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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 in November 2015, the termination of Entergy Texas’s, Entergy Gulf States Louisiana's, and Entergy Louisiana's participation in the System Agreement after expiration of the recently proposed 60-month notice period or such other period as approved by the FERC;

•	regulatory and operating challenges and uncertainties associated with the Utility operating companies’ move to the MISO RTO, which occurred in December 2013;

•	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 regulation of nuclear generating facilities and nuclear materials and fuel, including with respect to the planned or potential shutdown of nuclear generating facilities owned or operated by the Entergy Wholesale Commodities business, 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 of nuclear generating facilities;

•	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;

•	volatility and changes in markets for electricity, natural gas, uranium, and other energy-related commodities;

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

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•	changes in environmental, tax, and other laws, including requirements for reduced emissions of sulfur, nitrogen, carbon, greenhouse gases, mercury, 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;

•	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 that could influence economic conditions in those areas;

•	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 potential effects of threatened or actual terrorism, cyber-attacks or data security breaches, including increased security costs, 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 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 or cost to decommission nuclear plant sites;

•	the implementation of the shutdown of Vermont Yankee by the end of 2014 and the related decommissioning of 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 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 operates a small natural gas distribution business.

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The Entergy Wholesale Commodities business segment includes the ownership and operation of six nuclear power plants located in the northern United States and the sale of the electric power produced by those plants to wholesale customers.  In August 2013, Entergy announced plans to close and decommission Vermont Yankee. The plant is expected to cease power production in the fourth quarter 2014 after its current fuel cycle. This business also provides services to other nuclear power plant owners. Entergy Wholesale Commodities also owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.

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a formula rate plan increase at Entergy Louisiana, effective January 2013, which includes an increase relating to the Waterford 3 steam generator replacement project, which was placed in service in December 2012. The net income effect of the formula rate plan increase is limited to a portion representing an allowed return on equity with the remainder offset by costs included in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes;

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the recovery of Hinds plant costs through the power management rider at Entergy Mississippi, as approved by the MPSC, effective with the first billing cycle of 2013. The net income effect of the Hinds plant cost recovery is limited to a portion representing an allowed return on equity on the net plant investment with the remainder offset by the Hinds plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes;

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an increase in the capacity acquisition rider at Entergy Arkansas, as approved by the APSC, effective with the first billing cycle of December 2012, relating to the Hot Spring plant acquisition. The net income effect of the Hot Spring plant cost recovery is limited to a portion representing an allowed return on equity on the net plant investment with the remainder offset by the Hot Spring plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes;

•	increases in the energy efficiency rider, as approved by the APSC, effective July 2013 and July 2012. Energy efficiency revenues are offset by costs included in other operation and maintenance expenses and have no effect on net income;

•	an annual base rate increase at Entergy Texas, effective July 2012, as a result of the PUCT’s order that was issued in September 2012 in the November 2011 rate case; and

•	a formula rate plan increase at Entergy Mississippi, effective September 2013.

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•	the deferral of increased capacity costs that will be recovered through fuel adjustment clauses;

•	the expiration of the Evangeline gas contract on January 1, 2013; and

•	an adjustment to deferred fuel costs recorded in the third quarter 2012 in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of this PUCT order issued in Entergy Texas's 2011 rate case.

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the effect of rising forward power prices on electricity derivative instruments that are not designated as hedges, including additional financial power sales conducted in the fourth quarter 2013 to offset the planned exercise of in-the-money protective call options and to lock in margins. These additional sales did not qualify for hedge accounting treatment, and increases in forward prices after those sales were made accounted for the majority of the negative mark-to-market variance. It is expected that the underlying transactions will result in earnings in first quarter 2014 as these positions settle. See Note 16 to the financial statements for discussion of derivative instruments;

•	the decrease in net revenue compared to prior year resulting from the exercise of resupply options 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; and

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•	higher nuclear fuel expenses primarily resulting from the effect of the write-down in March 2012 of the carrying value of Vermont Yankee's nuclear fuel, which resulted in a lower level of nuclear fuel amortization in 2012, and the subsequent purchase of additional nuclear fuel in early-2013.

(a)	The reduction in owned capacity is due to the retirement of the 544 MW Ritchie Unit 2 in November 2013.

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an increase of $83 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs 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;

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an increase of $46 million in fossil-fueled generation expenses primarily due to the acquisitions of the Hot Spring plant by Entergy Arkansas and the Hinds plant by Entergy Mississippi in November 2012. Costs related to the Hot Spring and Hinds plants are recovered through the capacity acquisition rider and power management rider, respectively, as previously discussed. Also contributing to the increases is an overall higher scope of work done during plant outages as compared to the prior year;

•	an increase of $72 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative, partially offset by the deferral of approximately $44 million of these costs. See the "Human Capital Management Strategic Imperative" below for further discussion;

•	an increase of $16 million in energy efficiency costs at Entergy Arkansas. These costs are recovered through an energy efficiency rider and have no effect on net income;

•	an increase of $13 million in nuclear expenses, primarily due to higher labor costs, including higher contract labor;

•	the deferral in 2012, as approved by the LPSC and the FERC, of costs related to the transition and implementation of joining the MISO RTO, which reduced 2012 expenses by $10 million; and

•	an increase of $9 million resulting from costs related to the generator stator incident at ANO, including an offset for expected insurance proceeds. See “ANO Damage and Outage” below for further discussion of the incident.

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an increase of $43 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs 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;

•	an increase of $23 million primarily due to the effect of the final court decisions in the Vermont Yankee and Indian Point 2 lawsuits against the U.S. Department of Energy related to spent nuclear fuel disposal recorded in 2012. The damages awarded included the reimbursement of approximately $25 million of spent nuclear fuel storage costs previously recorded as operation and maintenance expenses;

•	an increase of $16 million resulting from implementation and severance costs in 2013 related to the human capital management strategic imperative. See "Human Capital Management Strategic Imperative" below for further discussion; and

•	approximately $15 million in commitments recorded in connection with the settlement agreement with parties in Vermont regarding the operation and decommissioning of Vermont Yankee. See "Impairment of Long-Lived Assets" in Note 1 to the financial statements for further discussion of the settlement agreement.

