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

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

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

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

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

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

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(a)

The jurisdictional split order assigned the regulatory asset to Entergy Texas.  The regulatory asset, however, is being recovered and amortized at Entergy Louisiana.  As a result, a billing occurs monthly over the same term as the recovery and receipts will be submitted to Entergy Texas.  Entergy Texas has recorded a receivable from Entergy Louisiana and Entergy Louisiana has recorded a corresponding payable.

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

(c)	Does not earn a return on investment.

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(a)	Offset by related asset.

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(a)	2015 and 2014 include respectively $66.7 million and $65.9 million for Entergy Arkansas 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.

(b)	2015 and 2014 include $168.1 million for Entergy Louisiana and $4.1 million 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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•	authorization to increase the revenue it collects from customers by approximately $24 million;

•	an authorized return on common equity of 10.4%;

•	authorization to increase depreciation rates embedded in the proposed revenue requirement; and,

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authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

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•	authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service);

•	an authorized return on common equity of 10.4%;

•	authorization to increase depreciation rates embedded in the proposed revenue requirement; and

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authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

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•	an approximate $16 million net increase in revenues, which reflected an agreed upon 10.07% return on common equity;

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revision of Entergy Mississippi’s formula rate plan by providing Entergy Mississippi with the ability to reflect known and measurable changes to historical rate base and certain expense amounts; resolving uncertainty around and obviating the need for an additional rate filing in connection with Entergy Mississippi’s withdrawal from participation in the System Agreement; updating depreciation rates; and moving costs associated with the Attala and Hinds generating plants from the power management rider to base rates;

•	recovery of non-fuel MISO-related costs through a separate rider for that purpose;

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a deferral of $6 million in other operation and maintenance expenses associated with the Baxter Wilson outage and a determination that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset over two years beginning in February 2015, and a provision that the capital costs will be reflected in rate base. See Note 8 to the financial statements for further discussion of the Baxter Wilson outage; and

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consolidation of the new nuclear generation development costs proceeding with the general rate case proceeding for hearing purposes and a determination that Entergy Mississippi would not further pursue, except as noted below, recovery of the costs that were approved for deferral by the MPSC in November 2011. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. See “New Nuclear Generation Development Costs - Entergy Mississippi” below for further discussion of the new nuclear generation development costs proceeding and subsequent write-off in 2014 of the regulatory asset related to those costs.

•	a $9.3 million base rate revenue increase to be phased in on a levelized basis over four years;

•	recovery of an additional $853 thousand annually through a MISO recovery rider; and

•	the adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.

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•	The System Agreement no longer roughly equalizes total production costs among the Utility operating companies.

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•	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.

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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 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)

In March 2014, New York enacted legislation that substantially modifies various aspects of New York tax law. The most significant effect of the legislation for Entergy is the adoption of full water’s-edge unitary combined reporting, meaning that all of Entergy’s domestic entities will be included in New York’s combined filing group. The effect of the tax law change resulted in a deferred state income tax reduction of approximately $21.5 million as shown in the table above.

(b)	See “Income Tax Audits - 2008-2009 IRS Audit” below for discussion of the most significant items for 2015 and 2013.

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(a)	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)	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 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 addition for Entergy Louisiana and System Energy is related to the nuclear decommissioning costs treatment discussed in “Other Tax Matters” below.

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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.

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

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

(b)	These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%.

(c)

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.

(d)	See Note 10 to the financial statements for further discussion of the Waterford 3 and Grand Gulf lease obligations.

(e)

The fair value excludes lease obligations of $109 million at Entergy Louisiana and $34 million at System Energy, long-term DOE obligations of $181 million at Entergy Arkansas, and the note payable to NYPA of $35 million at Entergy, and includes debt due within one year.  Fair values are classified as Level 2 in the fair value hierarchy discussed in Note 16 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported trades.

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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.

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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 $109 million at Entergy Louisiana and $34 million at System Energy and long-term DOE obligations of $181 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 16 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 first mortgage bonds.

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(a)	In 2007, Entergy Louisiana Holdings, an Entergy subsidiary, purchased 160,000 of these shares from the holders.

(b)	Dollar amount outstanding is net of $2,575 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 September 2015, Entergy Louisiana redeemed its $100 million of 6.95% Series preferred membership interests and Entergy Gulf States Louisiana redeemed its $10 million of 8.25% Series preferred membership interests as part of a multi-step process to effectuate the Entergy Louisiana and Entergy Gulf States Louisiana Business Combination.

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1.	The primary level is private insurance underwritten by American Nuclear Insurers (ANI) and provides public liability insurance coverage of $375 million.  If this amount is not sufficient to cover claims arising from an accident, the second level, Secondary Financial Protection, applies.

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 $127.3 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.4 billion).  This consists of a $121.3 million maximum retrospective premium plus a five percent surcharge, which equates to $127.3 million, that may be payable, if needed, at a rate that is currently set at $19 million per year per incident per nuclear power reactor.

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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 $13.5 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. The Terrorism Risk Insurance Reauthorization Act of 2007 expired on December 31, 2014. However, The Terrorism Risk Insurance Reauthorization Act of 2015 was signed into law by the President of the United States on January 12, 2015 thereby extending the Terrorism Risk Insurance Act for six years until December 31, 2020.

•	Primary Layer (per plant) - $1.5 billion per occurrence

•	Blanket Excess Layer (shared among the Utility plants) - $100 million per occurrence

•	Total limit - $1.6 billion per occurrence

•	Deductibles:

•	$2.5 million per occurrence - Turbine/generator damage

•	$2.5 million per occurrence - Other than turbine/generator damage

•	$10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption

•	Primary Layer (per plant) - $1.115 billion per occurrence

•	Total limit (per plant) - $1.115 billion per occurrence

•	Deductibles:

•	$2.5 million per occurrence - Turbine/generator damage

•	$2.5 million per occurrence - Other than turbine/generator damage

•	$10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption

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•	Primary Layer (per plant) - $1.5 billion per occurrence

•	Excess Layer - $100 million per occurrence

•	Total limit - $1.6 billion per occurrence

•	Deductibles:

•	$2.5 million per occurrence - Turbine/generator damage

•	$2.5 million per occurrence - Other than turbine/generator damage

•	$10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption

•	Primary Layer (per plant) - $1.06 billion per occurrence

•	Total limit - $1.06 billion per occurrence

•	Deductibles:

•	$2.5 million per occurrence - Turbine/generator damage

•	$2.5 million per occurrence - Other than turbine/generator damage

•	$10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption

•	Primary Layer (per plant) - $500 million per occurrence

•	Total limit - $500 million per occurrence

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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.

