salary was increased when he became Senior Vice President, Distribution Operations and Asset Management and assumed the increased responsibilities of that role.

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•	They represent objective measures that Entergy Corporation and its investors consider to be important in evaluating its financial performance;

•	They align with Entergy Corporation’s internal and external financial reporting; and

•	They provide both discipline and transparency.

•	Take into account changes in the business environment and specific challenges facing Entergy Corporation;

•	Reflect an appropriate balancing of the various risks and opportunities recognized at the time the targets are set; and

•	Are aligned with external expectations communicated to Entergy Corporation’s shareholders.

•	Any major storms that may occur during the year;

•	Certain impacts that may occur as a result of the implementation of the Tax Cuts and Jobs Act enacted in December 2017;

•	Certain unresolved litigation initiated in the late 1990s and early 2000s relating to an agreement among the Utility operating company subsidiaries that has since been terminated; and

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•	Unrealized gains and losses on equity securities different than assumed in the plan.

(1)	Payouts for performance between minimum and target achievement levels and between target and maximum levels are calculated using straight-line interpolation. There is no payout for performance below minimum.

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(1)

The target opportunities, as a percentage of salary, were determined based on the individual’s position and salary at the end of 2018. Such target opportunities for the Named Executive Officers did not change from the levels set in 2017, except for Ms. Landreaux’s and Mr. Riley’s, whose target opportunities increased due to their promotions during the year, and Mr. Rice’s whose target opportunities decreased, as he was no longer serving in an officer position at year-end.

(2)	The Named Executive Officers, who are members of the Office of the Chief Executive, may earn a maximum payout ranging from 0% to 200% of their target opportunity, not to exceed the EAM.

(3)	As a new hire, Mr. Ellis was not eligible to participate in the Annual Incentive Plan for 2018.

•	Each performance unit represents one share of Entergy Corporation’s common stock at the end of the three-year performance period, plus dividends accrued during the performance period.

•	The performance units and accrued dividends on any shares earned during the performance period are settled in shares of Entergy Corporation common stock.

•	The Personnel Committee sets payout opportunities for the program at the outset of each performance period, with payouts only occurring if the performance goals are met.

•	Payouts under this program are not made if minimum performance goals are not achieved.

•	All shares paid out under the Long-Term Performance Unit Program are required to be retained by Entergy Corporation’s officers until applicable executive stock ownership requirements are met.

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(1)	As a new hire in 2016, Mr. Bakken received a pro-rated target award opportunity for the 2016-2018 performance period.

(2)	As of December 31, 2018, Mr. Ellis was not a participant in the Long-Term Performance Unit Program.

(3)	When Ms. Landreaux became President, Entergy Arkansas, she received pro-rated target award opportunities for the 2017-2019 and 2018-2020 performance periods. As a new officer in 2018, Ms. Landreaux was not eligible to participate in the 2016-2018 performance period.

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(4)	Mr. Rice and Mr. Riley’s target opportunities were modified in connection with their change in positions in 2018.

(1)	Payouts for performance between achievement levels are calculated using straight-line interpolation, with no payouts for performance below the minimum achievement level.

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(1)	Value determined based on the closing price of Entergy Corporation’s common stock on January 17, 2019 ($86.03), the date the Personnel Committee certified the 2016-2018 performance period results.

(2)	As a new hire in 2016, Mr. Bakken received a pro-rated target award opportunity for the 2016-2018 performance period.

(3)	As a new hire in 2018, Mr. Ellis was not eligible to participate in 2016-2018 performance period.

(4)	As a new officer in 2018, Ms. Landreaux was not a participant in the 2016-2018 performance period.

(5)	Mr. Rice and Mr. Riley experienced a change in officer status in 2018, and accordingly, each received a pro-rated award opportunity for the 2016-2018 performance period.

(1)	As a new hire, Mr. Ellis was not eligible to receive stock options or restricted stock in 2018.

(2)	Stock options are awarded only to individuals who are officers at the time of grant. Ms. Landreaux was not eligible to receive stock options in 2018 because she was not an officer when the grants were made in 2018.