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•	an increase in the storm cost recovery rider at Entergy Mississippi, as approved by the MPSC for a five-month period effective August 2012. This increase is offset by costs included in other operation and maintenance expenses and has no effect on net income;

•	an increase in the energy efficiency rider at Entergy Arkansas, as approved by the APSC, effective July 2012. This increase is offset by costs included in other operation and maintenance expenses and has no effect on net income;

•	a special formula rate plan rate increase at Entergy Louisiana effective May 2011 in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center. See Note 2 to the financial statements for a discussion of the formula rate plan increase; and

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•	base rate increases at Entergy Texas beginning May 2011 as a result of the settlement of the December 2009 rate case and effective July 2012 as a result of the PUCT’s order in the December 2011 rate case. See Note 2 to the financial statements for further discussion of the rate cases.

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•	an increase of $47 million in compensation and benefits costs primarily due to decreasing discount rates and changes in certain actuarial assumptions resulting from an experience study. See "Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits" below and Note 11 to the financial statements for further discussion of benefits costs;

•	$38 million of costs incurred in 2012 related to the now terminated plan to spin off and merge the Utility’s transmission business;

•	an increase of $29 million in nuclear expenses primarily due to higher labor costs, including higher contract labor;

•	an increase of $21 million resulting from a temporary increase in the Entergy Mississippi storm damage reserve authorized by the MPSC effective August 2012. These costs included are recovered through the storm cost recovery rider and have no effect on net income;

•	an increase of $14 million in energy efficiency costs at Entergy Arkansas. These costs are recovered through the energy efficiency rider and have no effect on net income;

•	the deferral in 2011 of $13.4 million of 2010 Michoud plant maintenance costs pursuant to the settlement of Entergy New Orleans’ 2010 test year formula rate plan filing approved by the City Council in September 2011. See Note 2 to the financial statements for further discussion of the Entergy New Orleans 2010 test year formula rate plan filing and settlement; and

•	an increase of $10 million in operating expenses due to the sale of surplus oil inventory in 2011.

•	a decrease of approximately $7 million as a result of the deferral or capitalization of storm restoration costs for Hurricane Isaac, which hit the Utility’s service area in August 2012;

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•	the effect of the deferral, as approved by the FERC, and the LPSC for the Louisiana jurisdictions, of costs related to the transition and implementation of joining the MISO RTO, which reduced expenses by $10 million; and

•	a decrease of $9 million in legal expenses, not including legal costs related to the transition and implementation of joining the MISO RTO and the now terminated plan to spin off and merge the Utility’s transmission business which are included in other bullets, primarily resulting from a decrease in legal and regulatory activity decreasing the use of outside legal services.

•	an increase of $23 million in compensation and benefits costs primarily due to decreasing discount rates and changes in certain actuarial assumptions resulting from an experience study. See "Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits " below and Note 11 to the financial statements for further discussion of benefits costs;

•	an increase of $23 million primarily due to higher contract labor costs and higher material and supply costs; and

•	an increase of $20 million due to the operations of the Rhode Island State Energy Center, which was acquired in December 2011.

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

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(a)	The interest rate is the rate as of December 31, 2013 that would be applied to outstanding borrowings under the facility.

(b)	The credit facility requires Entergy Arkansas to maintain a debt ratio of 65% or less of its total capitalization.  Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable.

(c)	The credit facility allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2013, $0.2 million in letters of credit were outstanding.  The credit facility requires Entergy Arkansas to maintain a consolidated debt ratio of 65% or less of its total capitalization.

(d)	The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2013, $15.2 million in letters of credit were outstanding.  The credit facility requires Entergy Gulf States Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization.

(e)	The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2013, $7.0 million in letters of credit were outstanding.  The credit facility requires Entergy Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization.

(f)	The credit facilities require Entergy Mississippi to maintain a debt ratio of 65% or less of its total capitalization. Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable.

(g)	The credit facility requires Entergy New Orleans to maintain a debt ratio of 65% or less of its total capitalization.

(h)	The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2013, $25 million in letters of credit were outstanding.  The credit facility requires Entergy Texas to maintain a consolidated debt ratio of 65% or less of its total capitalization.

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

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

•	permit the continued commercial operation of Grand Gulf;

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

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

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•	The currently planned construction or purchase of additional generation supply sources within the Utility’s service territory through the Utility’s portfolio transformation strategy, including a self-build option at Entergy Louisiana’s Ninemile site identified in the Summer 2009 Request for Proposal, discussed below.

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

•	Environmental compliance spending. Entergy continues to review potential environmental spending needs and financing alternatives for any such spending, and future spending estimates could change based on the results of this continuing analysis and the implementation of new environmental laws and regulations.

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

•	Transmission spending to support economic development projects.

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•	internally generated funds;

•	cash on hand ($739 million as of December 31, 2013);

•	securities issuances;

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

•	sales of assets.

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•	increased recovery of deferred fuel costs;

•	higher Utility net revenues in 2013 resulting from additional generation investments made in 2012;

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

•	a decrease of approximately $84 million in storm restoration spending in 2013 due to Hurricane Isaac in August 2012, offset by an increase of approximately $23 million in storm restoration spending in 2013 due to the Arkansas December 2012 winter storm;

•	a refund of $30.6 million, including interest, paid to AmerenUE in June 2012. The FERC ordered Entergy Arkansas to refund to AmerenUE the rough production cost equalization payments previously collected. See Note 2 to the financial statements for further discussion of the FERC order; and

•	a decrease of $14 million in spending on nuclear refueling outages in 2013 as compared to the same period in prior year.

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•	an increase of $79 million in income tax payments primarily due to state income tax effects of the settlement of the 2004-2005 IRS audit in the fourth quarter 2012;

•	an increase of $52 million in lump sum retirement payments out of the non-qualified pension plan, partially offset by a decrease of $7 million in pension contributions. See "Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits" below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;

•	the decrease in Entergy Wholesale Commodities net revenue that was discussed previously; and

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

•	the decrease in Entergy Wholesale Commodities net revenue that is discussed previously;

•	Hurricane Isaac storm restoration spending of $98 million in 2012;

•	income tax payments of $49.2 million in 2012 compared to income tax refunds of $2 million in 2011. The income tax payments in 2012 were primarily due to state income tax effects of the settlement of the 2006-2007 IRS audit; and

•	a refund of $30.6 million, including interest, paid to AmerenUE in June 2012. The FERC ordered Entergy Arkansas to refund to AmerenUE the rough production cost equalization payments previously collected. See Note 2 to the financial statements for further discussion of the FERC order.