•	$2.95 million weekly indemnity

•	$413 million maximum indemnity - nuclear

•	$277 million maximum indemnity - non-nuclear

•	Deductible: 26 week deductible period

•	$400,000 weekly indemnity (total for four policies)

•	$56 million maximum indemnity - nuclear (total for four policies)

•	$37 million maximum indemnity - non- nuclear (total for four policies)

•	Deductible: 26 week deductible period

•	$4.5 million weekly indemnity

•	$490 million maximum indemnity - nuclear

•	$327.6 million maximum indemnity - non-nuclear

•	Deductible: 12 week deductible period

•	$4 million weekly indemnity

•	$490 million maximum indemnity - nuclear

•	$327.6 million maximum indemnity - non-nuclear

•	Deductible: 12 week deductible period

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

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(a)	Amounts reflect 100% of minimum payments. Under a separate contract, 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.

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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.

(d)	The registered investment company is a money market mutual fund with a stable net asset value of one dollar per share.

(e)	The registered investment company holds investments in domestic and international bond markets and estimates fair value using net asset value per share.

(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. Net asset value per share of the 103-12 investment entities estimate fair value.

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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 Consolidated Balance Sheets

(d)	Excludes cash collateral in the amount of $9 million posted and $68 million held as of December 31, 2015 and $25 million held as of December 31, 2014, respectively

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(a)	Before taxes of ($85) million, ($68) million, and $18 million, for the years ended December 31, 2015, 2014, and 2013, 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 FTRs 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 FTRs for the Utility operating companies are settled are recovered or refunded through fuel cost recovery mechanisms.

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(a)	No cash collateral was required to be posted as of December 31, 2015 and 2014, respectively.

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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.

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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:

-	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 FTRs 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 17 to the financial statements for additional information on the investment portfolios.

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(a)	Change in unrealized gains or losses for the period included in earnings for derivatives held at the end of the reporting period is $3 million, $120 million, and ($35) million for the years ended December 31, 2015, 2014, and 2013, 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 17 to the financial statements for additional information on the investment portfolios.

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(a)	Includes power purchased from Entergy Power of $3.3 million in 2013. The contract with Entergy Power expired in May 2013.

(b)	Includes power purchased from RS Cogen of $3.2 million in 2013 and power purchased from Entergy Power of $8.1 million in 2013. The contract with Entergy Power expired in May 2013.

(c)	Includes power purchased from Entergy Power of $8 million in 2013. The contract with Entergy Power expired in May 2013.

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(a)

See Note 1 to the financial statements for discussion of the business combination of Entergy Louisiana and Entergy Gulf States Louisiana.   The effect of the business combination has been retrospectively applied to Entergy Louisiana's financial statements that are presented in this report. As a result, operating revenues are higher by $429,097 in the first quarter 2015, $406,974 in the second quarter 2015, $488,543 in the third quarter 2015, $450,840 in the first quarter 2014, $495,020 in the second quarter 2014, $550,847 in the third quarter 2014, and $417,916 in the fourth quarter 2014.

(b)

See Note 1 to the financial statements for discussion of the transfer of Entergy Louisiana’s Algiers assets to Entergy New Orleans. The effect of the Algiers transfer has been retrospectively applied to Entergy New Orleans’s financial statements that are presented in this report.  As a result, operating revenues are higher by $9,726 in the first quarter 2015, $10,258 in the second quarter 2015, $9,299 in the first quarter 2014, $10,331 in the second quarter 2014, $15,553 in the third quarter 2014, and $9,924 in the fourth quarter 2014.

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(c)

See Note 1 to the financial statements for discussion of the business combination of Entergy Louisiana and Entergy Gulf States Louisiana. The effect of the business combination has been retrospectively applied to Entergy Louisiana's financial statements that are presented in this report. As a result, operating income is higher by $79,389 in the first quarter 2015, $65,901 in the second quarter 2015, $100,753 in the third quarter 2015, $82,576 in the first quarter 2014, $70,350 in the second quarter 2014, $96,698 in the third quarter 2014, and $43,766 in the fourth quarter 2014.

(d)

See Note 1 to the financial statements for discussion of the transfer of Entergy Louisiana’s Algiers assets to Entergy New Orleans. The effect of the Algiers transfer has been retrospectively applied to Entergy New Orleans’s financial statements that are presented in this report. As a result, operating income is higher by $1,177 in the first quarter 2015, $1,504 in the second quarter 2015, $541 in the first quarter 2014, $559 in the second quarter 2014, $3,530 in the third quarter 2014, and $856 in the fourth quarter 2014.

(e)

See Note 1 to the financial statements for discussion of the business combination of Entergy Louisiana and Entergy Gulf States Louisiana. The effect of the business combination has been retrospectively applied to Entergy Louisiana's financial statements that are presented in this report. As a result, net income is higher by $53,845 in the first quarter 2015, $33,963 in the second quarter 2015, $68,140 in the third quarter 2015, $46,472 in the first quarter 2014, $36,171 in the second quarter 2014, $55,535 in the third quarter 2014, and $24,313 in the fourth quarter 2014.

(f)

See Note 1 to the financial statements for discussion of the transfer of Entergy Louisiana’s Algiers assets to Entergy New Orleans. The effect of the Algiers transfer has been retrospectively applied to Entergy New Orleans’s financial statements that are presented in this report. As a result, net income is higher (lower) by $238 in the first quarter 2015, $393 in the second quarter 2015, ($18) in the first quarter 2014, $32 in the second quarter 2014, $2,018 in the third quarter 2014, and $291 in the fourth quarter 2014.

