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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 renewals or 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 the commitment of substantial human and capital resources required for the 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;

•	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;

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•	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, heat, and other regulated air and water emissions, requirements for waste management and disposal and for the remediation of contaminated sites, wetlands protection and permitting, and changes in costs of compliance with these 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, or energy policies;

•	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 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 Northeast 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, including the potential impact to credit ratings, which may affect Entergy’s ability to borrow funds or increase the cost of borrowing in the future;

•	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;

•	changes in technology, including with respect to new, developing, or alternative sources of generation such as distributed energy and energy storage, energy efficiency, demand side management and other measures that reduce load;

•	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;

•	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;

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•	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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•	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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an increase in base rates at Entergy Arkansas, as approved by the APSC. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. The increase included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. A significant portion of the increase was related to the purchase of Power Block 2 of the Union Power Station;

•	an increase in the purchased power and capacity acquisition cost recovery rider for Entergy New Orleans, as approved by the City Council, effective with the first billing cycle of March 2016, primarily related to the purchase of Power Block 1 of the Union Power Station;

•	an increase in formula rate plan revenues for Entergy Louisiana, implemented with the first billing cycle of March 2016, to collect the estimated first-year revenue requirement related to the purchase of Power Blocks 3 and 4 of the Union Power Station; and

•	an increase in revenues at Entergy Mississippi, as approved by the MPSC, effective with the first billing cycle of July 2016, and an increase in revenues collected through the storm damage rider.

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•	lower realized wholesale energy prices and lower capacity prices, the amortization of the Palisades below-market PPA, and Vermont Yankee capacity revenue. The effect of the amortization of the Palisades below-market PPA and Vermont Yankee capacity revenue on the net revenue variance from 2015 to 2016 is minimal;

•	the sale of the Rhode Island State Energy Center in December 2015. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale; and

•	lower volume in the Entergy Wholesale Commodities nuclear fleet resulting from more refueling outage days in 2016 as compared to 2015 and larger exercise of resupply options in 2016 as compared to 2015. See “Nuclear Matters - Indian Point” below for discussion of the extended Indian Point 2 outage in the second quarter 2016.

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an increase resulting from the reimbursement agreement with Exelon pursuant to which Exelon reimbursed Entergy 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 are offset in nuclear fuel expenses and other operation and maintenance expenses and have no material effect on net income. See “Entergy Wholesale Commodities Exit from the Merchant Power Business - Sale of FitzPatrick” below for further discussion of the reimbursement agreement; and

•	a decrease in nuclear fuel expenses primarily related to the impairments of the FitzPatrick, Pilgrim, and Palisades plants and related assets. See Note 14 to the financial statements for discussion of the impairments.

(a)	The reduction in owned capacity is due to Entergy’s sale of its 50% membership interest in Top Deer Wind Ventures, LLC in November 2016. See Note 14 to the financial statements for discussion of the sale.

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a decrease of $78 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit 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 include 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;

•	the deferral in 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

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•	a decrease of $13 million in energy efficiency costs, including the effects of true-ups to energy efficiency filings for fixed costs to be collected from customers and incentives recognized as a result of participation in energy efficiency programs.

•	the $45 million ($28 million net-of-tax) write-off in 2015 to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery; and

•	the $23.5 million ($15.3 million net-of-tax) write-off in 2015 of the regulatory asset associated with the Spindletop gas storage facility as a result of the approval of the System Agreement termination settlement agreement.

•	an increase of $60 million in severance and retention costs related to the planned shutdown or sale of the Pilgrim and FitzPatrick plants. See “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;

•	$41 million associated with preparing to refuel FitzPatrick in January 2017. Exelon reimbursed Entergy for these costs in accordance with the reimbursement agreement discussed in “Entergy Wholesale Commodities Exit From the Merchant Power Business - Sale of FitzPatrick” below; and

•	an increase of $26 million in costs related to Pilgrim’s response to a planned NRC enhanced inspection as a result of the NRC placing Pilgrim in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix in September 2015. See Note 8 to the financial statements for further discussion of the NRC’s decision and Pilgrim’s response.

•	the effects of recording the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $60 million in 2016 compared to the reimbursement of approximately $2 million in 2015 of spent nuclear fuel storage costs

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•	a decrease of $32 million as a result of the sale of the Rhode Island State Energy Center in December 2015. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale; and

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a decrease of $21 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.

•	decreases in depreciable asset balances as a result of the impairments of the FitzPatrick, Pilgrim, and Palisades plants. See Note 14 to the financial statements for further discussion of the impairments;

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the effects of recording the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $15 million in 2016 compared to the reimbursement of approximately $4 million in 2015 of spent nuclear fuel storage costs previously recorded as depreciation. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and

•	a decrease in depreciable asset balances as a result of the sale of the Rhode Island State Energy Center in December 2015. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale.

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•	determining the period over which certain income tax benefits are provided to customers;

•	accelerating depreciation or amortization for certain assets or asset classes; and

•	increasing or modifying capital investments.

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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, 2017 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 permits 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, 2017, letters of credit posted with MISO covered financial transmission right exposure of $0.2 million for Entergy Arkansas, $0.1 million for Entergy Mississippi, and $0.05 million for Entergy Texas. See Note 15 to the financial statements for discussion of financial transmission rights.

(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.

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•	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.

•	Investments, including the St. Charles Power Station, Lake Charles Power Station, New Orleans Power Station, and Montgomery County Power Station, each discussed below, and potential construction of additional generation.

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

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•	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 ($781 million as of December 31, 2017);

•	securities issuances;

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

•	sales of assets.

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•	lower Entergy Wholesale Commodities net revenue, excluding the effect of 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;

•	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. See Note 3 to the financial statements for a discussion of the income tax audit;

•	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

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•	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.

•	a decrease due to the timing of recovery of fuel and purchased power costs in 2016 as compared to 2015. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;

•	lower Entergy Wholesale Commodities net revenue in 2016 as compared to 2015, as discussed previously; and

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an increase of $83 million in interest paid in 2016 as compared to 2015 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 and an increase in interest expense primarily due to 2016 net debt issuances by various Utility operating companies, partially offset by a decrease in interest paid in 2016 on the Grand Gulf sale-leaseback obligation. 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 for details of the Grand Gulf lease obligation. See Note 5 to the financial statements for a discussion of long-term debt.

•	higher Utility net revenues in 2016 as compared to 2015, as discussed above;

•	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;

•	a decrease of $46 million in spending on nuclear refueling outages in 2016 as compared to 2015; and

•	a decrease of $19 million in spending related to the shutdown of Vermont Yankee, which ceased power production in December 2014.