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(i) the payment was predicated upon the achievement of certain financial results with respect to the applicable performance period that were subsequently determined to be the subject of a material restatement other than a restatement due to changes in accounting policy; or (ii) a material miscalculation of a performance award occurs, whether or not the financial statements were restated and, in either such case, a lower payment would have been made to the executive officer based upon the restated financial results or correct calculation; or

•	in the Board of Directors’ view, the executive officer engaged in fraud that caused or partially caused the need for a restatement or caused a material miscalculation of a performance award, in each case, whether or not the financial statements were restated.

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•	all net after-tax shares paid out under the Long-Term Performance Unit Program;

•	all net after-tax shares of the restricted stock and restricted stock units received upon vesting; and

•	at least 75% of the after-tax net shares received upon the exercise of Entergy Corporation stock options.

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•	Annual review of the compensation elements and mix of elements for the following year;

•	Annual review and approval of incentive program design, goals and objectives for alignment with Entergy Corporation’s compensation and business strategies;

•	Evaluation of company and individual performance results in light of these goals and objectives;

•	Evaluation of the competitiveness of each executive officer’s total compensation package;

•	Approval of any changes to Entergy Corporation’s officers’ total compensation package, including but not limited to, base salary, annual and long-term incentive award opportunities, and retention programs;

•	Evaluation of the performance of Entergy Corporation’s Chairman and Chief Executive Officer; and

•	Reporting, at least annually, to the Board on succession planning.

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(1)	Mr. Bakken was named Executive Vice President and Chief Nuclear Officer in April 2016. Mr. Ellis was named Chief Executive Officer, Entergy New Orleans in December 2018, and Ms. Landreaux was named Chief Executive Officer, Entergy Arkansas in July 2018.

(2)	The amounts in column (c) represent the actual base salary paid to the Named Executive Officers in the applicable year.  Except as otherwise provided, the 2018 changes in base salaries noted in the Compensation Discussion and Analysis were effective in April 2018.

(3)

The amount in column (d) in 2018 and 2017 for Mr. Bakken represents the cash bonus paid to him pursuant to the Nuclear Retention Plan. See “Nuclear Retention Plan” in Compensation Discussion and Analysis. The amount in column (d) in 2016 for Mr. Bakken represents a cash sign-on bonus paid to Mr. Bakken in connection with his commencement of employment with Entergy Corporation. The amount in column (d) in 2018 for Mr. Ellis represents a cash sign-on bonus paid in connection with his commencement of employment with Entergy New Orleans.

(4)	The amounts in column (e) represent the aggregate grant date fair value of restricted stock, performance units, and restricted stock units granted under the 2015 Equity Plan, each calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures.  The grant date fair value of the restricted stock and

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(5)	The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the 2015 Equity Plan calculated in accordance with FASB ASC Topic 718.  For a discussion of the relevant assumptions used in valuing these awards, see Note 12 to the financial statements.

(6)	The amounts in column (g) represent cash payments made under the Annual Incentive Plan.

(7)

For all Named Executive Officers, the amounts in column (h) include the annual actuarial increase in the present value of these Named Executive Officers’ benefits under all pension plans established by Entergy Corporation using interest rate and mortality rate assumptions consistent with those used in Entergy Corporation’s financial statements and include amounts which the Named Executive Officers may not currently be entitled to receive because such amounts are not vested (see “2018 Pension Benefits”).  For 2018, the aggregate change in the actuarial present value was a decrease of pension benefits of $52,000 for Mr. Fisackerly, $163,000 for Mr. Marsh,$700 for Mr. May, $110,700 for Ms. Rainer, and $149,300 for Mr. West. None of the increases for any of the Named Executive Officers is attributable to above-market or preferential earnings on non-qualified deferred compensation (see “2018 Non-qualified Deferred Compensation”).

(8)

The amounts in column (i) for 2018 include (a) matching contributions by Entergy Corporation under the Savings Plan to each of the Named Executive Officers; (b) dividends paid on restricted stock when vested; (c) life insurance premiums; (d) tax gross up payments on club dues and relocation expenses; and (e) perquisites and other compensation as described further below.  The amounts are listed in the following table:

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(1)	The amounts in columns (c), (d), and (e) represent minimum, target, and maximum payment levels under the Annual Incentive Plan.  The actual amounts awarded are reported in column (g) of the Summary Compensation Table.