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(g)

See Note 1 to the financial statements for discussion of the business combination of Entergy Louisiana and Entergy Gulf States Louisiana. The effect of the business combination has been retrospectively applied to Entergy Louisiana's financial statements that are presented in this report. As a result, earnings applicable to common equity is higher by $53,639 in the first quarter 2015, $33,757 in the second quarter 2015, $67,970 in the third quarter 2015, $46,266 in the first quarter 2014, $35,962 in the second quarter 2014, $55,329 in the third quarter 2014, and $24,107 in the fourth quarter 2014.

(h)

See Note 1 to the financial statements for discussion of the transfer of Entergy Louisiana’s Algiers assets to Entergy New Orleans. The effect of the Algiers transfer has been retrospectively applied to Entergy New Orleans’s financial statements that are presented in this report. As a result, earnings applicable to common equity is higher (lower) by $238 in the first quarter 2015, $393 in the second quarter 2015, ($18) in the first quarter 2014, $32 in the second quarter 2014, $2,018 in the third quarter 2014, and $290 in the fourth quarter 2014.

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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, 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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(a)	Includes the effect of intercompany eliminations.

(a)	Major industrial customers are in the chemical, petroleum refining, and pulp and paper industries.

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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.

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

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

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

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

•	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.

•	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);

•	12-month agreements originally executed in 2005 and which are renewed annually between Entergy Arkansas and Entergy Louisiana and Entergy Texas, and between Entergy Arkansas and Entergy Mississippi, relating 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;

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•	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;

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In September 2012, Entergy Gulf States Louisiana executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 megawatts 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 October 2012, Entergy Arkansas and Union Power Partners, L.P. executed a 3 ½-year agreement for 495 MW from the Union Power Station located in El Dorado, Arkansas.  Cost recovery for this agreement was approved within Entergy Arkansas’s general rate case filed in March 2013;

•	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; and

•	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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(a)	Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2015 and is expected to provide 1% of its generation in 2016.

(b)

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.

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

(b)	In October 2015, Entergy determined that it will close the FitzPatrick plant at the end of the current fuel cycle, which is planned for January 27, 2017.

(c)	On December 29, 2014, the Vermont Yankee plant ceased power production.

(d)	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.”

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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;

•	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;

•	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;

•	issuance and sale of certain securities; and

•	other matters.

•	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 permits program for administration and enforcement of these and other Clean Air Act programs;

•	Regional Haze and Best Available Retrofit Technology 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;

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

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

•	revisions to the estimates of the Social Cost of Carbon used 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; and

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

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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, including but not limited to, the price impacts of proposed emission controls such as the Regional Greenhouse Gas Initiative (RGGI);

•	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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•	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;

•	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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an increase of $43.4 million in nuclear generation expenses primarily due to an increase in regulatory compliance costs. 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 further discussion;

•	an increase of $15.3 million in distribution expenses primarily due to vegetation maintenance and higher labor costs;

•	an increase of $12.6 million in energy efficiency costs, including the effects of true-ups to the energy efficiency filings for fixed costs to be collected from customers. Energy efficiency costs are recovered through the energy efficiency rider and have a minimal effect on net income;

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an increase of $8.9 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefits 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 benefits costs; and

•	an increase of $6.6 million in fossil-fueled generation expenses due to an overall higher scope of work in 2015 as compared to 2014.

•	a net increase of $26.4 million in energy efficiency costs, including a $4.3 million true-up to the 2013 energy efficiency filing for fixed costs collected from customers. These costs are recovered through the energy efficiency rider and have a minimal effect on net income;

•	an increase of $21.2 million in nuclear generation expenses primarily due to higher material costs, higher nuclear labor costs, including contract labor, and higher NRC fees;

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•	an increase of $13.9 million due to an increase in storm damage accruals effective January 2014, as approved by the APSC;

•	an increase of $7.5 million in administration fees in 2014 related to participation in the MISO RTO;

•	an increase of $7.2 million due to the amortization in 2014 of human capital management costs that were deferred in 2013, as approved by the APSC. See Note 2 to the financial statements for further discussion of the deferral of these costs;

•	an increase of $5.2 million due to the amortization in 2014 of costs deferred in 2013 related to the transition and implementation of joining the MISO RTO; and

•	the effects of recording the final court decision in 2013 in the Entergy Arkansas lawsuit against the U.S. Department of Energy related to spent nuclear fuel disposal. The damages awarded include the reimbursement of approximately $3.2 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense.

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a decrease of $20.8 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, 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 pension and other postretirement benefits costs;

•	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; and

•	a decrease of $8.6 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business.

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a $68 million payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period and a $38 million payment made in September 2014 as a result of the compliance filing pursuant to the FERC’s orders related to the bandwidth payments/receipts for the comprehensive recalculation for 2007, 2008, and 2009.  In 2015, Entergy Arkansas received $89.5 million in System Agreement bandwidth remedy collections from customers related to the filings.  See Note 2 to the financial statements for a discussion of the System Agreement proceedings and related recovery from customers;

•	an increase in the recovery of fuel and purchased power costs; and

•	a decrease of $50 million in storm spending in 2015.

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income tax payments of $103.3 million in 2015 compared to income tax refunds of $48.9 million in 2014. Entergy Arkansas made income tax payments in 2015 and received income tax refunds in 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. 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 whereas the income tax refunds in 2014 resulted primarily from the utilization of Entergy Arkansas’s net operating losses by the consolidated group. See Note 3 to the financial statements for a discussion of the income tax audits;

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an increase in nuclear generation expenses primarily due to an increase in regulatory compliance costs. 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” above; and

•	an increase of $30 million in spending on nuclear refueling outages in 2015.