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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;

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•	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.

•	the purchase of the Union Power Station for approximately $949 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;

•	proceeds of approximately $490 million from the sale in December 2015 of Rhode Island State Energy Center. See Note 14 to the financial statements for further discussion of the sale; and

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an increase of $279 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 $114 million in transmission construction expenditures primarily due to an overall higher scope of work performed on transmission projects in 2016 as compared to 2015, an increase of $106 million in nuclear construction expenditures primarily due to a higher scope of work on various nuclear projects in 2016 as compared to 2015, an increase of $95 million in fossil-fueled generation construction expenditures primarily due to spending on the St. Charles Power Station project in 2016, an increase of $79 million in distribution construction expenditures primarily due to a higher scope of non-storm related work performed in 2016 as compared to the same period in 2015 and higher storm restoration spending in 2016, and an increase of $65 million in information technology construction expenditures due to various information technology projects and upgrades in 2016. The increase was partially offset by a decrease of $148 million in spending related to compliance with NRC post-Fukushima requirements in the Utility and Entergy Wholesale Commodities businesses.

•	a decrease of $179 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;

•	an increase of $151 million in proceeds received from the DOE in 2016 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;

•	a $71 million NYPA value sharing payment in 2015. See Note 14 to the financial statements for further discussion of Entergy’s NYPA value sharing agreements; and

•	the deposit of $64 million into Entergy New Orleans’s storm reserve escrow accounts in 2015.

•	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;

•	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%

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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.

•	long-term debt activity providing approximately $1,489 million of cash in 2016 compared to providing $41 million of cash in 2015.  Included in the long-term debt activity is net repayments of borrowings of $135 million in 2016 compared to net borrowings of $140 million in 2015 on the Entergy Corporation long-term credit facility;

•	the issuance of $110 million of preferred stock in 2015. See Note 6 to the financial statements for further discussion;

•	$100 million of common stock repurchased in 2015, as discussed above;

•	a net increase of $41 million in 2016 in short-term borrowings by the nuclear fuel company variable interest entities; and

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a decrease of $21 million resulting from higher repurchase/redemptions of preferred stock. In September 2015, Entergy Louisiana redeemed its $100 million 6.95% Series preferred membership interests, of which $16 million was owned by Entergy Louisiana Holdings, an Entergy subsidiary, and Entergy Gulf States Louisiana repurchased its $10 million Series A 8.25% preferred membership interests as part of a multi-step process to effectuate the Entergy Louisiana and Entergy Gulf States Louisiana business combination.  See Note 2 to the financial statements for a discussion of the combination. 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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•	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 that may require regulatory approval or approval of transmission rights. 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 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)

Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the other party as specified in the contract, a portion of which may be capped through the use of risk management products. This also includes option transactions that may expire without being exercised.

(d)	Transactions for the purchase of energy, generally to offset a Firm LD transaction.

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

(f)	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,

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

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

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

(j)	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, as well as assumptions regarding the probability that the plant’s license will be renewed for those plants that have not yet received operating license renewal. Second, an assumption must be made 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 regarding either the probability of license renewal, the period of continued operation, or the use of a SAFSTOR period can change the present value of the asset retirement obligation.

•

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 3% 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.

•

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 occur, however, and affect current cost estimates. In addition, if regulations regarding nuclear decommissioning were to change, this could significantly affect cost estimates.

•

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.

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•	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 $67.1 million in 2017 and $66.9 million in 2016 of fuel and purchased power 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.

(b)	Includes $168.1 million in each year for Entergy Louisiana and $4.1 million in each year 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 would redeem its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million, which includes call premiums, plus accumulated and unpaid dividends, if any.

•	Entergy Arkansas would convert from an Arkansas corporation to a Texas corporation.

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Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas will allocate 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 will assume substantially all of the liabilities of Entergy Arkansas, in a transaction regarded as a merger under the TXBOC. Entergy Arkansas will remain in existence and hold the membership interests in Entergy Arkansas Power.

•	Entergy Arkansas will contribute 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 will be a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

•	Entergy Arkansas will change its name to Entergy Utility Property, Inc., and Entergy Arkansas Power will then change its name to Entergy Arkansas, 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 equalizes 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 will 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 will not reflect the actual Vidalia price for the year but is 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 and the first reallocation payments were made in 2007.

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(a)	See “Other Tax Matters - Tax Cuts and Jobs Act” below for discussion of the tax legislation enactment.

(b)	See “Other Tax Matters - Entergy Wholesale Commodities Restructuring” below for discussion of the Entergy Wholesale Commodities restructuring.

(c)	See “Income Tax Audits - 2008-2009 IRS Audit” below for discussion of the most significant items for 2015.

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

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(a)	See “Other Tax Matters - Tax Cuts and Jobs Act” below for discussion of the tax legislation enactment.

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

(c)	See “Income Tax Audits - 2008-2009 IRS Audit” below for discussion of the most significant items for Entergy Louisiana and System Energy.

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(a)	The primary reduction for 2015 is related to the nuclear decommissioning costs treatment discussed in “Income Tax Audits - 2008-2009 IRS Audit” below.

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

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(a)	The primary additions for Entergy Louisiana in 2016 and for Entergy New Orleans in 2017 are related to the mark-to-market treatment discussed in “Other Tax Matters - Tax Accounting Methods” below.

(b)	The primary addition for Entergy Louisiana and System Energy is related to the nuclear decommissioning costs 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. Entergy Louisiana also accrued a regulatory liability of $16.1 million ($9.9 million net-of-tax) in accordance with the terms of Entergy Louisiana’s previous settlement agreement approved by the LPSC regarding 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, 2017 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 permits 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, 2017, letters of credit posted with MISO covered financial transmission right exposure of $0.2 million for Entergy Arkansas, $0.1 million for Entergy Mississippi, and $0.05 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

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(b)	Includes borrowings on the credit facility and commercial paper. Commercial paper is classified as a current liability and the amount outstanding for Entergy Arkansas VIE as of December 31, 2017 was $50 million.

(c)	Includes borrowings on the credit facility and commercial paper. Commercial paper is classified as a current liability and the amount outstanding for Entergy Louisiana Waterford VIE as of December 31, 2017 was $43.5 million.

(d)	Includes borrowings on the credit facility and commercial paper. Commercial paper is classified as a current liability and the amount outstanding for System Energy VIE as of December 31, 2017 was $17.8 million.

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(a)	Consists of pollution control revenue bonds and environmental revenue bonds, some of which are secured by collateral mortgage 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)	See Note 10 to the financial statements for further discussion of the Waterford 3 lease obligation and Entergy Louisiana’s acquisition of the equity participant’s beneficial interest in the Waterford 3 leased assets and for further discussion of the Grand Gulf lease obligation.