(2)

The amounts in columns (f), (g), and (h) represent the minimum, target, and maximum payment levels under the Long-Term Performance Unit Program.  Performance under the program is measured by Entergy Corporation’s total shareholder return relative to the total shareholder returns of the companies included in the Philadelphia Utility Index and UP&O Adjusted EPS with each performance measure weighted equally. There is no payout under the program if Entergy Corporation’s total shareholder return falls within the lowest quartile of the peer companies in the Philadelphia Utility Index and UP&O Adjusted EPS is below the minimum performance goal. Subject to the achievement of performance targets, each unit will be converted into one share of Entergy Corporation’s common stock on the last day of the performance period (December 31, 2020.)  Accrued dividends on the shares earned will also be paid in Entergy Corporation common stock.

(3)	The amounts in column (i) represent shares of restricted stock granted under the 2015 Equity Plan.  Shares of restricted stock vest one-third on each of the first through third anniversaries of the grant date, have voting rights, and accrue dividends during the vesting period.

(4)	The amounts in column (j) represent options to purchase shares of Entergy Corporation’s common stock.  The options vest one-third on each of the first through third anniversaries of the grant date and have a ten-year term from the date of grant. The options were granted under the 2015 Equity Plan.

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(5)

The amounts in column (l) are valued based on the aggregate grant date fair value of the award calculated in accordance with FASB ASC Topic 718 and, in the case of the performance units, are based on the probable outcome of the applicable performance conditions.  See Notes 4 and 5 to the 2018 Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.

(6)	Ms. Landreaux’s and Messrs. Rice’s and Riley’s awards were modified in connection with their changes in position.

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(1)	Consists of options granted under the 2015 Equity Plan that vested or will vest as follows: 1/3 of the options granted vest on each of January 25, 2019, January 25, 2020 and January 25, 2021.

(2)	Consists of options granted under the 2015 Equity Plan that vested or will vest as follows: 1/2 of the remaining unexercisable options vest on each of January 26, 2019 and January 26, 2020.

(3)	Consists of options granted under the 2015 Equity Plan that vested on January 28, 2019.

(4)

Consists of performance units granted under the 2015 Equity Plan that will vest on December 31, 2020 based on two performance measures: 1) Entergy Corporation’s total shareholder return performance over the 2018-2020 performance period and 2) UP&O Adjusted EPS with each performance measure weighted equally, as described under “What Entergy Corporation Pays and Why - Executive Compensation Elements - Variable Compensation - Long-Term Incentive Compensation - Performance Unit Program” in the Compensation Discussion and Analysis.

(5)	Consists of performance units granted under the 2015 Equity Plan that will vest on December 31, 2019 based on Entergy Corporation’s total shareholder return performance over the 2017-2019 performance period.

(6)	Consists of shares of restricted stock granted under the 2015 Equity Plan that vested or will vest as follows:  1/3 of the shares of restricted stock granted vest on each of January 25, 2019, January 25, 2020, and January 25, 2021.

(7)	Consists of shares of restricted stock granted under the 2015 Equity Plan that vested or will vest as follows:  1/2 of the shares of restricted stock granted vest on each of January 26, 2019 and January 26, 2020.

(8)	Consists of shares of restricted stock granted under the 2015 Equity Plan that vested on January 28, 2019.

(9)	Consists of restricted stock units granted under the 2015 Equity Plan which will vest on August 3, 2020.

(10)	Consists of restricted stock units granted under the 2015 Equity Plan which will vest one third on April 6, 2019, April 6, 2022, and April 6, 2025.

(1)	Represents the value of performance units for the 2016-2018 performance period (payable solely in shares based on the closing stock price of Entergy Corporation on the date of vesting) under the Performance Unit Program and the vesting of shares of restricted stock in 2018.

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(2)	Includes the May 1, 2018 cash settlement of 21,000 restricted stock units granted under the 2011 Equity Ownership Plan.