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income tax refunds of $48.9 million in 2014 compared to income tax payments of $184.6 million in 2013. Entergy Arkansas received income tax refunds in 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax refunds in 2014 resulted primarily from the utilization of Entergy Arkansas’s net operating losses by the consolidated group whereas the income tax payments in 2013 resulted primarily from the reversal of temporary differences for which Entergy Arkansas had previously claimed a tax deduction;

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

•	$13.4 million in insurance proceeds received in 2014 for property damages related to the generator stator

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a decrease in the recovery of fuel and purchased power costs including a $68 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period and a $38 million System Agreement bandwidth remedy payment made in September 2014 as a result of the compliance filing pursuant to the FERC’s orders related to the bandwidth payments/receipts for the comprehensive recalculation for 2007, 2008, and 2009. See Note 2 to the financial statements for a discussion of the System Agreement bandwidth remedy payments;

•	an increase of $60.1 million in pension contributions in 2014. 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 $38 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel;

•	the timing of payments to vendors; and

•	an increase of $24.6 million in storm spending in 2014.

•	an increase in transmission construction expenditures primarily due to a higher scope of non-storm related work performed in 2015;

•	an increase in nuclear construction expenditures primarily due to a higher scope of work on various nuclear projects in 2015 as compared to 2014 and compliance with NRC post-Fukushima requirements;

•	an increase in distribution construction expenditures due to a higher scope of work performed in 2015;

•	an increase in information technology capital expenditures due to various technology projects and upgrades in 2015;

•	$11.7 million in insurance proceeds received in 2015 compared to $36.6 million received in 2014 for property damages related to the generator stator incident at ANO, as discussed above; and

•	money pool activity.

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•	a decrease in transmission and distribution construction expenditures primarily due to higher storm restoration spending in 2014; and

•	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.

•	an increase of $101.4 million storm spending in 2014;

•	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

•	proceeds of $10.3 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel.

•	approximately $69 million in spending in 2013 related to the generator stator incident at ANO, as discussed above;

•	$36.6 million in insurance proceeds received in 2014 for property damages related to the generator stator incident at ANO, as discussed above; and

•	money pool activity.

•	the issuance of $250 million of 4.95% Series first mortgage bonds in December 2014;

•	the issuance of $90 million of 9% Series L notes by the nuclear fuel company variable interest entity in July 2014;

•	net repayments of $36.3 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2015 compared to net borrowings of $48 million in 2014; and

•	the issuance of $375 million of 3.7% Series first mortgage bonds in March 2014, the proceeds of which were used to pay, prior to maturities, a $250 million term loan in March 2014 and $115 million of 5.0% Series first mortgage bonds in April 2014.

•	the retirement, at maturity, of $70 million of 5.69% Series I notes by the nuclear fuel company variable interest entity in July 2014;

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•	money pool activity; and

•	$10 million in common stock dividends paid in 2014.

•	the issuance of $375 million of 3.70% Series first mortgage bonds in March 2014;

•	the retirement, at maturity, of $300 million of 5.40% Series first mortgage bonds in August 2013;

•	the issuance of $90 million of 9% Series L notes by the nuclear fuel company variable interest entity in July 2014;

•	the issuance of $250 million of 4.95% Series first mortgage bonds in December 2014;

•	net borrowings of $48 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2014 compared to net repayments of $36.7 million in 2013;

•	the retirement, at maturity, of $30 million of 9% Series H notes by the nuclear fuel company variable interest entity in June 2013; and

•	a decrease of $5 million in common stock dividends paid in 2014.

•	borrowings on a $250 million term loan credit facility entered into in July 2013 and its repayment, prior to maturity, in March 2014;

•	the issuance of $250 million of 3.05% Series first mortgage bonds in May 2013;

•	the issuance of $125 million of 4.75% Series first mortgage bonds in June 2013;

•	the retirement, prior to maturity, of $115 million of 5.0% Series first mortgage bonds in April 2014; and

•	the retirement, at maturity, of $70 million of 5.69% Series I notes by the nuclear fuel company variable interest entity in July 2014.

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

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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 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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•	the $45 million write-off recorded 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 write-off recorded in 2014 due to the uncertainty at the time associated with the resolution of the Waterford 3 replacement steam

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•	an increase of $19.9 million in nuclear generation expenses primarily due to an increased scope of work performed in 2015;

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an increase of $14.6 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefits 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 postretirement benefits costs;

•	an increase of $11 million in transmission expenses primarily due to an increase in the amount of transmission costs allocated by MISO. There is no effect on net income due to the recovery of these costs through the MISO cost recovery mechanism.  See Note 2 to the financial statements for further information on the recovery of these costs;

•	an increase of $9.4 million due to the amortization effective December 2014 of costs related to the transition and implementation of joining the MISO RTO; and

•	an increase resulting from losses of $1.7 million on the sale of surplus diesel inventory in 2015 compared to gains of $5.1 million on the sale of surplus oil inventory and $2.2 million on the sale of surplus diesel inventory in 2014.

•	the decrease in the allowance for borrowed funds used during construction due to a higher construction work in progress balance in 2014, including the Ninemile Unit 6 project, which was placed in service in December 2014;

•	the issuance of $250 million of 4.95% Series first mortgage bonds in November 2014; and

•	the issuance of two series totaling $300 million of 3.78% Series first mortgage bonds in July 2014.

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•	an increase of $17.4 million due to administration fees related to the participation in the MISO RTO effective December 2013. The LPSC approved deferral of these expenses resulting in no net income effect;

•	a $16 million write-off recorded in 2014 because of the uncertainty associated with the resolution of the Waterford 3 replacement steam generator project prudence review. See Note 2 to the financial statements for further discussion of the prudence review;

•	an increase of $15 million in regulatory, consulting, and legal fees;

•	an increase of $9.1 million in nuclear generation expenses primarily due to higher labor costs, including contract labor, higher materials costs, and higher NRC fees;

•	an increase of $8.8 million in fossil-fueled generation expenses primarily due to an overall higher scope of work done during plant outages as compared to prior year;

•	an increase of $3.8 million as a result of higher write-offs of uncollectible accounts in 2014; and

•	several individually insignificant items.

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a decrease of $44.7 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, 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 pension and other postretirement benefits costs; and

•	a decrease of $13.1 million due to costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business.

•	an increase of $12.3 million due to distributions earned on preferred membership interests purchased from Entergy Holdings Company with the proceeds received in August 2014 from the Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;

•	$7.6 million of carrying charges recorded in 2014 on storm restoration costs related to Hurricane Isaac as approved by the LPSC; and

•	the increase in allowance for equity funds used during construction due to a higher construction work in progress balance in 2014, including the Ninemile Unit 6 project.