•	the acquisitions of the Hot Spring plant by Entergy Arkansas and the Hinds plant by Entergy Mississippi in November 2012. See Note 15 to the financial statements for further discussion of these plant acquisitions;

•	the withdrawal of a total of $260 million from storm reserve escrow accounts in 2013, primarily by Entergy Gulf States Louisiana and Entergy Louisiana, after Hurricane Isaac. See Note 2 to the financial statements for a discussion of Hurricane Isaac;

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a decrease in construction expenditures, primarily in the Utility business, resulting from spending in 2012 on the uprate project at Grand Gulf and storm restoration spending in 2012 resulting from the Arkansas December 2012 winter storm and Hurricane Isaac, substantially offset by spending in 2013 on the Ninemile 6 self-build project and spending in 2013 related to the generator stator incident at ANO, as discussed previously. Entergy’s construction spending plans for 2014 through 2016 are discussed further in “Capital Expenditure Plans and Other Uses of Capital” above; and

•	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.

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•	a change in collateral deposit activity, reflected in the “Decrease (increase) in other investments” line on the Consolidated Statement of Cash Flows, as Entergy returned $50 million more net deposits in 2013 than 2012. Entergy Wholesale Commodities’s forward sales contracts are discussed in the “Market and Credit Risk Sensitive Instruments” section below; and

•	proceeds of $21 million in 2013 compared to proceeds of $109 million in 2012 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel.

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a decrease of $190 million in payments for the purchase of plants resulting from the purchase of the Hot Spring Energy Facility by Entergy Arkansas for approximately $253 million in November 2012, the purchase of the Hinds Energy Facility by Entergy Mississippi for approximately $206 million in November 2012, the purchase of the Acadia Power Plant by Entergy Louisiana for approximately $300 million in April 2011, and the purchase of the Rhode Island State Energy Center for approximately $346 million by an Entergy Wholesale Commodities subsidiary in December 2011. These transactions are described in more detail in Note 15 to the financial statements;

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

•	a decrease in nuclear fuel purchases because of 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.

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long-term debt activity using approximately $69 million of cash in 2013 compared to providing $348 million of cash in 2012. The most significant long-term debt activity in 2013 included the net issuance of approximately $520 million of long-term debt at the Utility operating companies and System Energy and Entergy Corporation decreasing borrowings outstanding on its long-term credit facility by $540 million. Entergy Corporation issued $380 million of commercial paper in 2013 and $665 million in 2012, in part, to repay borrowings on its long-term credit facility;

•	a net decrease of $136 million in short-term borrowings by the nuclear fuel company variable interest entities; and

•	$51 million in proceeds from the sale to a third party in 2012 of a portion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests.

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long-term debt activity provided approximately $348 million of cash in 2012 compared to $554 million of cash in 2011. The most significant long-term debt activity in 2012 included the net issuance of $1.1 billion of long-term debt at the Utility operating companies and System Energy, the issuance of $500 million of senior notes by Entergy Corporation, and Entergy Corporation decreasing borrowings outstanding on its long-term credit facility by $1.1 billion. Entergy Corporation issued $665 million of commercial paper in 2012 to repay borrowings on its long-term credit facility;

•	Entergy repurchasing $235 million of its common stock in 2011, as discussed below;

•	a net increase in 2012 of $51 million in short-term borrowings by the nuclear fuel company variable interest entities; and

•	$51 million in proceeds from the sale to a third party in 2012 of a portion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests.

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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.

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•	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 issuances of debt.  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.

(b)	Transaction under which power is supplied from a specific generation asset; if the asset is not operating, seller is generally not liable to buyer for any damages.

(c)

A sale of power on a unit-contingent basis coupled with a guarantee of availability provides 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.

(d)	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.

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

(f)	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.

(g)

Assumes NRC license renewals for plants whose current licenses expire within five years. Assumes shutdown of Vermont Yankee in the fourth quarter 2014 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 extended operations) and Indian Point 3 (December 2015). For a discussion regarding the shutdown of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements. For a discussion regarding the license renewals for Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” above.

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

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

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

(k)

Contracts priced in accordance with cost-based rates, a ratemaking concept used for the design and development of rate schedules to ensure that the filed rate schedules recover only the cost of providing the service; these contracts are on owned non-utility resources located within Entergy’s Utility service area and were executed prior to receiving market-based authority under MISO. The percentage sold assumes approval of long-term transmission rights.

(l)

Non-nuclear planned generation and net MW in operation include purchases from affiliated and non-affiliated counterparties under long-term contracts and exclude energy and capacity from Entergy Wholesale Commodities’s wind investment and from the 544 MW Ritchie plant that Entergy retired in November 2013. The decrease in planned net MW in operation beginning in 2017 is due to the expiration of a non-affiliated 75 MW contract.

(m)	Includes expectations for the new New York ISO Lower Hudson Valley capacity zone starting in May 2014.

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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. A high probability that the plant’s license will be renewed and the plant will operate for some time beyond the original license term has been assumed for purposes of calculating the decommissioning liability for a number of Entergy’s nuclear units. 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 3.25%. A 50 basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 9% to 18%. The timing assumption influences the effect of a

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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 damages 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, when applicable. These estimates could change in the future, however, based on the timing 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 a current credit-adjusted risk-free rate. Decreases in estimated cash flows are discounted using the previously-used credit-adjusted risk-free rate. Therefore, to the extent that one of the factors noted above results in a significant increase in estimated cash flows, current interest rates will affect the calculation of the present value of the additional 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 impacted by factors unique to those assets.

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

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

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•	Discount rates used in determining future benefit obligations;

•	Projected health care cost trend rates;

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

•	Rate of increase in future compensation levels;

•	Retirement rates; and

•	Mortality rates.

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•	A 40% excise tax on per capita medical benefit costs that exceed certain thresholds;

•	Change in coverage limits for dependents; and

•	Elimination of lifetime caps.

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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 Gulf States Louisiana.  The investment and accumulated depreciation numbers above are only for the common facilities and not for the generating units.

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(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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(a)

The jurisdictional split order assigned the regulatory asset to Entergy Texas.  The regulatory asset, however, is being recovered and amortized at Entergy Gulf States 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 Gulf States Louisiana and Entergy Gulf States 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)	2013 and 2012 include $100.1 million for Entergy Gulf States Louisiana, $68 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 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,

•

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

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

•

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

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

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(a)	See "Income Tax Audits - 2006-2007 IRS Audit" below for discussion of these items.