(d)	This note did not have a stated interest rate, but had an implicit interest rate of 7.458%.

(e)	The fair value excludes lease obligations of $34 million at System Energy and long-term DOE obligations of $183 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.

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

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•	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 $183 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)	The interest rate as of December 31, 2016 was 8.09%. See Note 10 to the financial statements for further discussion of Entergy Louisiana’s acquisition of the equity participant’s beneficial interest in the Waterford 3 leased assets in March 2016.

(f)	This note did not have a stated interest rate, but had an implicit interest rate of 7.458%.

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(a)	Dollar amount outstanding is net of $2,575 thousand of preferred stock issuance costs.

(b)	Dollar amount outstanding is net of $602 thousand of preferred stock issuance costs.

(c)	Dollar amount outstanding is net of $751 thousand of preferred stock issuance costs.

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(a)	In November 2017, Entergy New Orleans redeemed its $6 million of 4.36% Series, $7.8 million of 4.75% Series, and $6 million of 5.56% Series of preferred membership interests as part of a multi-step 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,

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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 $127.3 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.146 billion).  This retrospective premium is payable at a rate currently set at approximately $19 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 $13 billion in coverage.  The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $100 billion in coverage in excess of existing coverage for a terrorist event. Under current law, the Terrorism Risk Insurance Act extends through 2020.

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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)	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.

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

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

(d)	See “Entergy Wholesale Commodities” in “Nuclear Plant Decommissioning” below for additional discussion regarding the decommissioning agreements with NYPA and the associated asset retirement obligations.

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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.

(h)

103-12 investment entities hold investments in accordance with stated objectives. The investment strategy of the investment entities is to capture the growth potential of international equity markets by replicating the performance of a specified index. 103-12 investment entities estimate fair value using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table.

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(a)	The fair value of Pilgrim was based on the probability weighting of two potential scenarios.

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

(c)	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.

(d)	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 $1 million posted and $4 million held as of December 31, 2017 and $2 million posted as of December 31, 2016. Also excludes $34 million in letters of credit held as of December 31, 2017.

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(a)	Before taxes of $38 million, $103 million, and ($85) million, for the years ended December 31, 2017, 2016, and 2015, respectively

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(a)	Due to regulatory treatment, the natural gas swaps 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 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 (loss) recognized in accumulated other comprehensive income from electricity swaps and options de-designated as hedged items.

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(a)

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. As of December 31, 2016, letters of credit posted with MISO covered financial transmission rights exposure of $0.3 million for Entergy Arkansas and $0.1 million for Entergy Mississippi.

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(a)	Due to regulatory treatment, the natural gas swaps 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 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 hedge contracts.  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 $0.9 million, $0.2 million, and $3 million for the years ended December 31, 2017, 2016, and 2015, 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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•	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 2018 forward test year.

(b)	Based on December 31, 2016 test year.

(c)	Based on September 30, 2016 test year.

(d)	Based on 2017 forward test year.

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

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

(g)	Based on March 31, 2013 adjusted test year and excludes approximately $331 million for rate base being recovered through the distribution cost recovery rider and the transmission cost recovery rider

(h)	Based on calculation as of December 31, 2017.

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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;

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•	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;

•	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; and

•	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.

•	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;

•	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 has approved the project, and the expected commercial operation date is in June 2019;

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•	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 has 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 has received regulatory approval and will begin in June 2018; and

•	In June 2017, Entergy Arkansas and Chicot Solar, LLC executed 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. Entergy Arkansas filed for regulatory approval in October 2017.

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(a)	Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2017 and is expected to provide about less than1% of its generation in 2018.

(b)	Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2017 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2018.

(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. MISO purchases cannot be projected for 2018.

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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.

•

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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(a)	In October 2015, Entergy determined that it would close the Pilgrim plant no later than June 1, 2019, as discussed above.

(b)

In January 2017, Entergy announced that it reached a settlement with New York State to shut down Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021, and resolve all New York State-initiated legal challenges to Indian Point’s operating license renewal. See below for discussion of Indian Point 2 and Indian Point 3 entering their “period of extended operation” after expiration of the plants’ initial license terms under “timely renewal.”

(c)	On December 29, 2014, the Vermont Yankee plant ceased power production. In November 2016, Entergy entered into an agreement to sell 100% of the membership interest in Entergy Nuclear Vermont Yankee, to NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant.

(d)

In December 2016, Entergy announced that it had reached an agreement with Consumers Energy to terminate the existing PPA for the Palisades plant in 2018. Separately, and assuming regulatory approvals are obtained for the PPA termination agreement, Entergy intended to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. In September 2017, as a result of the Michigan Public Service Commission’s order, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022.

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(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.

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•	oversee utility service;

•	set retail rates;

•	determine reasonable and adequate service;

•	control leasing;

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

•	set rates of depreciation;

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

•	regulate the issuance and sale of certain securities.

•	utility service;

•	retail rates and charges;

•	certification of generating facilities and certain transmission projects;

•	certification of power or capacity purchase contracts;

•	audit of the fuel adjustment charge, environmental adjustment charge, and avoided cost payment to Qualifying Facilities;

•	integrated resource planning;

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

•	depreciation and other matters.

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•	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;

•	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 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;

•

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 mandatory federal carbon dioxide emission 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;

•	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;

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•	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 to them, or Entergy or its subsidiaries otherwise may be unable to achieve anticipated regulatory treatment of any such transaction or acquired business or assets; and

•	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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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 the prior year; and

•	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

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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 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; and

•

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.

•

a decrease of $21.6 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;

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the deferral 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; and

•	a decrease of $7.2 million in energy efficiency costs, including the effects of true-ups to the energy efficiency filings for fixed costs to be collected from customers and incentives recognized as a result of participation in energy efficiency programs.

•	$5.1 million in estimated interest expense recorded in connection with the FERC orders issued in April 2016 in the opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding; and

•	the net issuance of $230 million of first mortgage bonds in 2016. See Note 5 to the financial statements for further discussion of long-term debt.

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income tax refunds of $135.7 million in 2016 compared to income tax payments of $103.3 million in 2015. Entergy Arkansas had income tax refunds in 2016 and income tax payments in 2015 in accordance with an intercompany income tax allocation agreement. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit whereas the income tax payments in 2015 resulted primarily from final settlement of amounts outstanding associated with the 2006-2007 IRS audit as well as adjustments associated with the settlement of the 2008-2009 IRS audit. See Note 3 to the financial statements for further discussion of the income tax audits;

•	the timing of payments to vendors; and

•	an increase in net revenue.

