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

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the termination of Entergy Arkansas’s participation in the System Agreement, which occurred in December 2013, the termination of Entergy Mississippi’s participation in the System Agreement, which occurred in November 2015, and the termination of Entergy Texas’s, Entergy New Orleans’s, and Entergy Louisiana’s participation in the System Agreement, which will occur on August 31, 2016, and will result in the termination of the System Agreement in its entirety pursuant to a settlement agreement approved by FERC in December 2015;

•

regulatory and operating challenges and uncertainties and economic risks associated with the Utility operating companies’ move to MISO, which occurred in December 2013, including 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 the beginning or end of 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;

•	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 its 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;

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

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

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

•	changes in environmental, tax, and other laws and regulations, including requirements for reduced emissions of sulfur dioxide, nitrogen oxide, greenhouse gases, mercury, thermal energy, and other regulated air and water emissions, and changes in costs of compliance with environmental and other laws and regulations;

•	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;

•	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;

•	the effects of Entergy’s strategies to reduce tax payments;

•	changes in the financial markets, particularly those affecting the availability of capital and Entergy’s ability to refinance existing debt, 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;

•	the effects of threatened or actual terrorism, cyber-attacks or data security breaches, including increased security costs, 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 and directors;

•	changes in accounting standards and corporate governance;

•	declines in the market prices of marketable securities and resulting funding requirements and the effects on benefit 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 nuclear plant sites;

•	the implementation of the shutdown of Pilgrim and FitzPatrick and the related decommissioning of those plants and Vermont Yankee;

•	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 merger, acquisition, or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition, or divestiture, and the success of the business following a merger, acquisition, or divestiture.

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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. On December 29, 2014, the Vermont Yankee plant ceased power production and entered its decommissioning phase. In October 2015, Entergy determined that it will close the Pilgrim plant no later than June 1, 2019 and the FitzPatrick plant at the end of its current fuel cycle, which is planned for January 27, 2017. 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.

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•	formula rate plan increases at Entergy Louisiana, as approved by the LPSC, effective December 2014 and January 2015;

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an increase in energy efficiency rider revenue primarily due to increases in the energy efficiency rider at Entergy Arkansas, as approved by the APSC, effective July 2015 and July 2014, and new energy efficiency riders at Entergy Louisiana and Entergy Mississippi that began in the fourth quarter 2014. Energy efficiency revenues are largely offset by costs included in other operation and maintenance expenses and have a minimal effect on net income; and

•	an annual net rate increase at Entergy Mississippi of $16 million, effective February 2015, as a result of the MPSC order in the June 2014 rate case.

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•	lower realized wholesale energy prices, primarily due to significantly higher Northeast market power prices in 2014, and lower capacity prices in 2015; and

•	a decrease in net revenue as a result of Vermont Yankee ceasing power production in December 2014.

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(a)	The reduction in owned capacity is due to the retirement of the 605 MW Vermont Yankee plant in December 2014 and the sale of the 583 MW Rhode Island State Energy Center in December 2015.

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an increase of $59 million in nuclear generation expenses primarily due to an increase in regulatory compliance costs, higher labor costs, and an overall higher scope of work done in 2015. The increase in regulatory compliance costs is primarily related to additional NRC inspection activities in 2015 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 “ANO Damage, Outage, and NRC Reviews” below for a discussion of the ANO stator incident and subsequent NRC reviews;

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an increase of $28 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefit costs as a result of lower discount rates and changes in retirement and mortality assumptions, partially offset by a decrease in the accrual for incentive-based compensation.  See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;

•	an increase of $27 million in energy efficiency costs, including the effects of true-ups to energy efficiency filings for fixed costs to be collected from customers.  These costs are recovered through energy efficiency riders in certain jurisdictions and have a minimal effect on net income;

•	an increase of $26 million in distribution expenses primarily due to higher vegetation maintenance and higher labor costs in 2015 as compared to 2014; and

•	an increase of $24 million in transmission expenses primarily due to an increase in the amount of transmission costs allocated by MISO. The net income effect is partially offset by the method of recovery of these costs in certain jurisdictions.  See Note 2 to the financial statements for further information on the recovery of these costs.

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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 is no longer probable of recovery and the $16 million ($11 million net-of-tax) write-off in 2014 due to the uncertainty at the time associated with the resolution of the Waterford 3 replacement steam generator project prudence review;

•	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; and

•	the $56 million ($37 million net-of-tax) write-off in 2014 of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs.