(b)	See "Income Tax Audits - 2004-2005 IRS Audit" below for discussion of this item.

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(c)	See "Income Tax Audits - 2008-2009 IRS Audit" below for discussion of the most significant items in 2013 and 2012.

(a)	See "Income Tax Audits - 2006-2007 IRS Audit" below for discussion of these items.

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(a)	See "Income Tax Audits - 2006-2007 IRS Audit" below for discussion of these items.

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(a)	See "Income Tax Audits - 2006-2007 IRS Audit" below for discussion of these items.

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

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(a)	The capacity decreases to $3,490 in March 2017.

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(a)	The interest rate is the rate as of December 31, 2013 that would be applied to outstanding borrowings under the facility.

(b)	The credit facility requires Entergy Arkansas to maintain a debt ratio of 65% or less of its total capitalization.  Entergy Arkansas is in compliance with this covenant. Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable.

(c)	The credit facility allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2013, $0.2 million in letters of credit were outstanding.  The credit facility requires Entergy Arkansas to maintain a consolidated debt ratio of 65% or less of its total capitalization. Entergy Arkansas is in compliance with this covenant.

(d)

The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2013, $15.2 million in letters of credit were outstanding.  The credit facility requires Entergy Gulf States Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization. Entergy Gulf States Louisiana is in compliance with this covenant.

(e)	The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2013, $7.0 million in letters of credit were outstanding.  The credit facility requires Entergy Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization. Entergy Louisiana is in compliance with this covenant.

(f)	The credit facilities require Entergy Mississippi to maintain a debt ratio of 65% or less of its total capitalization. Entergy Mississippi is in compliance with this covenant. Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable.

(g)	The credit facility requires Entergy New Orleans to maintain a debt ratio of 65% or less of its total capitalization. Entergy New Orleans is in compliance with this covenant.

(h)	The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility.  As of December 31, 2013, $25 million in letters of credit were outstanding.  The credit facility requires Entergy Texas to maintain a consolidated debt ratio of 65% or less of its total capitalization. Entergy Texas is in compliance with this covenant.

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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 Gulf States Louisiana 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 $149 million at Entergy Louisiana and $97 million at System Energy, long-term DOE obligations of $181 million at Entergy Arkansas, and the note payable to NYPA of $95 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.

•	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

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•	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 $149 million at Entergy Louisiana and $97 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)

Upon the sale of Class B preferred shares in December 2009, Entergy Asset Management had issued and outstanding Class A and Class B preferred shares.  On December 20, 2011, Entergy Asset Management purchased all of the outstanding Class B preferred shares from the holder thereof; currently, there are no outstanding Class B preferred shares.  On December 20, 2011, Entergy Asset Management purchased all of the outstanding Class A preferred shares (278,905 shares) that were held by a third party; currently, there are 4,759 shares held by an Entergy affiliate.

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

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(a)	Series is callable at par.

(b)	Series is callable at par on and after December 15, 2015.

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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 $19.0 million per year per incident per nuclear power reactor.

3.

In the event that one or more acts of terrorism cause a nuclear power plant accident, which results in third-party damages – off-site property and environmental damage, off-site bodily injury, and on-site third-party bodily injury (i.e. contractors); the primary level provided by ANI combined with the Secondary Financial Protection would provide $13.6 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.

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

•	Excess Layer (per plant)  - $750 million per occurrence

•	Blanket Layer (shared among the Utility plants) - $350 million per occurrence

•	Total limit - $1.6 billion per occurrence

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•	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

•	Excess Layer - $615 million per occurrence

•	Total limit - $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

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

•	Excess Layer - $1.1 billion 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

•	$2.95 million weekly indemnity

•	$413 million maximum indemnity

•	Deductible:  26 week deductible period

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

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

•	Deductible:  26 week deductible period

•	$4.5 million weekly indemnity

•	$490 million maximum indemnity

•	Deductible: 12 week deductible period

•	$4.0 million weekly indemnity

•	$490 million maximum indemnity

•	Deductible: 12 week deductible period

•	$3.5 million weekly indemnity

•	$435 million maximum indemnity

•	Deductible: 12 week deductible period

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

•

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

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

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

(b)	Common stocks, treasury notes and bonds, and certain preferred stocks and fixed income debt securities 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 the 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.

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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 amounts of $47 million posted and $4 million held as of December 31, 2013 and $56 million held as of December 31, 2012

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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.

•

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

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

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

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

-	inputs that are derived principally from or corroborated by observable market data

•	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 for additional information on the investment portfolios.

(b)	Commingled equity funds may be redeemed bi-monthly.

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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 for additional information on the investment portfolios.

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(a)	Includes $3.3 million in 2013, $1.4 million in 2012, and $1.2 million in 2011 for power purchased from Entergy Power.

(b)	Includes power purchased from RS Cogen of $3.2 million in 2013, $2.8 million in 2012, and $41.1 million in 2011.

(c)	Includes power purchased from Entergy Power of $8.1 million in 2013, $14.3 million in 2012, and $14.5 million in 2011.

(d)	Includes power purchased from Entergy Power of $8.0 million in 2013, $14.1 million in 2012, and $14.2 million in 2011.

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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 operates a small natural gas distribution business.

•

The Entergy Wholesale Commodities business segment includes the ownership and operation of six nuclear power plants located in the northern United States and the sale of the electric power produced by those plants to wholesale customers.  In August 2013, Entergy announced plans to close and decommission Vermont Yankee. The plant is expected to cease power production in the fourth quarter 2014 after its current fuel cycle. This business also provides services to other nuclear power plant owners.  Entergy Wholesale Commodities also owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.

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(a)	Excludes the Algiers area of the city, where Entergy Louisiana provides electric service.

(a)	Includes the effect of intercompany eliminations.

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(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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(a)	Includes a conditional option to increase the capacity up to the upper bound of the range.

(b)	The contracted capacity increased from 101 MW to 121 MW in 2010.

(c)

This table does not reflect (i) the River Bend 30% life-of-unit purchased power agreements totaling approximately 300 MW between Entergy Gulf States Louisiana and Entergy Louisiana (200 MW), and between Entergy Gulf States Louisiana and Entergy New Orleans (100 MW) related to Entergy Gulf States Louisiana's unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun or (ii) the Entergy Arkansas wholesale base load capacity life-of-unit purchased power agreements 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 were not included in retail rates); or (iii) 12-month agreements originally executed in 2005 and which are renewed annually between Entergy Arkansas and Entergy Gulf

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(d)	Entergy Louisiana's June 2005 purchase of the 718 MW, gas-fired Perryville plant, of which a total of 75% of the output is sold to Entergy Gulf States Louisiana and Entergy Texas.