(1)	As of December 31, 2018, Mr. Brown, Mr. Denault, Mr. May, Ms. Rainer, and Mr. Riley were retirement eligible.

(2)

In 2006, Mr. Denault entered into a retention agreement granting him an additional 15 years of service and permission to retire under the non-qualified System Executive Retirement Plan in the event his employment is terminated by his Entergy employer other than for cause (as defined in the retention agreement), by Mr. Denault for good reason (as defined in the retention agreement), or on account of his death or disability. His retention agreement also provides that if he terminates employment for any other reason, he shall be entitled to the additional

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(3)	Service under the non-qualified System Executive Retirement Plan is granted from the date of hire. Qualified plan benefit service is granted from the later of the date of hire or the plan participation date.

(4)	Mr. Riley separated from Entergy Corporation and was subsequently rehired in June 1995. The Entergy Retirement Plan does not include any credit service prior to his rehire date; however, the System Executive Retirement Plan reflects a net credited service date of December 28, 1989.

(5)	Mr. Rice’s benefit accruals in the System Executive Retirement Plan ceased with his change in position. He continues to accrue benefits under the Entergy Retirement Plan and the Pension Equalization Plan.

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(1)

Effective July 1, 2014, (a) no new grants of supplemental service may be provided to participants in the Pension Equalization Plan; (b) supplemental credited service granted prior to July 1, 2014 was grandfathered; and (c) participants in Entergy Corporation’s Cash Balance Plan are not eligible to participate in the Pension Equalization Plan and instead may be eligible to participate in the Cash Balance Equalization Plan.

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(2)

Benefits accrued under the System Executive Retirement Plan, Pension Equalization Plan, and Cash Balance Equalization Plan, if any, will become fully vested if a participant is involuntarily terminated without cause or terminates his or her employment for good reason in connection with a change in control with payment generally made in a lump-sum payment as soon as reasonably practicable following the first day of the month after the termination of employment, unless delayed 6 months under Internal Revenue Code Section 409A.

(3)	The System Executive Retirement Plan was closed to new executive officers effective July 1, 2014.

(1)	Amounts in this column are not included in the Summary Compensation Table.

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*

Cash severance payments are capped at 2.99 times the sum of (a) an executive’s annual base salary plus (b) the higher of his or her actual annual incentive payment under the Annual Incentive Plan or his or her annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which termination occurs. Any cash severance payments to be paid under the Continuity Plan in excess of this cap will be forfeited by the participant.

•

Change in Control: (a) the purchase of 30% or more of either Entergy Corporation’s common stock or the combined voting power of Entergy Corporation’s voting securities; (b) the merger or consolidation of Entergy Corporation (unless its Board members constitute at least a majority of the board members of the surviving entity); (c) the liquidation, dissolution or sale of all or substantially all of Entergy Corporation’s assets; or (d) a change in the composition of Entergy Corporation’s Board such that, during any two-year period, the individuals serving at the beginning of the period no longer constitute a majority of Entergy Corporation’s Board at the end of the period.

•

Potential Change in Control: (a) Entergy Corporation or an affiliate enters into an agreement the consummation of which would constitute a Change in Control; (b) the Entergy Corporation Board adopts resolutions determining that, for purposes of the Continuity Plan, a potential Change in Control has occurred; (c) a System Company or other person or entity publicly announces an intention to take actions that would constitute a Change in Control; or (d) any person or entity becomes the beneficial owner (directly or indirectly) of Entergy Corporation’s outstanding shares of common stock constituting 20% or more of the voting power or value of the Entergy Corporation’s outstanding common stock.

•

Cause: The participant’s (a) willful and continuous failure to perform substantially his or her duties after written demand for performance; (b) engagement in conduct that is materially injurious to Entergy Corporation or any of its subsidiaries; (c) conviction or guilty or nolo contendere plea to a felony or other crime that materially and adversely affects either his or her ability to perform his or her duties or Entergy Corporation’s reputation; (d)

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•

Good Reason: The participant’s (a) nature or status of duties and responsibilities is substantially altered or reduced; (b) salary is reduced by 5% or more; (c) primary work location is relocated outside the continental United States; (d) compensation plans are discontinued without an equitable replacement; (e) benefits or number of vacation days are substantially reduced; or (f) an Entergy employer purports to terminate his employment other than in accordance with the Continuity Plan.