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•	increases in the energy efficiency rider at Entergy Arkansas, as approved by the APSC, effective July 2013 and July 2014. Energy efficiency revenues are offset by costs included in other operation and maintenance expenses and have minimal effect on net income;

•	the effect of the APSC’s order in Entergy Arkansas’s 2013 rate case, including an annual base rate increase effective January 2014 offset by a MISO rider to provide customers credits in rates for transmission revenue received through MISO;

•	a formula rate plan increase at Entergy Mississippi, as approved by the MSPC, effective September 2013;

•	an increase in Entergy Mississippi’s storm damage rider, as approved by the MPSC, effective October 2013. The increase in the storm damage rider is offset by other operation and maintenance expenses and has no effect on net income;

•	an annual base rate increase at Entergy Texas, effective April 2014, as a result of the PUCT’s order in the September 2013 rate case; and

•	a formula rate plan increase at Entergy Louisiana, as approved by the LPSC, effective December 2014.

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higher realized wholesale energy prices primarily due to increases in Northeast market power prices and higher capacity prices. Entergy Wholesale Commodities’ hedging strategies routinely include financial instruments that manage operational and liquidity risk. These positions, in addition to a larger-than-normal unhedged position in 2014 due to Vermont Yankee being in its final year of operation, allowed Entergy Wholesale Commodities to benefit from increases in Northeast market power prices; and

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higher volume in its nuclear fleet resulting from approximately 90 fewer unplanned outage days in 2014 compared to 2013, partially offset by a larger exercise of resupply options in 2013 compared to 2014 provided for in purchase power agreements where Entergy Wholesale Commodities may elect to supply power from another source when the plant is not running. Amounts related to the exercise of resupply options are included in the GWh billed in the table below.

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•	an increase of $53 million in nuclear generation expenses primarily due to higher material costs, higher contract labor costs, and higher NRC fees;

•	an increase of $38 million in administration fees related to participation in the MISO RTO beginning December 2013. The net income effect is partially offset due to deferrals of these fees in certain jurisdictions. See Note 2 to the financial statements for further information on the deferrals;

•	an increase of $29 million in energy efficiency costs.  These costs are recovered through energy efficiency riders and have a minimal effect on net income;

•	an increase of $24 million in storm damage accruals primarily at Entergy Arkansas effective January 2014, as approved by the APSC, and at Entergy Mississippi effective October 2013, as approved by the MPSC;

•	an increase of $20 million in regulatory, consulting, and legal fees;

•	an increase of $19 million in contract labor primarily due to higher infrastructure and application services and call center outsourcing;

•	an increase of $11 million primarily due to higher vegetation maintenance;

•	an increase of $7 million due to higher write-offs of uncollectible customer accounts in 2014 as compared to 2013;

•	an increase of $7 million due to the amortization in 2014 of costs deferred in 2013 related to the transition and implementation of joining the MISO RTO; and

•	several individually insignificant items.

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a decrease of $146 million in compensation and benefits costs primarily due to fewer employees, an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan.  See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;

•	a decrease of $36 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business;

•	a decrease of $9 million resulting from costs incurred in 2013 related to the generator stator incident at ANO, including an offset for insurance proceeds. See “ANO Damage, Outage, and NRC Reviews” below for further discussion of the incident;

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a net decrease of $8 million related to the human capital management strategic imperative in 2014 as compared to 2013 including a decrease of $60 million in implementation costs, severance costs, and curtailment and special termination benefits, the deferral in 2013 of $44 million of costs incurred, as approved by the APSC and LPSC, and partial amortization in 2014 of $8 million of costs that were deferred in 2013. See “Human Capital Management Strategic Imperative” below for further discussion; and

•	a net decrease of $4 million related to Baxter Wilson (Unit 1) repairs. The increase in repair costs incurred in 2014 compared to the prior year were offset by expected insurance proceeds and the deferral of repair costs, as approved by the MPSC. See “Baxter Wilson Plant Event” in Note 8 to the financial statements for further discussion.

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a decrease of $63 million in compensation and benefits costs primarily due to fewer employees, an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;

•	a decrease of $15 million due to the absence of expenses from Entergy Solutions District Energy, which was sold in November 2013; and

•	a decrease of $13 million in implementation costs, severance costs, and curtailment and special termination benefits related to the human capital management strategic imperative in 2014 as compared to 2013. See “Human Capital Management Strategic Imperative” below for further discussion.