(e)	In 2011, the LPSC approved Entergy Louisiana’s cancellation of the Little Gypsy Unit 3 re-powering project selected from the 2006 Long-Term RFP.

(f)	Entergy Arkansas’s September 2008 purchase of the 789 MW, combined-cycle, gas-fired Ouachita Generating Facility, of which one-third of the output was sold to Entergy Gulf States Louisiana prior to the purchase of one-third of the facility by Entergy Gulf States Louisiana in November 2009.

(g)

At the direction of the LPSC, but with full reservation of all legal rights, Entergy Services issued the January 2008 RFP for Supply-Side Resources seeking fixed price unit contingent products.  Although the LPSC request was directed to Entergy Gulf States Louisiana and Entergy Louisiana, Entergy Services issued the RFP on behalf of all of the Utility operating companies.  No proposals were selected from this RFP.

(h)	In October 2008, in response to the U.S. financial crisis, Entergy Services on behalf of the Utility operating companies terminated all long-term procurement efforts, including the long-term portion of the Summer 2008 RFP.

(i)	Represents the self-supply alternative considered in the RFP, consisting of a cost-based purchase by Entergy Texas, Entergy Louisiana, and Entergy Mississippi of wholesale baseload capacity from Entergy Arkansas.

(j)	Includes the Ninemile self-build option, acquisitions from KGen of its Hinds and Hot Spring facilities, and a long-term PPA with Calpine Carville.

(k)	Three transactions executed as a result of the RFP are reflected in the table, however one transaction is still pending regulatory approval.

(l)	Negotiations with the potential supplier for a definitive agreement arising out of the 2011 Western Region RFP have been discontinued. Entergy Texas does not intend to pursue any other proposal submitted in the RFP.

(m)	Only includes the agreement resulting from the RFP for Entergy Mississippi to purchase capacity and energy from Entergy Arkansas from Grand Gulf (60 MW).

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(a)	Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2013 and is expected to provide less than 1% of its generation in 2014.

(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 Gulf States Louisiana, 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 August 2013, Entergy announced plans to close and decommission Vermont Yankee. The plant is expected to cease power production in the fourth quarter 2014 after its current fuel cycle.

(b)

The original expiration date of the NRC operating license for Indian Point 2 was September 28, 2013. Indian Point Unit 2 has now entered its “period of extended operation” after expiration of the plant’s initial license term under “timely renewal,” which is a federal statutory rule of general applicability providing for extension of a license for which a renewal application has been timely filed with the licensing agency. The Indian Point license renewal application qualifies for timely renewal protection because it met NRC regulatory standards for timely filing.

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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;

•	sales 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.

•	utility service;

•	service areas;

•	facilities;

•	certification of generating facilities and certain transmission projects;

•	retail rates;

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•	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 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, new and existing sources of 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;

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•	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.  Entergy cannot estimate the effect of any future legislation at this time due to the uncertainty of the regulatory format;

•	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.  Entergy has prepared responses for the Carbon Disclosure Project’s (CDP) annual questionnaire for the past several years and has given permission for those responses to be posted to CDP’s website.

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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’s 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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•	an increase in the capacity acquisition rider, as approved by the APSC, effective with the first billing cycle of December 2012, relating to the Hot Spring plant acquisition. The net income effect of the Hot Spring plant cost recovery is limited to a portion representing an allowed return on equity on the net plant

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•	increases in the energy efficiency rider, as approved by the APSC, effective July 2013 and July 2012. Energy efficiency revenues are largely offset by costs included in other operation and maintenance expenses and have no effect on net income.

•	an increase of $33.7 million in gross wholesale revenues primarily due to increased sales to affiliated customers and higher prices;

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the June 2012 AmerenUE refund of $30.6 million, including interest, in rough production cost equalization payments collected from AmerenUE. Entergy Arkansas had previously recorded a regulatory provision for the potential refund to AmerenUE. The result of the refund in 2012 was a decrease in gross revenues with an offsetting increase in other regulatory credits. See Note 2 to the financial statements for a discussion of the FERC order in the System Agreement production cost equalization proceedings;

•	an increase of $27.2 million due to the increase in the capacity acquisition rider, as discussed above;

•	an increase of $24.6 million in rider revenues primarily due to an increase in the Grand Gulf rate effective January 2013;

•	an increase of $20.5 million in rider revenues due to increases in the energy efficiency rider effective July 2013 and July 2012, as discussed above; and

•	an increase of $14.3 million in rider revenues related to higher System Agreement production cost equalization payments. These revenues are offset in deferred fuel expenses. See Note 2 to the financial statements for a discussion of the FERC orders in the System Agreement production cost equalization proceedings.

•	increased purchased power costs and gas-fired generation due to an increase in demand as a result of the ANO extended outage as well as increases in the average market prices of natural gas and purchased power; and

•	higher costs related to System Agreement production cost equalization payments, as discussed above.

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an increase of $24.3 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative, partially offset by the deferral, as approved by the APSC, of $21.8 million of these costs. See "Human Capital Management Strategic Imperative" section of Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis for further discussion;

•	an increase of $16.2 million in fossil-fueled generation expenses primarily due to the addition of the Hot Spring plant in November 2012;

•	an increase of $16.1 million in energy efficiency costs. These costs are recovered through the energy efficiency rider and have no effect on net income;

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an increase of $10.8 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs 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; and

•	an increase of $9 million resulting from costs related to the generator stator incident at ANO, including an offset for expected insurance proceeds. See “ANO Damage and Outage” below for further discussion of the incident.

•	a decrease of $4.6 million due to costs incurred in 2012 related to the transition and implementation of joining the MISO RTO. In April 2013, Entergy Arkansas began deferring these costs as approved by the APSC; and

•	the effects of recording the final court decision 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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•	the issuance of $200 million of 4.90% Series first mortgage bonds in December 2012;

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

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

•	an increase of $14.8 million in compensation and benefits costs resulting from a decrease in the discount rate and changes in certain actuarial assumptions resulting from an experience study.  See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;

•	an increase of $13.9 million in energy efficiency costs.  These costs are recovered through the energy efficiency rider and have no effect on net income;

•	$13.3 million of costs incurred in 2012 related to the now terminated plan to spin off and merge the transmission business; and

•	an increase of $10.3 million in nuclear generation expenses primarily due to higher contract costs.

