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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.

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Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2% to 3% annually. A 50-basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 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.

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

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

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

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

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

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

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

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