•	the issuance of $325 million of 4.05% Series first mortgage bonds in August 2013;

•	the issuance of $170 million of 5.0% Series first mortgage bonds in June 2014;

•	the issuance of two series totaling $300 million of 3.78% Series first mortgage bonds in July 2014; and

•	$3.6 million of carrying charges recorded in 2014 on storm restoration costs related to Hurricane Isaac, as approved by the LPSC.

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•	proceeds of $309.5 million received in 2014 from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;

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income tax payments of $89.1 million in 2015 and income tax refunds of $242.4 million in 2014. Entergy Louisiana had income tax payments in 2015 and income tax refunds in 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The 2015 income tax payments are primarily due to adjustments associated with the settlement of the IRS Audit of the 2008-2009 tax years whereas the 2014 income tax refunds are primarily due to favorable adjustments allowed in the IRS Audit of the 2006-2007 tax years and a carryback of a 2008 net operating loss. See Note 3 to the financial statements for a discussion of the income tax audits; and

•	an increase of $17.1 million in spending on nuclear refueling outages in 2015.

•	proceeds of $309.5 million received in 2014 from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;

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•	an increase in income tax refunds of $213.9 million. Entergy Louisiana had income tax refunds in 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds are primarily due to favorable adjustments allowed in the IRS Audit of the 2006-2007 tax years and a carryback of a 2008 net operating loss;

•	the timing of collections from customers; and

•	a decrease of $13.7 million in spending on nuclear refueling outages in 2014 compared to 2013.

•	the investment in 2014 of $293.5 million in affiliate securities as a result of the Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;

•	the deposit of $268.6 million into the storm reserve escrow account in 2014;

•	cash proceeds of $59.6 million 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; and

•	a decrease in fossil-fueled generation construction expenditures primarily due to decreased spending on the Ninemile Unit 6 project, which was placed in service in December 2014.

•	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;

•	an increase in nuclear expenditures primarily due to compliance with NRC post-Fukushima requirements and a higher scope of work on various nuclear projects in 2015;

•	an increase in distribution construction expenditures due to an increased scope of work performed in 2015;

•	an increase in information technology capital expenditures due to various technology projects and upgrades in 2015; and

•	money pool activity.

•	the investment in 2014 of $293.5 million in affiliate securities as a result of the Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;

•	the deposit of $268.6 million into the storm reserve escrow account in 2014; and

•	the withdrawal of $252.5 million from the storm reserve escrow account in 2013.

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•	a decrease in fossil-fueled generation construction expenditures due to lower spending on the Ninemile Unit 6 project;

•	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

•	money pool activity.

•	the retirement of $104 million on long-term debt in 2015 compared to the net issuance of $239.4 million of long-term debt in 2014; and

•	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, which is discussed above.

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

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•	construction and other capital investments;

•	debt and preferred equity maturities or retirements;

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

•	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 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 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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•	authorization to increase the revenue it collects from customers by approximately $24 million;

•	an authorized return on common equity of 10.4%;

•	authorization to increase depreciation rates embedded in the proposed revenue requirement; and,

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authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

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•	authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service);

•	an authorized return on common equity of 10.4%;

•	authorization to increase depreciation rates embedded in the proposed revenue requirement; and

•

authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

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•	a $9.3 million base rate revenue increase to be phased in on a levelized basis over four years;

•	recovery of an additional $853 thousand annually through a MISO recovery rider; and

•	adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.

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•	an increase of $5 million in distribution expenses primarily due to higher vegetation maintenance and higher labor costs in 2015 as compared to 2014;

•	an increase of $4.9 million in energy efficiency costs. These costs began in fourth quarter 2014 and are recovered through the energy efficiency rider having minimal effect on net income;

•	an increase of $4.8 million in fossil-fueled generation expenses primarily due to a higher scope of work done during plant outages in 2015 as compared to 2014;

•	a $2.6 million loss recognized on the disposition of plant components;

•	an increase of $1.8 million in costs incurred in 2014 related to Baxter Wilson (Unit 1) repairs, including an offset for expected insurance proceeds and amortization of the repair costs in 2015 that were deferred in 2014 as approved by the MPSC. See “Baxter Wilson Plant Event” below for a discussion of the Baxter Wilson plant event; and

•

an increase of $1.7 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefits 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 postretirement benefits costs.

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a decrease of $11.6 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, 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 pension and other postretirement benefits costs;

•	a decrease of $7.6 million in fossil-fueled generation expenses primarily due to a lower scope of work done during plant outages in 2014 as compared to the same period in 2013;

•	a decrease of $5.9 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 $5.1 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 the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion; and

•	a net decrease of $3.8 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” below for further discussion.

•	an increase of $10 million in storm damage accruals, as approved by the MPSC, effective October 2013;

•	an increase of $5.1 million in 2014 as compared to 2013 in administration fees related to participation in the MISO RTO;

•	an increase of $4 million in regulatory, consulting, and legal fees;

•	an increase of $2.3 million in distribution and transmission vegetation maintenance;

•	an increase of $1.3 million due to higher write-offs of uncollectible customer accounts in 2014 as compared to 2013; and

•	several individually insignificant items.

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•	increased recovery of fuel costs in 2015;

•	System Agreement bandwidth remedy payments of $16.4 million made in September 2014 as a result of the compliance filing pursuant to the FERC’s orders related to the bandwidth payments/receipts for the 2007 - 2009 period;

•	$15.3 million in insurance proceeds received in 2015 related to the Baxter Wilson plant event. See “Baxter Wilson Plant Event” above for a discussion of the Baxter Wilson plant event; and

•	the timing of collections from customers.

•	an increase of $41.7 million in income tax payments in 2015. Entergy Mississippi had income tax payments in 2015 and 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax payments in 2015 are primarily due to the results of operations

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•	System Agreement bandwidth remedy payments of $11.3 million received in 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period.

•	increased recovery of fuel costs;

•	the timing of collections of receivables from customers; and

•	System Agreement bandwidth remedy payments of $11.3 million received in 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period.