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income tax payments of $184.6 million in 2013 compared to income tax refunds of $20.5 million in 2012. Entergy Arkansas had income tax payments in 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. 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 related to the generator stator incident at ANO, as discussed above;

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•	$22.6 million in storm restoration spending in 2013 resulting from the December 2012 winter storm which caused significant damage to Entergy Arkansas’s distribution lines, equipment, poles and other facilities; and

•	a decrease in the recovery of fuel and purchased power costs.

•	proceeds of $38 million associated with the payments received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel; and

•	the $30.6 million June 2012 refund to AmerenUE, as discussed above.

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

•	$39.6 million in storm restoration spending in 2013 resulting from the December 2012 winter storm;

•	$7.6 million in storm restoration spending in 2013 resulting from the December 2013 winter storm; and

•	money pool activity.

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

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

•	the issuance of $200 million of 4.9% Series first mortgage bonds in December 2012;

•	the issuance of $60 million of 2.62% Series K notes by the nuclear fuel company variable interest entity in December 2012; and

•	the net repayment of $36.7 million of borrowings on the nuclear fuel company variable interest entity credit facility in 2013 compared to net borrowings of $2.8 million in 2012.

•	the issuance of $250 million of 3.05% Series first mortgage bonds in May 2013 and $125 million of 4.75% Series first mortgage bonds in June 2013; and

•	borrowings on a $250 million term loan credit facility entered into in July 2013.

•	the issuance of $200 million of 4.9% Series first mortgage bonds in December 2012 and $60 million 2.62% Series K note by the nuclear fuel company variable interest entity in December 2012 compared to the issuance of $55 million 3.23% Series J note by the nuclear fuel company variable interest entity in June 2011;

•	a decrease of $107.8 million in common stock dividends paid in 2012;

•	the repayment, at maturity, of a $35 million 5.60% Series G note by the nuclear fuel company variable interest entity in September 2011; and

•	an increase in borrowings on the nuclear fuel company variable interest entity’s credit facility.

(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 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 increase of $173.6 million in electric fuel cost recovery revenues primarily due to higher fuel rates;

•	an increase of $69.6 million in rider revenues primarily due to System Agreement credits to customers in 2012;

•	an increase of $10 million in gross wholesale revenues primarily due to higher prices; and

•	an increase of $7.6 million in gas fuel cost recovery revenues primarily due to higher fuel rates.

•	an increase in the average market price of purchased power and increased demand; and

•	an increase in deferred fuel expense due to the timing of receipt of System Agreement payments and credits to customers and higher fuel cost recovery revenues due to higher fuel rates as compared to the prior year. See Note 2 to the financial statements for a discussion of the System Agreement proceedings.

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•	a decrease in the average market prices of purchased power and natural gas; and

•	a decrease in deferred fuel expense due to the timing of receipt of System Agreement payments and credits to customers and lower fuel cost recovery revenues in 2012. See Note 2 to the financial statements for a discussion of the System Agreement proceedings.

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an increase of $15 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs 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;

•	the deferral recorded in the second quarter 2012, as approved by the LPSC and the FERC, of costs related to the transition and implementation of joining the MISO RTO, which reduced expenses by $4.2 million in 2012;

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an increase of $13.5 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative, partially offset by the deferral, as approved by the LPSC, of $9.8 million of these costs. See the "Human Capital Management Strategic Imperative" section of Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis for further discussion;

•	an increase of $3.5 million in fossil-fueled generation expenses due to an overall higher scope of work done during plant outages as compared to the prior year;

•	an increase of $2.9 million in loss reserves; and

•	several individually insignificant items.

•	an increase of $10.4 million in nuclear generation expenses primarily due to higher labor costs, including higher contract labor;

•	an increase of $9.3 million in compensation and benefits costs primarily due to decreasing discount rates and changes in certain actuarial assumptions resulting from an experience study.  See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;

•	$4.7 million of costs incurred in 2012 related to the now terminated plan to spin off and merge the transmission business; and

•	an increase of $3.7 million in fossil-fueled generation expenses resulting primarily from more plant outages and an increased scope of work as compared to the prior year.

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•	$5.8 million of transmission investment equalization expenses recorded in the fourth quarter 2011 as a result of a billing adjustment related to prior transmissions costs (for the approximate period of 1996 – 2011) allocable to Entergy Gulf States Louisiana under the System Agreement;

•	the deferral, as approved by the LPSC and the FERC, of costs related to the transition and implementation of joining the MISO RTO, which reduced expenses by $4.2 million; and

•	several individually insignificant items.

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income tax payments of $5.1 million in 2013 compared to income tax payments of $89.2 million in 2012. Entergy Gulf States Louisiana had income tax payments in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. In 2013, the payments resulted primarily from the reversal of temporary differences for which Entergy Gulf States Louisiana had previously claimed a tax deduction. In 2012, Entergy Gulf States Louisiana no longer had a net operating loss carryover from prior years to reduce current taxable income; and

•	decreased Hurricane Isaac storm spending in 2013.

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an increase in the recovery of fuel and purchased power costs due to System Agreement bandwidth remedy payments of $75 million received in January 2012 as a result of receipts required to implement the FERC’s remedy in an October 2011 order for the period June - December 2005. In the fourth quarter 2012, Entergy Gulf States Louisiana customers were credited $69.6 million. See Note 2 to the financial statements for a discussion of the System Agreement proceedings; and

•	a decrease of $13.7 million in pension contributions. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits.

•	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;

•	$51 million in proceeds in 2012 from the sale of a portion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests to a third party. See Note 2 to the financial statements for discussion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests;

•	money pool activity;

•	an increase in nuclear construction expenditures as a result of spending on nuclear projects during the River Bend refueling outage in 2013; and

•	an increase in transmission construction expenditures due to additional reliability work performed in 2013.

•	the withdrawal of $65.5 million from the storm reserve escrow account in 2013;

•	a decrease in distribution construction expenditures due to prior year Hurricane Isaac spending; and

•	a decrease in fossil-fueled generation construction expenditures as a result of decreased scope of work in 2013.