•	an increase of $22 million incurred in 2014 as compared to 2013 related to the shutdown of Vermont Yankee including severance and retention costs. See “Impairment of Long-Lived Assets” in Note 1 to the financial statements for discussion regarding the shutdown of the Vermont Yankee plant in December 2014;

•	an increase of $18 million primarily due to higher contract costs and higher NRC fees; and

•	$18 million in transmission imbalance sales in 2013.

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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 rate as of December 31, 2015 that would be 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 allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility.

(d)	The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility.

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

(f)	The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility.

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

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

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

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

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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.

•	Potential resource planning investments, including the Union Power Station acquisition discussed below, and potential construction of additional generation.

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

•	NRC post-Fukushima requirements for the Utility and Entergy Wholesale Commodities nuclear fleets.

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

•	Distribution spending to maintain reliability and improve service to customers, including initial investment to support smart meter deployment.

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•	internally generated funds;

•	cash on hand ($1,351 million as of December 31, 2015);

•	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 revenues in 2015 as compared to 2014, as discussed previously;

•	proceeds of $310 million received from the Louisiana Utilities Restoration Corporation in August 2014 as a result of the Louisiana Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” above for a discussion of the Act 55 storm cost financing;

•	spending of $78 million in 2015 on activities related to the decommissioning of Vermont Yankee, which ceased power production in December 2014;

•	an increase of $52 million in interest paid in 2015 primarily due to an increase in interest paid on the Grand Gulf sale-leaseback obligation. See Note 10 to the financial statements for details of the Grand Gulf sale-leaseback obligation;

•	an increase in spending of $48 million in 2015 related to Vermont Yankee, including the severance and retention payments accrued in 2014 and defueling activities that took place after the plant ceased power production in December 2014; and

•	an increase in income tax payments of $26 million primarily due to payments made in 2015 for the final settlement of amounts outstanding associated with the 2006-2007 IRS audit. See Note 3 to the financial statements for a discussion of the finalized tax and interest computations for the 2006-2007 IRS audit.

•	an increase in the recovery of fuel costs in 2015;

•	higher Utility net revenues in 2015 as compared to 2014, as discussed above; and

•	a decrease of $46 million in storm spending in 2015 as compared to 2014.

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•	higher Entergy Wholesale Commodities and Utility net revenues in 2014 as compared to 2013, as discussed previously;

•	proceeds of $310 million received from the LURC in August 2014 as a result of the Louisiana Act 55 storm cost financings. See Note 2 to the financial statements for a discussion of the Act 55 storm cost financings;

•	$58 million margin deposits made by Entergy Wholesale Commodities in 2013;

•	a decrease in income tax payments of $50 million in 2014 compared to 2013 primarily due to state income tax effects of the settlement of the 2004-2005 IRS audit paid in 2013; and

•	approximately $25 million in spending in 2013 related to the generator stator incident at ANO, as discussed previously.

•	an increase of $236 million in pension contributions in 2014, partially offset by a decrease of $38 million in lump sum retirement payments out of the non-qualified pension plan in 2014 as compared to 2013. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;

•	proceeds of $72 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel;

•	an increase of $44 million in spending on nuclear refueling outages in 2014 as compared to 2013; and

•	an increase of $25 million in storm restoration spending in 2014.

•	proceeds of approximately $490 million from the sale in December 2015 of Rhode Island State Energy Center. See Note 15 to the financial statements for further discussion of the sale;

•	the deposit of a total of $64 million into Entergy New Orleans’s storm reserve escrow accounts in 2015 compared to the deposit of a total of $268 million into Entergy Louisiana’s storm reserve escrow accounts in 2014;

•	$58 million in disbursements from the Vermont Yankee decommissioning trust funds to Entergy in 2015; and

•	a decrease 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 in construction expenditures primarily due to an overall higher scope of work on various projects in 2015 as compared to 2014 and compliance with NRC post-Fukushima requirements, partially offset by a decrease in storm restoration spending and a decrease in spending on the Ninemile Unit 6 project;

•	a change in collateral deposit activity, reflected in the “Decrease (increase) in other investments” line on the Consolidated Statements of Cash Flows, as Entergy received net deposits of $47 million in 2014.  Entergy Wholesale Commodities’ forward sales contracts are discussed in the “Market and Credit Risk Sensitive Instruments” section below; and