*	If an officer resigns after the completion of an Annual Incentive Plan, he or she may receive, at the Company’s discretion, an annual incentive payment.

**	If an officer resigns after the completion of a Long-Term Performance Unit Program performance period, he or she may receive a payout under the Long-Term Performance Unit Program based on the outcome of the performance period.

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1)	See “2018 Pension Benefits” for a description of the pension benefits Mr. Bakken, Mr. Ellis, Mr. Fisackerly, Ms. Landreaux, Mr. Marsh, Mr. Rice, and Mr. West may receive upon the occurrence of certain termination events.

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2)

As of December 31, 2018, Mr. Brown, Mr. Denault, Mr. May, Mr. Riley, and Ms. Rainer are retirement eligible and would retire rather than voluntarily resign, and in addition to the payments and benefits in the table, Mr. Brown, Mr. Denault, Mr. Riley, and Ms. Rainer also would be entitled to receive their vested pension benefits under the Entergy Retirement Plan. For a description of these benefits, see “2018 Pension Benefits.”

3)

For purposes of the table, the value of Mr. Denault’s payments was calculated by multiplying the target performance units for the 2015-2017 Performance Unit Program (33,100) by the closing price of Entergy stock on December 31, 2018 ($86.07), which would equal a payment of $2,848,917 for the forfeited performance units for each performance period. The value of Mr. Bakken’s, Mr. Brown’s, Mr. Marsh’s, and Mr. West’s payments was calculated by multiplying the target performance units for the 2015-2017 Performance Unit Program (6,550) by the closing price of Entergy stock on December 31, 2018 ($86.07), which would equal a payment of $563,759 for the forfeited performance units for each performance period. The value of Mr. May’s and Mr. Riley’s payment was calculated by multiplying the target performance units for the 2015-2017 Performance Unit Program (2,050) by the closing price of Entergy stock on December 31, 2018 ($86.07), which would equal a payment of $176,444 for the forfeited performance units for each performance period. The value of the payments for the other Named Executives Officers, other than Mr. Ellis and Mr. Rice, was calculated by multiplying the target performance units for the 2015-2017 Performance Unit Program (1,450) by the closing price of Entergy stock on December 31, 2018 ($86.07), which would equal a payment of $124,802 for the forfeited performance units for each performance period. At December 31, 2018, Mr. Ellis was not eligible to participate in the long-term performance unit program, and Mr. Rice was not a participant in the System Executive Continuity Plan.

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4)

For purposes of the table, the value of Mr. Denault’s retention payment was calculated by taking an average of the target performance units from the 2014-2016 Performance Unit Program (40,000) and from the 2015-2017 Performance Unit Program (33,100). This average number of units (36,550) multiplied by the closing price of Entergy stock on December 31, 2018 ($86.07) would equal a payment of $3,145,859.

5)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Bakken, Mr. Marsh, and Mr. West would be eligible to receive Entergy-subsidized COBRA benefits for 18 months and Mr. Ellis, Mr. Fisackerly, and Ms. Landreaux would be eligible to receive Entergy-subsidized COBRA benefits for 12 months.

6)	Upon retirement, Mr. Brown, Mr. Denault, Mr. May, Mr. Riley, and Ms. Rainer would be eligible for retiree medical and dental benefits, the same as all other retirees.

7)

Mr. Bakken’s 30,000 restricted stock units vest 1/3rd on each of April 6, 2019, April 6, 2022, and April 6, 2025. Pursuant to his restricted stock unit agreement, if Mr. Bakken’s employment terminates due to total disability or death or, prior to April 6, 2019, Mr. Bakken’s employment is terminated by his Entergy employer other than for cause, he will vest in and be paid the 10,000 restricted stock units that otherwise would have vested had he satisfied the vesting conditions of the restricted stock unit agreement through the next vesting date to occur following his date of total disability, death or termination other than for cause prior to April 6, 2019 subject, in the case of a termination without cause, to Mr. Bakken timely executing and not revoking a release of claims against Entergy and its affiliates. In the event of a change in control, the unvested restricted stock units will fully vest upon Mr. Bakken’s Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. Bakken is subject to certain restrictions on his ability to compete with Entergy and its affiliates or solicit its employees or customers during and for 12 months after his employment with his Entergy employer. In addition, the restricted stock unit agreement limits Mr. Bakken’s ability to disparage Entergy and its affiliates. In the event of a breach of these restrictions, other than following certain constructive terminations of his employment, Mr. Bakken will forfeit any restricted stock units that are not yet vested and paid, and must repay to Entergy any shares of Entergy stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares.