•	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;

•	$51 million in proceeds from the sale of a portion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests to a third party in 2012; see Note 2 to the financial statements for discussion of Entergy Gulf States Louisiana’s investment in Entergy Holdings

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•	a decrease in nuclear construction expenditures as a result of the River Bend refueling outage in 2011. River Bend had a refueling outage in 2011 and did not have one in 2012.

•	higher distribution construction expenditures due to Hurricane Isaac and increased reliability work performed in 2012;

•	money pool activity;

•	an increase in fossil-fueled generation construction expenditures due to an increased scope of work in 2012; and

•	an increase in transmission construction expenditures due to increased transmission plant upgrades in 2012.

•	money pool activity;

•	an increase of $5.7 million in common equity distributions;

•	net cash redemptions of $5.2 million of long-term debt in 2013; and

•	net cash issuances of $3.4 million of long-term debt in 2012.

•	the repayment, at maturity, of $60 million 5.41% Series O notes by the nuclear fuel company variable interest entity in July 2012;

•	the redemption of $10.84 million of pollution control revenue bonds in 2012 compared to the redemption of $47.34 million of pollution control revenue bonds in 2011; and

•	the nuclear fuel company variable interest entity making payments of $29.4 million on its credit facility in 2012 compared to an increase of $5.2 million in credit facility borrowings in 2011.

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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.

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

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•	internally generated funds;

•	cash on hand;

•	debt or preferred membership interest issuances; and

•	bank financing under new or existing facilities.

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•	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

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•	an increase of $356.9 million in fuel cost recovery revenues primarily due to higher fuel rates.  Entergy Louisiana’s fuel and purchased power recovery mechanism is discussed in Note 2 to the financial statements;

•	the formula rate plan increase, as discussed above;

•	an increase of $29.8 million in affiliated sales as a result of the Acadia contract with Entergy Gulf States Louisiana effective January 2013; and

•	the increase related to volume/weather, as discussed above.

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•	a decrease of $330.3 million in fuel cost recovery revenues primarily due to lower fuel rates. Entergy Louisiana’s fuel and purchased power recovery mechanism is discussed in Note 2 to the financial statements;

•	a decrease of $42 million in rider revenues primarily due to higher System Agreement credits in 2012; and

•	the decrease related to volume/weather, as discussed above.

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an increase of $20.9 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs 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;

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an increase of $16.5 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative, substantially offset by the deferral, as approved by the LPSC, of $13 million of these costs. See the "Human Capital Management Strategic Imperative" section of Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis for further discussion;

•	an increase of $5.4 million in nuclear generation expenses primarily due to higher labor and materials costs; and

•	the prior year deferral, as approved by the LPSC and the FERC, of costs related to the transition and implementation of joining the MISO RTO, which reduced 2012 expenses by $5.2 million.

•	$200 million of 5.25% Series first mortgage bonds in July 2012;

•	$200 million of 3.30% Series first mortgage bonds in December 2012;

•	$100 million of 4.70% Series first mortgage bonds in May 2013; and

•	$325 million of 4.05% Series first mortgage bonds in August 2013.

•	$17.1 million of transmission investment equalization expenses recorded in the fourth quarter 2011 as a result of a billing adjustment related to prior transmission costs (for the approximate period of 1996-2011) allocable to Entergy Louisiana under the System Agreement;

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•	a decrease of $7.3 million in fossil-fueled generation expenses due to an overall lower scope of outages compared to prior year;

•	the deferral, as approved by the LPSC and the FERC, of costs related to the transition and implementation of joining the MISO RTO, which reduced expenses by $5.2 million; and

•	a decrease of $2.7 million as a result of lower write-offs of uncollectible accounts in 2012.

•	an increase of $11.2 million in compensation and benefits costs primarily due to decreasing discount rates and changes in certain actuarial assumptions resulting from an experience study.  See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs; and

•	$6.7 million of costs incurred in 2012 related to the now terminated plan to spin off and merge the transmission business.

•	cessation in 2011 of interest on transmission credits per a FERC order relating to an interconnection and operating agreement between a power producer and Entergy Louisiana;

•	the issuance of $200 million of 4.8% Series first mortgage bonds in March 2011;

•	the issuance by Entergy Louisiana Investment Recovery Funding, L.L.C., a wholly owned subsidiary of Entergy Louisiana, of $207.2 million of senior secured investment recovery bonds with a coupon rate of 2.04% in September 2011;

•	the issuance of $250 million of 1.875% Series first mortgage bonds in January 2012; and

•	the issuance of $200 million of 5.25% Series first mortgage bonds in July 2012.

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•	receipts of $187 million from the storm reserve escrow account in 2013 compared to receipts of $14.5 million in 2012;

•	a decrease in nuclear construction expenditures due to the Waterford 3 steam generator replacement project in 2012;

•	a decrease 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

•	a decrease in distribution construction expenditures due to higher Hurricane Isaac spending in prior year.

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•	an increase in fossil construction expenditures due to spending on the Ninemile Unit 6 self-build project;

•	an increase in nuclear construction expenditures due to the Waterford 3 steam generator replacement project in 2012. The increase is partially offset by various nuclear projects in 2011;

•	higher distribution construction expenditures due to Hurricane Isaac; and

•	money pool activity.

•	the purchase of the Acadia Unit 2 for approximately $300 million in April 2011;

•	a decrease 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;

•	a decrease in transmission construction expenditures due to increased work performed in 2011; and

•	receipts of $13.7 million in 2012 from the storm reserve escrow account.

•	an increase of $340.7 million in common equity distributions in 2013;

•	the net issuance of $386.9 million of long-term debt in 2013 compared to the net issuance of $613.1 million of long-term debt in 2012; and

•	money pool activity.

•	a decrease of $342.6 million in common equity distributions in 2012;

•	the net issuance of $613.1 million of long-term debt in 2012 compared to the net issuance of $384.9 million of long-term debt in 2011;

•	an increase in borrowings of $10.3 million on the nuclear fuel company variable interest entity’s credit facility in 2012 compared to an increase in borrowings of $21.3 million on the nuclear fuel company variable interest entity’s credit facility in 2011;

•	borrowings of $50 million on Entergy Louisiana’s credit facility in 2011 and the repayment of credit facility borrowings of $50 million in 2012; and

•	money pool activity.

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

•	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.

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

(b)

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

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•	internally generated funds;

•	cash on hand;

•	debt or preferred membership interest issuances; and

•	bank financing under new and existing facilities.