•	System Agreement bandwidth remedy payments made in September 2014 of $16.4 million as a result of the compliance filing pursuant to the FERC’s orders related to the bandwidth payments/receipts for the 2007 - 2009 period;

•	an increase of $15 million in income tax payments in 2014. Entergy Mississippi had income tax payments in 2014 and 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The 2013 and 2014 payments resulted primarily from the reversal of temporary differences for which Entergy Mississippi had previously claimed a tax deduction; and

•	an increase of $13.7 million in pension contributions 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.

•	an increase in transmission construction expenditures primarily due to a higher scope of work done in 2015;

•	an increase in information technology capital expenditures due to various technology projects and upgrades in 2015; and

•	money pool activity

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•	the payment, prior to maturity, of $95 million of 4.95% Series first mortgage bonds in April 2014;

•	an increase of $54 million in common stock dividends paid; and

•	money pool activity.

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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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•	an approximate $16 million net increase in revenues, which reflected an agreed upon 10.07% return on common equity;

•

revision of Entergy Mississippi’s formula rate plan by providing Entergy Mississippi with the ability to reflect known and measurable changes to historical rate base and certain expense amounts; resolving uncertainty around and obviating the need for an additional rate filing in connection with Entergy Mississippi’s withdrawal from participation in the System Agreement; updating depreciation rates; and moving costs associated with the Attala and Hinds generating plants from the power management rider to base rates;

•	recovery of non-fuel MISO-related costs through a separate rider for that purpose;

•

a deferral of $6 million in other operation and maintenance expenses associated with the Baxter Wilson outage and a determination that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset over two years beginning in February 2015, and a provision that the capital costs will be reflected in rate base. See “Baxter Wilson Plant Event” above for further discussion of the Baxter Wilson outage; and

•

consolidation of the new nuclear generation development costs proceeding with the general rate case proceeding for hearing purposes and a determination that Entergy Mississippi would not further pursue, except as noted below, recovery of the costs that were approved for deferral by the MPSC in November 2011. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. See “New Nuclear Generation Development Costs” above for further discussion of the new nuclear generation development costs proceeding and subsequent write-off in 2014 of the regulatory asset related to those costs.

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a decrease of $7.7 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, 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 pension and other postretirement benefits costs;

•	a decrease of $6.7 million in fossil-fueled generation expenses due to an overall lower scope of work done during plant outages as compared to prior year; and

•	a decrease of $2.4 million in outside regulatory consultant fees.

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•	a deposit of $63.9 million into the storm reserve escrow account in July 2015. See “Sources of Capital” below for a discussion of the issuance in July 2015 of securitization bonds to recover storm costs;

•	money pool activity;

•	an increase in transmission construction expenditures primarily due to a higher scope of work performed in 2015 as compared to 2014; and

•	an increase in distribution construction expenditures primarily due to a higher scope of work performed in 2015 as compared to 2014.

•	a decrease in fossil-fueled generation construction expenditures primarily due to spending on the Michoud turbine blade replacement projects in 2013;

•	a decrease in transmission construction expenditures as a result of decreased scope of work in 2014; and

•	money pool activity.

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•	construction and other capital investments;

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

•	debt and preferred stock maturities or retirements; and

•	dividend 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 stock issuances; and

•	bank financing under new or existing facilities.

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•	a $9.3 million base rate revenue increase to be phased in on a levelized basis over four years;

•	recovery of an additional $853 thousand annually through a MISO recovery rider; and

•	adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.

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•	an increase of $7.5 million in transmission expenses primarily due to an increase in the amount of transmission costs allocated by MISO;

•	a net increase of $6.4 million in energy efficiency costs for fixed costs collected from customers. These costs are recovered through the energy efficiency rider and have a minimal effect on net income; and

•	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. See Note 2 to the financial statements for discussion of these proceedings.

•

a decrease of $14.9 million in compensation and benefit costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, and a settlement charge in 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 pension and other postretirement benefits costs;

•	a decrease of $7.4 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business; and

•	a decrease of $7.1 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

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•	income tax payments of $60.4 million in 2015. Entergy Texas had income tax payments in 2015 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement.  The income tax payments in 2015 resulted primarily from the results of operations and the reversal of taxable temporary differences; and

•

a net decrease of $24 million related to the System Agreement bandwidth remedy payments in 2014. In the second quarter 2014, Entergy Texas received total payments of $48.6 million as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period, of which $24.6 million was refunded to Entergy Texas customers as of December 31, 2014.

•	$86.1 million of fuel cost refunds in 2013;

•

System Agreement bandwidth remedy payments of $48.6 million received in the second quarter 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. Entergy Texas received approval to apply a portion of the payments to the under-collected fuel balance. The remaining balance of $24.6 million was refunded to Entergy Texas customers as of December 31, 2014. See Note 2 to the financial statements for a discussion of fuel cost refunds and the System Agreement proceedings; and

•	the timing of collections from customers.

•	a decrease of $54.8 million in income tax refunds in 2014 compared to 2013. Entergy Texas had income tax refunds in 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds in 2013 resulted from the utilization of Entergy Texas’s taxable losses against taxable income of other members of the Entergy consolidated group; and

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•	an increase of $10.2 million in pension contributions in 2014.  See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

•	an increase in transmission construction expenditures primarily due to a greater scope of projects in 2015;

•	an increase in information technology capital expenditures due to various technology projects and upgrades in 2015; and

•	an increase in fossil-fueled generation construction expenditures primarily due to Lewis Creek dam repairs in 2015 and a greater scope of work done during outages in 2015.

•	the issuance of $250 million of 5.15% Series first mortgage bonds in May 2015;

•	the retirement, prior to maturity, of $150 million of 7.875% Series first mortgage bonds in June 2014;

•	$70 million in common stock dividends paid in 2014; 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.

•	internally generated funds;

•	cash on hand;

•	debt or preferred stock issuances; and

•	bank financing under new or existing facilities.

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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;

•	an increase in nuclear construction expenditures primarily as a result of spending on nuclear projects during the Grand Gulf refueling outage in 2014; and

•	money pool activity.