8)

Mr. Marsh’s 21,100 restricted stock units vest 100% in 2020. Pursuant to his restricted stock unit agreement, any unvested restricted stock units will vest immediately in the event of his termination of employment due to Mr. Marsh’s total disability or death or a Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. Marsh is subject to certain restrictions on his ability to compete with Entergy and its affiliates during and for 12 months after his employment with Entergy, or to solicit its employees or customers during and for 24 months after his employment with Entergy. In addition, the restricted stock unit agreement limits Mr. Marsh’s ability to disparage Entergy and its affiliates. In the event of a breach of these restrictions, Mr. Marsh will forfeit any restricted stock units that are not yet vested and paid, and must repay to Entergy any shares of Entergy stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares.

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•	The median of the annual total compensation of all of Entergy Arkansas’ employees, other than Entergy Arkansas’ Chief Executive Officer, was $113,820.

•	The combined annual total compensation of Entergy Arkansas’ previous Chief Executive Officer, Mr. Riley, and its current Chief Executive Officer, Ms. Landreaux, as reported in the Total column of the 2018 Summary Compensation Table (pro-rated for the time each served as Entergy Arkansas’ Chief Executive Officer in 2018) was $990,731.

•	Based on this information, the ratio of the annual total compensation of Entergy Arkansas’ Chief Executive Officer to the median of the annual total compensation of all employees is estimated to be 9:1.

•	The median of the annual total compensation of all of Entergy Louisiana’s employees, other than Mr. May, was $108,115.

•	Mr. May’s annual total compensation, as reported in the Total column of the 2018 Summary Compensation Table, was $1,031,421.

•	Based on this information, the ratio of the annual total compensation of Mr. May to the median of the annual total compensation of all employees is estimated to be 10:1.

•	The median of the annual total compensation of all of Entergy Mississippi’s employees, other than Mr. Fisackerly, was $113,046.

•	Mr. Fisackerly’s annual total compensation, as reported in the Total column of the 2018 Summary Compensation Table, was $815,654.

•	Based on this information, the ratio of the annual total compensation of Mr. Fisackerly to the median of the annual total compensation of all employees is estimated to be 7:1.

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•	The median of the annual total compensation of all of Entergy New Orleans’ employees, other than Entergy New Orleans’ Chief Executive Officer, was $93,562.

•	The combined annual total compensation of Entergy New Orleans’ previous Chief Executive Officers, Mr. Rice and Mr. West, and its current Chief Executive Officer, Mr. Ellis, as reported in the Total column of the 2018 Summary Compensation Table (pro-rated for the time each served as Entergy New Orleans’ Chief Executive Officer in 2018) was $1,382,688.

•	Based on this information, the ratio of the annual total compensation of Entergy New Orleans’ Chief Executive Officer to the median of the annual total compensation of all employees is estimated to be 15:1.

•	The median of the annual total compensation of all of Entergy Texas’ employees, other than Ms. Rainer, was $104,839.

•	Ms. Rainer’s annual total compensation, as reported in the Total column of the 2018 Summary Compensation Table, was $774,225.

•	Based on this information, the ratio of the annual total compensation of Ms. Rainer to the median of the annual total compensation of all employees is estimated to be 7:1.

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(1)	The number of shares of Entergy Corporation common stock owned by each individual and by all non-employee directors and executive officers as a group does not exceed one percent of the outstanding shares of Entergy Corporation common stock.