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•	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;

•	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; and

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

•	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 resulting from Entergy Arkansas’s routine evaluation of its ability to pay dividends. 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.

•	the net issuance of $189.1 million of long-term debt in 2016 compared to the net retirement of $13.2 million of long-term debt in 2015;

•	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; and

•	net repayments of $11.7 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2016 compared to net repayments of $36.3 million in 2015.

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

•	construction and other capital investments;

•	debt and preferred stock 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)	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 stock issuances; and

•	bank financing under new or existing facilities.

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•	Entergy Arkansas would redeem its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million, which includes call premiums, plus accumulated and unpaid dividends, if any.

•	Entergy Arkansas would convert from an Arkansas corporation to a Texas corporation.

•

Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas will allocate 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 will assume substantially all of the liabilities of Entergy Arkansas, in a transaction regarded as a merger under the TXBOC. Entergy Arkansas will remain in existence and hold the membership interests in Entergy Arkansas Power.

•	Entergy Arkansas will contribute 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 will be a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.

•	Entergy Arkansas will change its name to Entergy Utility Property, Inc., and Entergy Arkansas Power will then change its name to Entergy Arkansas, LLC.

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•	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;

•	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.

•	the $45 million write-off recorded in 2015 to recognize the portion of the assets associated with the Waterford 3 replacement steam generator project no longer probable of recovery. See Note 2 to the financial statements for further discussion of the prudence review proceeding; and

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a decrease of $35 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement costs as a result of higher discount rates used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.

•	the issuance in March 2016 of $425 million of 3.25% Series collateral trust mortgage bonds;

•	the issuance in March 2016 of $200 million of 4.95% Series first mortgage bonds; and

•	the issuance in October 2016 of $400 million of 2.40% Series collateral trust mortgage bonds.

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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 audits;

•	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 $67.5 million in income tax payments in 2016. Entergy Louisiana had income tax payments in 2016 and 2015 in accordance with intercompany income tax allocation agreements. 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. The 2015 income tax payments resulted primarily from adjustments

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•	an increase of $80.7 million in interest paid resulting from an increase in interest expense, including a 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 the purchase of a beneficial interest in the Waterford 3 leased assets;

•	the timing of collections from customers and payments to vendors; and

•	a decrease due to the timing of recovery of fuel and purchased power costs in 2016.

•	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;

•	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.

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•	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;

•	an increase of $130.7 million in fossil-fueled generation construction expenditures primarily due to spending on the St. Charles Power Station project in 2016;

•	cash proceeds of $59.6 million received in 2015 from the transfer of Algiers assets to Entergy New Orleans in September 2015. See “State and Local Rate Regulation and Fuel-Cost Recovery - Retail Rates - Electric - Filings with the City Council” below for further discussion of the transfer;

•	an increase of $52 million in transmission construction expenditures due to a higher scope of work performed in 2016; and

•	an increase of $20.5 million due to various information technology projects and upgrades in 2016.

•	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;

•	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; and

•	a decrease of $16.9 million in nuclear construction expenditures primarily due to decreased spending on compliance with NRC post-Fukushima requirements.

•	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.

•	the net issuance of $961.2 million of long-term debt in 2016 compared to the net retirement of $103.4 million of long-term debt in 2015;

•	the redemption in September 2015 of $100 million of 6.95% Series and $10 million of 8.25% Series preferred membership interests in connection with the Entergy Louisiana and Entergy Gulf States Louisiana business combination;

•	net repayments of borrowings of $56.6 million on the nuclear fuel company variable interest entity’s credit facility in 2016 compared to net borrowings of $14.3 million in 2015; and

•	an increase of $59.5 million in common equity distributions in 2016. Equity distributions were lower in 2015 in anticipation of the purchase of Power Blocks 3 and 4 of the Union Power Station.

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(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; 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

•	long-term borrowings by its nuclear fuel company variable interest entities.

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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 on storm cost recovery.

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•	a decrease of $9.4 million in fossil-fueled generation expenses primarily due to a lower scope of work done during plant outages in 2016 as compared to the same period in 2015;

•

a decrease of $6.1 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;

•	a decrease of $2 million due to lower write-offs of uncollectible customer accounts in 2016;

•	a decrease of $2 million in energy efficiency costs; and

•	several individually insignificant items.

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•	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.

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•	an increase of $72.4 million in transmission construction expenditures primarily due to a higher scope of work performed in 2016 as compared to 2015;

•	insurance proceeds of $12.9 million received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013;

•	an increase of $11.4 million in distribution construction expenditures primarily due to a higher scope of non-storm related work performed in 2016 as compared to 2015; and

•	an increase of $10.1 million due to various information technology projects and upgrades.

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•	construction and other capital investments;

•	debt and preferred stock maturities or retirements;

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

•	dividend 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 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 stock issuances; 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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•	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.

•	a decrease of $6.1 million due to lower transmission equalization expenses, as allocated under the System Agreement as compared to the same period in 2015 primarily due to the termination of the System Agreement. See Note 2 to the financial statements for further discussion on the System Agreement termination;

•	a decrease of $4.4 million due to the cessation of storm damage provisions in August 2015. See Note 2 to the financial statements for further discussion of storm cost recovery; and

•

a decrease of $3.1 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.

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•	an increase of $5.7 million in fossil-fueled generation expenses primarily due to an increase as a result of the purchase of Power Block 1 of the Union Power Station in March 2016, partially offset by a decrease as a result of the deactivation of Michoud Units 2 and 3 effective May 2016.  See Note 14 to the financial statements for discussion of the Union Power Station purchase;

•	an increase of $3.1 million in loss provisions; and

•	an increase of $2.8 million due to higher write-offs of uncollectible customer accounts in 2016 as compared to 2015.

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•	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 above.

•	the purchase of Entergy Louisiana’s Algiers assets in September 2015. The cash portion of the purchase is reflected as a repayment of a long-term payable due to Entergy Louisiana in the cash flow statement. See Note 2 to the financial statements and “Algiers Asset Transfer” below for further discussion of the Algiers asset transfer and accounting for the transaction;

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

•	the issuance of $85 million of 4% Series first mortgage bonds in May 2016. Entergy New Orleans used the proceeds to pay, prior to maturity, its $33.271 million of 5.6% Series first mortgage bonds due September 2024 and to pay, prior to maturity, its $37.772 million of 5.65% Series first mortgage bonds due September 2029.