•	an increase of $98.8 million in common stock dividends and distributions;

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

•	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; and

•	net repayments of $20.4 million on the nuclear fuel company variable interest entity’s credit facility in 2015 compared to net borrowings of $20.4 million on the nuclear fuel company variable interest entity’s credit facility in 2014.

•	the redemption of $70 million of 6.29% Series F notes by the nuclear fuel company variable interest entity in September 2013; and

•	net borrowings of $20.4 million on the nuclear fuel company variable interest entity’s credit facility in 2014 compared to net repayments of $40 million on the nuclear fuel company variable interest entity’s credit facility in 2013.

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•	construction and other capital investments;

•	debt maturities or retirements;

•	working capital purposes, including the financing of fuel 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 System Energy, it includes nuclear fuel purchase obligations.

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•	internally generated funds;

•	cash on hand;

•	debt issuances; and

•	bank financing under new or existing facilities.

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

•	long-term borrowings and security issuances; and

•	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 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 set forth above; and

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

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•	Requires a “double trigger” for severance payments or equity acceleration in the event of a change in control

•	Maintains a “clawback” policy that goes beyond Sarbanes-Oxley requirements

•	Caps the maximum payout at 200% of target under the Long-Term Performance Unit Program and under the Annual Incentive Plan for members of the Office of the Chief Executive

•	Requires minimum vesting periods for equity based awards

•	Targets the long-term compensation mix to give more weight to performance units than to time-based restricted stock and stock options combined

•	Settles 100% of long-term performance unit payouts in shares of Entergy stock

•	Requires executives to hold substantially all equity compensation received from Entergy Corporation until stock ownership guidelines are met

•	Prohibits directors and officers from pledging or entering into hedging or other derivative transactions with respect to their Entergy Corporation shares

•	Mitigates undue risk taking in compensation programs

•	Subjects executive officer equity grants to non-compete and non-solicitation covenants

•	No 280(G) tax “gross up” payments in the event of a change in control

•	No tax “gross up” payments on any executive perquisites, other than relocation benefits available to all eligible employees, and club dues for some of the Named Executive Officers

•	No option repricing or cash buy-outs for underwater options under the equity plans

•	No agreements providing for severance payments to executive officers that exceed 2.99 times annual base salary and annual incentive awards without shareholder approval

•	No unusual or excessive perquisites

•	New officers are excluded from participation in the System Executive Retirement Plan

•	No grants of supplemental service credit for newly-hired officers under any of Entergy Corporation’s non-qualified retirement plans

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•	125% for Mr. Denault;

•	70% for Mr. Bunting, Mr. Marsh, and Mr. West;

•	60% for Mr. May;

•	50% for Mr. McDonald; and

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

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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.

(2)	Reflects downward adjustment by Personnel Committee, as further described below.

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(1)	Messrs. Denault, Marsh and May received pro-rated awards for the 2013-2015 performance cycles as a result of their promotions in 2013.

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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

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•	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 the restricted stock 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 the 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. Bunting was not a Named Executive Officer in 2014 and 2013.

(2)	The amounts in column (c) represent the actual base salary paid to the Named Executive Officer.  The 2015 changes in base salaries noted in the Compensation Discussion and Analysis were effective in April 2015. The Named Executive Officers are paid on a bi-weekly basis and during 2015 there was an extra pay period at Entergy Arkansas and Entergy Mississippi.

(3)	The amounts in column (d) in 2013 for Mr. Fisackerly, Mr. May, Mr. McDonald, Ms. Rainer, and Mr. Rice represent a cash bonus paid in recognition of their work supporting the move to MISO.

(4)

The amounts in column (e) represent the aggregate grant date fair value of restricted stock and performance units granted under the 2011 Equity Ownership Plan and restricted stock units granted under the 2015 Equity Ownership Plan, each calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures.  The grant date fair value of the restricted stock and the 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 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 2015 are as follows:  Mr. Bunting, $1,177,690; Mr. Denault, $5,951,380; Mr. Fisackerly, $260,710; Mr. Marsh, $1,177,690; Mr. May, $368,590; Mr. McDonald, $260,710; Ms. Rainer, $260,710; Mr. Rice, $260,710; and Mr. West, $1,177,690.

(5)	The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the 2011 Equity Ownership Plan calculated in accordance with FASB ASC Topic 718.  For a discussion of the relevant assumptions used in valuing these awards, see Note 12 to the financial statements.

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

(7)

For all of the Named Executive Officers, the amounts in column (h) include the annual actuarial increase in the present value of the 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 “2015 Pension Benefits”).  None of the increase is attributable to above-market or preferential earnings on non-qualified deferred compensation (see “2015

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(8)	The amounts in column (i) for 2015 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 (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.

(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 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, 2017.)  Accrued dividends on the shares earned will also be paid in Entergy Corporation common stock.

(3)	Except as otherwise noted in footnote 6, the amounts in column (i) represent shares of restricted stock granted under the 2011 Equity Ownership Plan.  Shares of restricted stock vest one-third on each of the first through third anniversaries of the grant, 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 2011 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

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(6)	In August 2015, Mr. Marsh was awarded 21,100 restricted stock units under the 2015 Equity Ownership Plan. The restricted stock units will vest on August 3, 2020.

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(1)	Consists of options that vested or will vest as follows: 1/3 of the options granted vest on each of 1/29/2016, 1/29/2017, and 1/29/2018.

(2)	Consists of options that vested or will vest as follows: 1/2 of the remaining unexercisable options vest on each of 1/30/2016 and 1/30/2017.

(3)	The remaining unexercisable options vested on 1/31/2016.

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(4)	Consists of performance units that will vest on December 31, 2017 based on Entergy Corporation’s total shareholder return performance over the 2015-2017 performance period, as described under “What Entergy Corporation Pays and Why- Executive Compensation Elements - Long-Term Incentive Compensation - Performance Unit Program” in Compensation Discussion and Analysis.

(5)	Consists of performance units that will vest on December 31, 2016 based on Entergy Corporation’s total shareholder return performance over the 2014-2016 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 1/29/2016, 1/29/2017, and 1/29/2018.

(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 1/30/2016 and 1/30/2017.

(8)	Consists of shares of restricted stock that vested on 1/31/2016.