(2)

For the non-employee directors, the balances include phantom units that are issued under the Service Recognition Program. All non-employee directors are credited with phantom units for each year of service on the Entergy Corporation Board. These phantom units do not have voting rights, accrue dividends, and will be settled in shares of Entergy Corporation common stock following the non-employee director’s separation from the Board.

(3)

Represents the balances of phantom units each executive holds under the defined contribution restoration plan and the deferral provisions of the Equity Ownership Plan.  These units will be paid out in either Entergy Corporation Common Stock or cash equivalent to the value of one share of Entergy Corporation common stock per unit on the date of payout, including accrued dividends.  The deferral period is determined by the individual and is at least two years from the award of the bonus.  Messrs. Donald and Frederickson have deferred receipt of some of their quarterly stock grants.  The deferred shares will be settled in cash in an amount equal to the market value of Entergy Corporation common stock at the end of the deferral period.

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(1)

Includes the 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, and the 2015 Equity Plan.  The 2007 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 12, 2006, and only applied to awards granted between January 1, 2007 and May 5, 2011. The 2011 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 6, 2011, and only applied to awards granted between May 6, 2011 and May 7, 2015.  The 2015 Equity Plan was approved by Entergy Corporation shareholders on May 8, 2015, and 6,900,000 shares of Entergy Corporation common stock can be issued from the 2015 Equity Plan, with no more than 1,500,000 shares available for incentive stock option grants.  The 2015 Equity Plan applies to awards granted on or after May 8, 2015. The 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, and the 2015 Equity Plan (collectively, the “Plans”) are administered by the Personnel Committee of the Board of Directors (other than with respect to awards granted to non-employee directors, which awards are administered by the entire Board of Directors).  Eligibility under the Plans is limited to the non-employee directors and to the officers and employees of an Entergy employer and any corporation 80% or more of whose stock (based on voting power) or value is owned, directly or indirectly, by Entergy Corporation.  The Plans provide for the issuance of stock options, restricted stock, equity awards (units whose value is related to the value of shares of the common stock but do not represent actual shares of common stock), performance awards (performance shares or units valued by reference to shares of common stock or performance units valued by reference to financial measures or property other than common stock), restricted stock unit awards, and other stock-based awards.

(2)	The weighted average exercise price reported in the column does not include outstanding performance awards.

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•	Whether the proposed transaction is on terms that are at least as favorable to Entergy Corporation as those achievable with an unaffiliated third party;

•	Size of the transaction and amount of consideration;

•	Nature of the interest;

•	Whether the transaction involves a conflict of interest;

•	Whether the transaction involves services available from unaffiliated third parties; and

•	Any other factors that the Corporate Governance Committee or subcommittee deems relevant.

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(a)	Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, and other attestation services.

(b)	100% of fees paid in 2018 and 2017 were pre-approved by the Entergy Corporation Audit Committee.

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1.	The independent auditor will provide the Audit Committee, for approval, an annual engagement letter outlining the scope of services proposed to be performed during the fiscal year, including audit services and other permissible non-audit services (e.g. audit-related services, tax services, and all other services).

2.

For other permissible services not included in the engagement letter, Entergy management will submit a description of the proposed service, including a budget estimate, to the Audit Committee for pre-approval.  Management and the independent auditor must agree that the requested service is consistent with the SEC’s rules on auditor independence prior to submission to the Audit Committee.  The Audit Committee, at its discretion, will pre-approve permissible services and has established the following additional guidelines for permissible non-audit services provided by the independent auditor:

•	Aggregate non-audit service fees are targeted at fifty percent or less of the approved audit service fee.

•	All other services should only be provided by the independent auditor if it is a highly qualified provider of that service or if the Audit Committee pre-approves the independent audit firm to provide the service.

3.	The Audit Committee will be informed quarterly as to the status of pre-approved services actually provided by the independent auditor.

4.	To ensure prompt handling of unexpected matters, the Audit Committee delegates to the Audit Committee Chair or its designee the authority to approve permissible services and fees.  The Audit Committee Chair or designee will report action taken to the Audit Committee at the next scheduled Audit Committee meeting.

5.	The Vice President and General Auditor will be responsible for tracking all independent auditor fees and will report quarterly to the Audit Committee.

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