•	the issuance of $98.7 million of storm costs recovery bonds in July 2015;

•	a $47.8 million capital contribution received from Entergy Corporation in 2016 as compared to an $87.5 million capital contribution received from Entergy Corporation in 2015, both in anticipation of Entergy New Orleans’s purchase of Power Block 1 of the Union Power Station; and

•	an increase of $11.5 million in common equity distributions in 2016. Common equity distributions were lower in 2015 in anticipation of the purchase of Power Block 1 of the Union Power Station.

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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; and

•	bank financing under new or existing facilities.

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•	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.

•	a decrease of $11.2 million in fossil-fueled generation expenses primarily due to an overall lower scope of work performed in 2016 as compared to 2015;

•	a decrease of $7 million in transmission expenses primarily due to lower transmission equalization expenses, as allocated under the System Agreement, as compared to the same period in 2015 as a result of Entergy Mississippi’s exit from the System Agreement in November 2015 and Entergy Texas’s exit from the System Agreement in August 2016;

•

a decrease of $5.7 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;

•	the write-off in the third quarter 2015 of $4.3 million of rate case expenses and acquisition costs related to the proposed Union Power Station acquisition upon Entergy Texas’s withdrawal of its 2015 rate case and dismissal of its certificate of convenience and necessity filing; and

•	a decrease of $4.2 million in energy efficiency costs.

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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 2.55% Series first mortgage bonds in December 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; and

•	bank financing under new or existing facilities.

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•	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.

•

a decrease of $90.5 million in income tax refunds in 2016. System Energy received income tax refunds in 2016 and 2015 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2016 and 2015 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; and

•	an increase in spending of $35.1 million on nuclear refueling outages in 2016 as compared to 2015.

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•	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 in nuclear construction expenditures primarily as a result of a higher scope of work performed in 2016 on Grand Gulf outage projects, partially offset by decreased spending in 2016 on compliance with NRC post-Fukushima requirements.

•	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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•	net borrowings of $66.9 million on the nuclear fuel company variable interest entity’s credit facility in 2016 compared to net repayments of $20.4 million on the nuclear fuel company variable interest entity’s credit facility in 2015;

•	a decrease of $61.8 million in common stock dividends and distributions as a result of lower operating cash flows and higher nuclear fuel purchases in 2016 as compared to the prior year;

•	the redemption in April 2015, at maturity, of $60 million of System Energy nuclear fuel company variable interest entity’s 5.33% Series G notes; and

•	redemption in May 2015 of $35 million and in November 2015 of $25 million of System Energy’s 5.875% Series governmental bonds due 2022.

•	construction and other capital investments;

•	debt maturities or retirements;

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•	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.

•	internally generated funds;

•	cash on hand;

•	debt issuances; and

•	bank financing under new or existing facilities.

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

•	long-term borrowings and security issuances; and

•	long-term 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;

•	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 “Corporate Governance at Entergy - Our Board Structure - Identifying Director Candidates”; and

•	the candidate’s signed consent to be named in the Proxy Statement and to serve as a director if elected.

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(1)	Messrs. Bakken, Brown, Denault, Marsh, and West hold the positions referenced above as executive officers

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•	Pay for performance

•	Attract, retain, and motivate key executive officers who drive Entergy Corporation’s success and industry leadership

•	Provide market compensation payout opportunities

•	Align with the interests of Entergy Corporation’s long-term shareholders

•	Reflect best practices in the market

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•

2017 Annual Incentive Plan Payout. For 2017, the Personnel Committee, based on a recommendation of the Finance Committee, determined that management exceeded its consolidated operational earnings per share goal of $5.05 per share by $2.17, but fell short of its consolidated operational operating cash flow goal of $3.000 billion by approximately $227 million. Based on the targets and ranges previously established by the Committee, these results resulted in a calculated EAM of 129%. This determined the maximum funding level for the plan and the maximum award, as a percentage of target, that could be received by any of the executive officers, subject to downward adjustment based on individual performance. After considering individual performance, including the role played by each of the Named Executive Officers, who are members of the Office of the Chief Executive, in advancing Entergy Corporation’s strategies and delivering the strong financial results in 2017, the Personnel Committee approved payouts of 129% of target for each of the Named Executive Officers, who are members of the Office of the Chief Executive.

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Long-Term Performance Unit Program Payout. For the three-year performance period ending in 2017, Entergy Corporation’s total shareholder return was in the third quartile, resulting in a payout of 31% of target for its executive officers. Payouts were made in shares of Entergy Corporation common stock which are required to be held by executive officers until they satisfy the executive stock ownership guidelines.

•	For non-industry specific positions, general industry data for total cash compensation (base salary and annual incentive) since the market for talent is broader than the utility sector.

•	For management positions that are industry-specific, such as Group President, Utility Operations, data from utility companies for total cash compensation.

•	For all positions, utility market data for long-term incentives.

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•	135% for Mr. Denault;

•	70% for Mr. Bakken, Mr. Brown, Mr. Marsh, and Mr. West;

•	60% for Mr. May; and

•	40% for Mr. Fisackerly, Ms. Rainer, Mr. Rice, and Mr. Riley.

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(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)	As a new hire in 2016, Mr. Bakken received pro-rated target award opportunities for the 2015-2017 and 2016-2018 performance periods.

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(1)	Value determined based on the closing price of Entergy Corporation’s common stock on January 17, 2018 ($78.51), the date the Personnel Committee certified the 2015-2017 performance period results.

(2)	As a new hire in 2016, Mr. Bakken received pro-rated target award opportunities for the 2015-2017 performance period.

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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.

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

•	all net after-tax shares of 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, except for stock options granted before January 1, 2014, as to which the executive officer must retain at least 75% of the after-tax net shares until the earlier of achievement of the stock ownership guidelines or five years from the date of exercise.

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•	developing and implementing compensation policies and programs for hiring, evaluating, and setting compensation for executive officers, including any employment agreement with an executive officer;

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

•	reporting, at least annually, to the Board on succession planning, including succession planning for the Chief Executive Officer.

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(1)	Mr. Bakken was named Executive Vice President and Chief Nuclear Officer in April 2016. Mr. Brown was not a Named Executive Officer in 2015. Mr. Riley was named Chief Executive Officer, Entergy Arkansas in May 2016.

(2)	The amounts in column (c) represent the actual base salary paid to the Named Executive Officers.  The 2017 changes in base salaries noted in the Compensation Discussion and Analysis were effective in April 2017.

(3)	The amount in column (d) in 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 represents a cash sign-on bonus paid to Mr. Bakken in connection with his commencement of employment with Entergy Corporation.