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

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

(1)	Represents the value of performance units for the 2013-2015 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 2015.

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

(2)	During 2006, Mr. Denault entered into an 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 Entergy other than for cause (as defined in the retention agreement), by Mr. Denault for good

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

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(1)	As of December 31, 2015, Mr. Bunting, Mr. Denault, and Mr. McDonald are retirement eligible and would retire rather than voluntarily resign.

(2)

In addition to the payments and benefits in the table, Mr. Denault also would have been entitled to receive his vested pension benefits. If Mr. Denault’s employment was terminated by Entergy Corporation 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. Otherwise, if Mr. Denault’s employment was terminated for cause or he was to retire from Entergy Corporation before age 65 without the permission of his Entergy System employer, he would not receive a benefit under the System Executive Retirement Plan. For a description of these benefits, see “2015 Pension Benefits.”

(3)

In addition to the payments and benefits in the table, Mr. Bunting and Mr. McDonald each would have been eligible to retire and entitled to receive his vested pension benefits. For a description of the pension benefits available, see “2015 Pension Benefits.” In the event of a termination by Entergy Corporation without cause or by the executive for good reason in connection with a change in control, Mr. Bunting and Mr. McDonald each would be eligible for subsidized early retirement benefits under the System Executive Retirement Plan even if he does not have permission from his Entergy System employer to separate from employment. If Mr. Bunting’s and Mr. McDonald’s employment were terminated for cause or they were to retire from Entergy Corporation before age 65 without the permission of their Entergy System employer, they would not receive a benefit under the System Executive Retirement Plan.

(4)

In addition to the payments and benefits in the table, if a Named Executive Officer’s, other than Messrs. Denault, Bunting, and McDonald, employment were terminated under certain conditions relating to a change in control, each also would have been entitled to receive his or her vested pension benefits upon attainment of age 55 and would have been eligible for early retirement benefits under the System Executive Retirement Plan

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(5)

In the event of a termination (not due to death or disability) by the executive for good reason or by Entergy Corporation 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 for Messrs. Denault, Bunting, Marsh, and West 2.99 times the product of, for Mr. May 2 times the product of, and Messrs. Fisackerly, McDonald, Rice, and Ms. Rainer the product of 1 time 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) his or her annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive for 2013 and 2014 (the two calendar years immediately preceding the calendar year in which his or her termination occurs). For purposes of this table, we assume the following target opportunity and base salary:

(6)

In the event of a termination due to death or disability, by Mr. Denault for good reason, or by Entergy Corporation not for cause (in all cases, regardless of whether there is a change in control), Mr. Denault would have forfeited his performance units for all open performance periods and would have been entitled to receive a single-lump sum calculated using the average annual number of performance units he would have been entitled to receive under the Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which his termination occurs, assuming all performance goals were achieved at target. For purposes of the table, the value of Mr. Denault’s payment was calculated by taking an average of the target performance units from the 2011-2013 Performance Unit Program (26,000 units) and the 2012-2014 Performance Unit Program (26,900 units). This average number of units (26,450 units) multiplied by the closing price of Entergy Corporation stock on December 31, 2015 ($68.36) would equal a payment of $1,808,122 for the forfeited performance units.

(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 2014-2016 and 2015-2017 performance periods and would have been entitled to receive, pursuant to the 2011 Equity Ownership Plan, a single-lump sum payment that would not be based on any outstanding performance periods. For both the 2014-2016 and 2015-2017 performance periods, the payment would have been calculated using the average annual number of performance units he or she would have been entitled to receive under each Performance Unit Program with respect to the two most recent performance periods preceding (but not including) the calendar year in which his or her termination occurs, assuming all performance goals were achieved at target multiplied by the closing price of Entergy Corporation stock on December 31, 2015. For purposes of the table, the value of Mr. Denault’s

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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. Denault, Mr. Bunting, or Mr. McDonald, all of the unvested stock options of each Named Executive Officer would immediately vest pursuant to the 2011 Equity Ownership Plan. In addition, each would be

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(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 twelve (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 twelve (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, the Named Executive Officers would immediately vest in all of their unvested restricted stock (as well as dividends declared on such restricted stock).

(10)	Upon retirement, Mr. Denault, Mr. Bunting, and Mr. McDonald would be eligible for retiree medical and dental benefits, the same as all other retirees. Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Messrs. Denault, Bunting, and McDonald would not be eligible to receive Entergy Corporation subsidized COBRA benefits.

(11)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Marsh, Mr. May, and Mr. West would be eligible to receive Entergy Corporation-subsidized COBRA benefits for 18 months and Mr. Fisackerly, Ms. Rainer, and Mr. Rice would be eligible to receive Entergy Corporation-subsidized COBRA benefits for 12 months.

(12)

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 Entergy Corporation 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.

(13)

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 for a reason other than cause, total disability or death. In the event of a change in control, the units will vest upon termination of Mr. West’s employment by Entergy Corporation without cause or by Mr. West with good reason during a change in control period (as defined in the 2011 Equity Ownership Plan). If Mr. West voluntarily resigns or is terminated for cause, he would forfeit these units.

•	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;

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•	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);

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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 or her under any of Entergy Corporation’s pension, savings, life insurance, medical, health and accident, disability, or vacation plans 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 common stock or the combined voting power of its 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 the Board at the end of the period.

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

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

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

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•	any person or entity becomes the beneficial owner (directly or indirectly) of outstanding shares of common stock of Entergy Corporation constituting 20% 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 the 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 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 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

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

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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 Board. These phantom units do not have voting rights, accrue dividends, and will be settled in shares of Entergy 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. Edwards and Hintz 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.

(1)	Includes the Equity Ownership Plan, which was approved by the shareholders on May 15, 1998, the 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, and the 2015 Equity Ownership Plan.  The 2007 Equity

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(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, 2015, all options outstanding under the plan were either exercised or expired.

•	Whether the proposed transaction is on terms at least as favorable to Entergy Corporation or the subsidiary as those could be achieved with an unaffiliated third party;

•	Size of 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 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 2015 and 2014 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 the only qualified provider of that service or if the Audit Committee specifically requests 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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