•	a decrease of $16 million in insurance proceeds primarily due to $13 million received in 2015 related to the Baxter Wilson plant event and $12 million received in 2015 for property damages related to the generator stator incident at ANO compared to $37 million received in 2014 for property damages related to the generator

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•	the deposit of a total of $276 million into storm reserve escrow accounts in 2014, primarily by Entergy Louisiana. See “Hurricane Isaac” above for a discussion of storm reserve escrow account replenishments in 2014;

•	the withdrawal of a total of $260 million from storm reserve escrow accounts in 2013, primarily by Entergy Louisiana, after Hurricane Isaac. See “Hurricane Isaac” above for discussion of storm reserve escrow account withdrawals;

•	proceeds of $140 million from the sale in November 2013 of Entergy Solutions District Energy. See Note 15 to the financial statements for further discussion of the sale;

•	proceeds of $21 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel; and

•	an increase 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.

•	a decrease in construction expenditures, primarily in the Utility business, including a decrease in spending on the Ninemile 6 project and spending in 2013 on the generator stator incident at ANO, partially offset by an increase in storm restoration spending;

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a change in collateral deposit activity, reflected in the “Decrease (increase) in other investments” line on the Consolidated Statements of Cash Flows, as Entergy received net deposits of $47 million in 2014 and returned net deposits of $88 million in 2013.  Entergy Wholesale Commodities’ forward sales contracts are discussed in the “Market and Credit Risk Sensitive Instruments” section below; and

•	$37 million in insurance proceeds received in 2014 for property damages related to the generator stator incident at ANO, as discussed above.

•	long-term debt activity providing approximately $41 million of cash in 2015 compared to providing $777 million of cash in 2014.  Included in the long-term debt activity is $140 million in 2015 and $440 million in 2014 for the repayment of borrowings on the Entergy Corporation long-term credit facility;

•	a decrease of $171 million in treasury stock issuances in 2015 primarily due to a larger amount of previously repurchased Entergy Corporation stock issued in 2014 to satisfy stock option exercises;

•	a net decrease of $154 million in 2015 in short-term borrowings by the nuclear fuel company variable interest entities; and

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the repurchase or redemption of $94 million of preferred membership interests in 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 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 business combination.

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•	net repayments of $62 million of commercial paper in 2015 compared to net repayments of $561 million of commercial paper in 2014;

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

•	a decrease of $83 million of common stock repurchased in 2015 as compared to 2014.

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long-term debt activity providing approximately $777 million of cash in 2014 compared to using $69 million of cash in 2013.  The most significant long-term debt activity in 2014 included the net issuance of approximately $385 million of long-term debt at the Utility operating companies and System Energy and Entergy Corporation increasing borrowings outstanding on its long-term credit facility by $440 million in 2014;

•	Entergy Corporation repaid $561 million of commercial paper in 2014 and issued $380 million in 2013;

•	an increase of $112 million in 2014 compared to a decrease of $129 million in 2013 in short-term borrowings by the nuclear fuel company variable interest entities;

•	the repurchase of $183 million of Entergy common stock in 2014; and

•	an increase of $170 million in treasury stock issuances in 2014 primarily due to a larger amount of previously repurchased Entergy Corporation common stock issued in 2014 to satisfy stock option exercises.

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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 17 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 NRC license renewals for plants with NRC license renewal applications in process. Assumes shutdown of FitzPatrick at the end of January 2017 , shutdown of Pilgrim June 1, 2019, and uninterrupted normal operation at remaining plants. NRC license renewal applications are in process for two units, as follows (with current license expirations in parentheses): Indian Point 2 (September 2013 and now operating under its period of

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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.

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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. For certain nuclear plants for which the operating license has not been renewed yet, this estimate assumes a high probability that the plant’s license will be renewed. 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 obligations.

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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 8% to 15%. 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 current Presidential administration, however, has defunded the Yucca Mountain project. 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 timing of when the DOE begins to fulfill its obligation to receive and store spent nuclear fuel.

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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.

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•	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 and currently assumes, for some of its nuclear units, that the plant’s license will be renewed beyond its current expiration date.  A change in the timing assumption could have a significant effect on the expected future cash flows and result in a significant effect on operations.

•	Discount rates used in determining future benefit obligations;

•	Projected health care cost trend rates;

•	Expected long-term rate of return on plan assets;

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•	Rate of increase in future compensation levels;

•	Retirement rates; and

•	Mortality rates.

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