(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 Equity Ownership Plans, 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 restricted stock units is based on the closing price of Entergy Corporation common stock on the date of grant.  The grant date fair value of performance units is based on the probable outcome of the applicable performance conditions, measured using a Monte Carlo simulation valuation model.  The simulation model applies a risk-free interest rate and an expected volatility assumption.  The risk-free interest rate is assumed to equal the yield on a three-year treasury bond on the grant date.  Volatility is based on historical volatility for the 36-month period preceding the grant date.  If the highest achievement level is attained, the maximum amounts that will be received with respect to the performance units granted in 2017 are as follows:  Mr. Bakken, $1,170,798; Mr. Brown, $1,170,798; Mr. Denault, $6,869,622; Mr. Fisackerly, $260,961; Mr. Marsh, $1,170,798; Mr. May, $444,339; Ms. Rainer, $260,961; Mr. Rice, $260,961; Mr. Riley, $260,961; and Mr. West, $1,170,798. The amount in 2016 for Mr. Bakken includes restricted stock units granted to him in connection with his commencement of employment as Chief Nuclear Officer.

(5)	The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the Equity Ownership Plans 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.

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(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 “2017 Pension Benefits”).  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 “2017 Non-qualified Deferred Compensation”).

(8)	The amounts in column (i) for 2017 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.  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.

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(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.  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.  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, 2019.)  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 Ownership 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 Ownership Plan.

(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 2017 Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.

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(1)	Consists of options that vested or will vest as follows: 1/3 of the remaining unexercisable options vest on each of January 26, 2018, January 26, 2019, and January 26, 2020.

(2)	Consists of options that vested or will vest as follows: 1/2 of the remaining unexercisable options vest on each of January 28, 2018 and January 28, 2019.

(3)	The remaining unexercisable options vested on January 29, 2018.

(4)	Consists of performance units that will vest on December 31, 2019 based on Entergy Corporation’s total shareholder return performance over the 2017-2019 performance period, as described under “What Entergy Corporation Pays and Why- Executive Compensation Elements - Variable - Long-Term Incentive Compensation - Performance Unit Program” in Compensation Discussion and Analysis.

(5)	Consists of performance units that will vest on December 31, 2018 based on Entergy Corporation’s total shareholder return performance over the 2016-2018 performance period.

(6)	Consists of shares of restricted stock that vested or will vest as follows:  1/3 of the shares of restricted stock granted vest on each of January 26, 2018, January 26, 2019, and January 26, 2020.

(7)	Consists of shares of restricted stock that vested or will vest as follows:  1/2 of the shares of restricted stock granted vest on each of January 28, 2018 and January 28, 2019.

(8)	Consists of shares of restricted stock that vested on January 29, 2018.

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

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

(11)	Consists of restricted stock units granted under the 2011 Equity Ownership Plan which will vest on May 1, 2018.

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(1)	Represents the value of performance units for the 2015-2017 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 2017.

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(1)	As of December 31, 2017, 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 15 years of service under the non-qualified System Executive Retirement Plan only if his Entergy employer grants him permission to retire. The additional 15 years of service increases the present value of his benefit by $3,967,700.

(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.

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(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.

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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.

(2)

Benefits already 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 Code Section 409A.

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

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

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1)

In addition to the payments and benefits in the table, if Mr. Bakken’s employment were terminated under certain conditions relating to a change in control, on the first day of the month following the Qualifying Event (as defined in the Cash Balance Equalization Plan) he would have become vested in and would have been entitled to receive his vested pension benefits accumulated in the Cash Balance Equalization Plan as of the date of the Qualifying Event so long as a forfeiture event does not occur as described in the plan. For a description of the pension benefits under the Cash Balance Equalization Plan, see “2017 Pension Benefits.”

2)	As of December 31, 2017, Messrs. Brown, May, and 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, each also would be entitled to receive his or her vested pension benefits under the Entergy Retirement Plan. For a description of the pension

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3)

As of December 31, 2017, Mr. Denault is retirement eligible and would retire rather than voluntarily resign, and in addition to the payments and benefits in the table, Mr. Denault also would be entitled to receive his vested pension benefits under the Entergy Retirement Plan. For a description of the pension benefits available, see “2017 Pension Benefits.” If Mr. Denault’s employment was terminated by his Entergy employer other than for cause, by Mr. Denault for good reason or on account of his death or disability, he would also be eligible for certain additional retirement benefits. For a description of these benefits, see “2017 Pension Benefits.” Otherwise, if Mr. Denault’s employment was terminated for cause or he was to retire from his Entergy employer before age 65 without the permission of his Entergy employer, he would not receive a benefit under the System Executive Retirement Plan.

4)

In addition to the payments and benefits in the table, if Mr. Fisackerly’s, Mr. Marsh’s, Mr. Rice’s, or Mr. West’s employment were terminated under certain conditions relating to a change in control, each also would have been entitled to receive his vested pension benefits upon attainment of age 55 under the Entergy Retirement Plan and would have been eligible for early retirement benefits under the System Executive Retirement Plan calculated using early retirement reduction factors. For a description of the pension benefits, see “2017 Pension Benefits.” Mr. Fisackerly’s, Mr. Marsh’s, Mr. Rice’s, or Mr. West’s employment were terminated for cause in connection with a change in control, he would not be entitled to receive a benefit under the System Executive Retirement Plan. If his employment were terminated for any reason not in connection with a change in control, or each were to resign from his Entergy employer before age 65 without the permission of his Entergy employer, each would not be entitled to receive a benefit under the System Executive Retirement Plan.

5)

In the event of a termination by the executive for good reason or by his or her Entergy system employer not for cause during the period beginning upon the occurrence of a “potential change in control” (as defined in the System Executive Continuity Plan) and ending on the 2nd anniversary of a change in control, each Named Executive Officer would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to a multiple of the sum of (1) his or her annual base salary as in effect at any time within one year prior to the commencement of a change of control period or, if higher, immediately prior to a circumstance constituting good reason plus (2) his or her annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for 2015 and 2016 (the two calendar years immediately preceding the calendar year in which termination occurs), but in no event shall the severance payment exceed the product of 2.99 times the sum of (a) his or her annual base salary as in effect at any time within one year prior to the commencement of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) the higher of his or her actual annual incentive payment under the Annual Incentive Plan for the 2016 performance year or his or her annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for 2015 and 2016 (the two calendar years immediately preceding the calendar year in which termination occurs). For purposes of this table, the following target opportunity and base salary were assumed:

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6)

With respect to Mr. Denault, in the event of a Termination Event (as defined in Mr. Denault’s 2006 retention agreement), he is entitled to a Target LTIP Award, as defined in his 2006 retention agreement, calculated by using the average annual number of performance units with respect to the two most recent performance periods preceding the calendar year in which his employment termination occurs, assuming all performance goals were achieved at target. 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 2013-2015 Performance Unit Program (38,000) and from the 2014-2016 Performance Unit Program (40,000). This average number of units (39,000) multiplied by the closing price of Entergy Corporation’s common stock on December 29, 2017 ($81.39) would equal a payment of $3,174,210. In the event of death or disability, Mr. Denault receives the greater of the Target LTIP Award calculated as described above or the sum of the amount that would be payable under the provisions of each open Performance Unit Program as described in Note 7 below.

7)

In the event of a qualifying termination related to a change in control, each Named Executive Officer would have forfeited his or her performance units for the 2016-2018 and 2017-2019 performance periods and would have been entitled to receive, pursuant to the 2015 Equity Ownership Plan, a single-lump sum payment in lieu of any payment for each performance award that would not be based on any outstanding performance period. The payments for the 2016-2018 and the 2017-2019 performance periods would have been calculated using the most recent performance period preceding (but not including) the calendar year in which his or her termination occurs. For purposes of the table, the value of Mr. Denault’s payments was calculated by multiplying the target performance units for the 2014-2016 Performance Unit Program (40,000) by the closing price of Entergy Corporation’s common stock on December 29, 2017 ($81.39), which would equal a payment of $3,255,600 for the forfeited performance units for each performance period. The value of the payments for the other Named Executive Officers was calculated by multiplying the target performance units for the 2014-2016 Performance Unit Program (9,400) by the closing price of Entergy Corporation’s common stock on December 29, 2017 ($81.39), which would equal a payment of $765,066 for the forfeited performance units for each performance period. In the event his death or disability, Mr. Denault would receive the greater of the target Long-Term Performance Incentive award as described in note 6 above or a pro-rated number of performance units for all open performance periods, based on the number of months of his participation in each open performance period.

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8)

In the event of death or disability or qualifying termination related to a change in control, or retirement in the case of Mr. Brown, Mr. Denault, Mr. May, Ms. Rainer, or Mr. Riley, all of the unvested stock options of each Named Executive Officer would immediately vest pursuant to the Equity Ownership Plans. In addition, with respect to grants under the 2011 Equity Ownership Plan, each Named Executive Officer would be entitled to exercise his or her stock options for the remainder of the ten-year period extending from the grant date of the options, and with respect to grants under the 2015 Equity Ownership Plan, within the lesser of five years or the remaining term of the option grant. For purposes of this table, it is assumed that the Named Executive Officers exercised their options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 29, 2017, and the applicable exercise price of each option share.

9)

In the event of death or disability pursuant to the 2011 Equity Ownership Plan, each Named Executive Officer would immediately vest in a pro-rated portion of his or her unvested restricted stock that was otherwise scheduled to become vested on the immediately following 12-month grant date anniversary date, as well as dividends declared on the pro-rated portion of such restricted stock pursuant to the 2011 Equity Ownership Plan. The pro-rated vested portion would be determined based on the number of days between the most recent preceding 12-month grant date anniversary date and the date of his or her death or disability. In the event of his or her qualifying termination related to a change in control, a Named Executive Officer would immediately vest in all of their unvested restricted stock, as well as dividends declared on such restricted stock granted pursuant the 2011 Equity Ownership Plan. In the event of death, disability, or qualifying termination related to a change in control, each Named Executive Officer would vest in all of their unvested restricted stock as well as dividends declared pursuant to the 2015 Equity Ownership Plan.

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10)	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-sponsored COBRA benefits for 18 months and Mr. Fisackerly and Mr. Rice would be eligible to receive Entergy-sponsored COBRA benefits for 12 months.

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

12)

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, then 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 Corporation and its affiliates. In the event of a change in control, the unvested restricted stock units will fully vest upon Mr. Bakken’s termination of employment by his Entergy employer without cause or by Mr. Bakken with good reason during a change in control period (as defined in the 2015 Equity Ownership Plan). Otherwise, if Mr. Bakken voluntarily resigns or is terminated, he would forfeit these units. Pursuant to his restricted stock unit agreement, Mr. Bakken is subject to certain restrictions on his ability to compete with Entergy Corporation 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 Corporation 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 Corporation any shares of Entergy Corporation’s common 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.

13)

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. In the event of a change in control, the units will vest upon termination of Mr. Marsh’s employment by his Entergy employer without cause or by Mr. Marsh with good reason during a change in control period (as defined in the 2015 Equity Ownership Plan). Otherwise, if Mr. Marsh voluntarily resigns or is terminated, he would forfeit these units. Pursuant to his restricted stock unit agreement, Mr. Marsh is subject to certain restrictions on his ability to compete with Entergy Corporation and its affiliates during and for 12 months after his employment with Entergy Corporation, or to solicit its employees or customers during and for 24 months after his employment with it. In addition, the restricted stock unit agreement limits Mr. Marsh’s ability to disparage Entergy Corporation 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 Corporation any shares of Entergy Corporation’s common 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.

14)

Mr. West’s 21,000 restricted stock units vest 100% in 2018. Pursuant to his restricted stock unit agreement, any unvested restricted stock units will vest immediately in the event of a termination other than for cause. In the event of a change in control, the units will vest upon termination of Mr. West’s employment by his Entergy employer without cause or by Mr. West with good reason during a change in control period (as defined in the 2011 Equity Ownership Plan). Otherwise, if Mr. West voluntarily resigns, is terminated for cause, dies, or becomes disabled, he would forfeit these units.

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•	continuing failure to substantially perform his duties (other than because of physical or mental illness or after he has given notice of termination for good reason) that remains uncured for 30 days after receiving a written notice from the Personnel Committee;

•	willfully engaging in conduct that is demonstrably and materially injurious to Entergy Corporation;

•	conviction of or entrance of a plea of guilty or nolo contendere to a felony or other crime that has or may have a material adverse effect on his ability to carry out his duties or upon Entergy Corporation’s reputation;

•	material violation of any agreement that he has entered into with Entergy Corporation; or

•	unauthorized disclosure of Entergy Corporation’s confidential information.

•	the substantial reduction in the nature or status of his duties or responsibilities from those in effect immediately prior to the date of the retention agreement, other than de minimis acts that are remedied after notice from Mr. Denault;

•	a reduction of 5% or more in his base salary as in effect on the date of the retention agreement;

•	the relocation of his principal place of employment to a location other than the corporate headquarters;

•	the failure to continue to allow him to participate in programs or plans providing opportunities for equity awards, stock options, restricted stock, stock appreciation rights, incentive compensation, bonus and other plans on a basis not materially less favorable than enjoyed at the time of the retention agreement (other than changes similarly affecting all senior executives);

•

the failure to continue to allow him to participate in programs or plans with opportunities for benefits not materially less favorable than those enjoyed by him under any of Entergy Corporation’s pension, savings, life insurance, medical, health and accident, disability, or vacation plans or policies at the time of the retention agreement (other than changes similarly affecting all senior executives); or

•	any purported termination of his employment not taken in accordance with his retention agreement.

•	the purchase of 30% or more of either Entergy Corporation’s common stock or the combined voting power of Entergy Corporation’s voting securities;

•	the merger or consolidation of Entergy Corporation (unless its Board members constitute at least a majority of the board members of the surviving entity);

•	the liquidation, dissolution, or sale of all or substantially all of Entergy Corporation’s assets; or

•	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.

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•	Entergy Corporation or an affiliate enters into an agreement the consummation of which would constitute a change in control;

•	the Entergy Corporation Board adopts resolutions determining that, for purposes of the System Executive Continuity Plan, a potential change in control has occurred;

•	a System Company or other person or entity publicly announces an intention to take actions that would constitute a change in control; or

•	any person or entity becomes the beneficial owner (directly or indirectly) of outstanding shares of Entergy Corporation’s common stock constituting 20% or more of the voting power or value of Entergy Corporation’s outstanding common stock.

•	willfully and continuously fails to substantially perform his or her duties after receiving a 30-day written demand for performance from Entergy Corporation’s Board;

•	engages in conduct that is materially injurious to Entergy Corporation or any of its subsidiaries;

•	is convicted or pleads guilty or nolo contendere to a felony or other crime that materially and adversely affects his or her ability to perform his or her duties or Entergy Corporation’s reputation;

•	materially violates any agreement with Entergy Corporation or any of its subsidiaries; or

•	discloses any of Entergy Corporation’s confidential information without authorization.

•	the nature or status of his or her duties and responsibilities is substantially altered or reduced compared to the period prior to the change in control;

•	his or her salary is reduced by 5% or more;

•	he or she is required to be based outside of the continental United States at somewhere other than his or her primary work location prior to the change in control;

•	any of his or her compensation plans are discontinued without an equitable replacement;

•	his or her benefits or number of vacation days are substantially reduced; or

•	his or her Entergy employer purports to terminate his or her employment other than in accordance with the System Executive Continuity Plan.

•	accepts employment with Entergy Corporation or any of its subsidiaries;

•	elects to receive the benefits of another severance or separation program;

•	removes, copies or fails to return any property belonging to Entergy Corporation or any of its subsidiaries;

•	discloses non-public data or information concerning Entergy Corporation or any of its subsidiaries; or

•	violates his or her non-compete provision, which generally runs for two years but extends to three years if permissible under applicable law.

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•	all unvested stock options, shares of restricted stock and restricted stock units as well as any perquisites to which he or she is entitled as an officer are forfeited;

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incentive payments under any outstanding performance periods under the Long-Term Performance Unit Program or the Annual Incentive Plan are forfeited; provided however, if an officer resigns after the completion of an Annual Incentive Plan or Long-Term Performance Unit Program performance period, he or she could receive a payout under the Long-Term Performance Unit Program based on the outcome of the performance period and could, at Entergy Corporation’s discretion, receive an annual incentive payment under the Annual Incentive Plan;

•	any vested stock options held by the officer as of the separation date will expire the earlier of ten years from date of grant or 90 days from the last day of active employment; and

•	he or she is entitled to all vested accrued benefits and compensation as of the separation date, including qualified pension benefits (if any) and other post-employment benefits on terms consistent with those generally available to other salaried employees.

•

the annual incentive payment under the Annual Incentive Plan is generally pro-rated based on the actual number of days employed during the performance year in which the retirement date occurs, subject to negative discretion that may be applied to reduce or disallow the payment; payments are delivered at the conclusion of the annual period, consistent with the timing of payments to active participants in the Annual Incentive Plan;

•

payments under the Long-Term Performance Unit Program for those retiring with a minimum of 12 months of participation are pro-rated based on the actual full months of participation in each outstanding performance period in which the retirement date occurs, and payments are delivered at the conclusion of each performance period, consistent with the timing of payments to active participants in the Long-Term Performance Unit Program;

•	unvested stock options issued under the 2011 Equity Ownership Plan vest on the retirement date and expire ten years from the grant date of the options;

•	unvested stock options issued under the 2015 Equity Ownership Plan vest on the retirement date and expire the earlier of five years from the grant date of the options or the original term of ten years;

•	any unvested restricted stock and restricted stock units held by the executive upon his retirement are forfeited; and

•	he or she is generally entitled to all vested accrued benefits and compensation as of the separation date, including qualified pension benefits and other post-employment benefits consistent with those generally available to salaried employees.

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•	Mr. Riley’s annual total compensation, as reported in the Total column of the 2017 Summary Compensation Table, was $1,353,719.

•	The annual total compensation of the median employee was $127,560.

•	Based on this information, the ratio of the annual total compensation of Mr. Riley to the median employee is estimated to be 11:1.

•	Mr. May’s annual total compensation, as reported in the Total column of the 2017 Summary Compensation Table, was $1,564,954.

•	The annual total compensation of the median employee was $144,954.

•	Based on this information, the ratio of the annual total compensation of Mr. May to the median employee is estimated to be 11:1.

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•	Mr. Fisackerly’s annual total compensation, as reported in the Total column of the 2017 Summary Compensation Table, was $1,207,343.

•	The annual total compensation of the median employee was $112,110.

•	Based on this information, the ratio of the annual total compensation of Mr. Fisackerly to the median employee is estimated to be 11:1.

•	Mr. Rice’s annual total compensation, as reported in the Total column of the 2017 Summary Compensation Table, was $824,111.

•	The annual total compensation of the median employee was $91,346.

•	Based on this information, the ratio of the annual total compensation of Mr. Rice to the median employee is estimated to be 9:1.

•	Ms. Rainer’s annual total compensation, as reported in the Total column of the 2017 Summary Compensation Table, was $1,200,260.

•	The annual total compensation of the median employee was $129,877.

•	Based on this information, the ratio of the annual total compensation of Ms. Rainer to the median employee is estimated to be 9:1.

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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, Hintz, 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 Ownership 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 Ownership 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 Ownership Plan, with no more than 1,500,000 shares available for incentive stock option grants.  The 2015 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 Ownership Plan (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)	Entergy has a Board-approved stock-based compensation plan. However, effective May 9, 2003, the Board has directed that no further awards be issued under that plan. As of December 31, 2017, all options outstanding under the plan were either exercised or expired.

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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 2017 and 2016 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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