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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 increase of $69.6 million in gross wholesale revenues due to an increase in sales to affiliated customers;

•	an increase of $60.4 million in power management rider revenue, as approved by the MPSC, primarily resulting from the acquisition of the Hinds plant in November 2012, as discussed previously;

•	an increase of $58.6 million in fuel cost recovery revenues primarily due to higher fuel rates; and

•	an increase of $28.2 million in rider revenue primarily due to an increase in the Grand Gulf rider effective October 2012.

•	increases in the average market prices of natural gas and purchased power;

•	an increase in Grand Gulf capacity costs as a result of the Grand Gulf uprate; and

•	an increase in deferred fuel expenses as a result of higher fuel revenues primarily due to lower 2012 fuel rates as a result of bandwidth remedy payments refunded to customers in August through December 2012. See Note 2 to the financial statements for a discussion of the System Agreement proceedings.

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•	an increase of $30.6 million in fossil-fueled generation expenses resulting from a higher scope of work done during plant outages in 2013 as compared to 2012, the acquisition of the Hinds plant in November 2012, and the Baxter Wilson (Unit 1) unplanned outage in September 2013;

•	an increase 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; and

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an increase of $5.9 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs 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.

•	an increase of $21.1 million resulting from a temporary increase in the storm damage reserve authorized by the MPSC effective August 2012;

•	$7.6 million of costs incurred in 2012 related to the now terminated plan to spin off and merge the transmission business; and

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•	an increase of $4.8 million in compensation and benefits costs primarily resulting from decreasing discount rates and changes in certain actuarial assumptions resulting from an experience study.  See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs.

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•	the purchase in 2011 of $42.6 million of fuel oil from System Fuels because System Fuels will no longer procure fuel oil for the Utility companies;

•	income tax payments of $22.1 million in 2011; and

•	a decrease of $19.5 million in pension contributions. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension funding.

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•	redemptions of $80 million of 4.65% Series first mortgage bonds and $100 million of 5.92% Series first mortgage bonds in second quarter 2011;

•	the issuance of $250 million of 3.1% Series first mortgage bonds in December 2012 compared to the issuance of $150 million of 6.0% Series first mortgage bonds in April 2011 and the issuance of $125 million of 3.25% Series first mortgage bonds in May 2011; 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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•	a decrease of $53.3 million in gross wholesale revenue primarily due to decreased sales to affiliate customers; and

•	a decrease of $18.9 million in gross gas revenues primarily due to lower fuel cost recovery revenues as a result of lower fuel rates and the effect of milder weather. Entergy New Orleans’s fuel and purchased power recovery mechanism is discussed in Note 2 to the financial statements.

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•	an increase of $9 million in fossil-fueled generation expenses due to an overall higher scope of work done during plant outages as compared to prior year;

•	an increase of $4.4 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; and

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an increase of $3.1 million in compensation and benefits costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs 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.

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•	money pool activity;

•	an increase in transmission construction expenditures as a result of additional reliability work performed in 2013; and

•	an increase in fossil-fueled generation construction expenditures due to an increased scope of work in 2013.

•	higher distribution construction expenditures due to Hurricane Isaac;

•	money pool activity; and

•	the repayment by System Fuels of Entergy New Orleans’s $3.3 million investment in System Fuels in 2011.

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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.

(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; and

•	debt and preferred stock issuances.

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•	an increase of $67.5 million in gross wholesale revenues as a result of an increase in sales to affiliated customers and higher prices;

•	an increase of $20.9 million in rider revenues primarily due to System Agreement credits in 2012;

•	an increase of $15.2 million in fuel cost recovery revenue due to higher fuel rates;

•	favorable weather/volume, as discussed above; and

•	the annual base rate increase effective July 2012, as discussed above.

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•	a decrease of $156.2 million in fuel cost recovery revenues primarily attributable to lower fuel rates and lower usage, offset by lower interim fuel refunds in 2012 versus 2011.  Entergy Texas’s fuel and purchased power recovery mechanism is discussed in Note 2 to the financial statements.  The interim fuel refunds and the PUCT approvals are discussed in Note 2 to the financial statements; and

•	less favorable volume/weather, as discussed above.

•

an increase of $9 million in compensation and benefit costs primarily due to a decrease in the discount rates used to determine net periodic pension and other postretirement benefit costs 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;

•	an increase of $8.8 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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•	an increase of $2.3 million primarily due to storm damage accruals in accordance with a rate order from PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order;

•	an increase of $1.7 million in distribution contract work relating primarily to vegetation maintenance; and

•	an increase of $1.4 million in insurance expenses primarily due to increases in premiums.

•	the amortization of $4.3 million of Hurricane Rita storm costs in prior year in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order; and

•	a decrease of $2.7 million in fossil-fueled expenses due to a reduced scope of work and fewer outages compared to 2012.

•	an increase of $7.2 million in fossil-fueled generation expenses due to a greater scope of work and an additional outage in 2012 compared to 2011;

•	$4.8 million of costs incurred in 2012 related to the now terminated plan to spin off and merge the transmission business;

•	the amortization of $4.3 million of Hurricane Rita storm costs in accordance with a rate order from the PUCT issued in September 2012.  See Note 2 to the financial statements for further discussion of the PUCT rate order;

•	an increase of $3.5 million in compensation and benefit costs primarily due to decreasing discount rates and changes in certain actuarial assumptions resulting from an experience study.   See “Critical Accounting Estimates” below for further discussion of benefits costs;

•	an increase of $2.7 million in loss reserves in 2012; and

•	an increase of $2.3 million in storm damage reserves in accordance with a rate order from the PUCT issued in September 2012.  See Note 2 to the financial statements for further discussion of the PUCT rate order.

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the receipt, in January 2012, of $43 million in System Agreement bandwidth remedy payments required to implement the FERC’s remedy in an October 2011 order for the period June-December 2005. As of March 31, 2013, all of the $43 million, plus interest, had been credited to Entergy Texas customers, with the final $9.5 million being credited in the first quarter 2013. See Note 2 to the financial statements for a discussion of the System Agreement proceedings;

•	$86.1 million of fuel cost refunds in 2013, compared to $67.2 million of fuel cost refunds in 2012. See Note 2 to the financial statements for discussion of the fuel cost refunds; and

•	the timing of collections of receivables from customers.

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an increase in the recovery of fuel costs due to System Agreement bandwidth remedy payments of $43 million received in January 2012 as a result of receipts required to implement the FERC’s remedy in an October 2011 order for the period June-December 2005.  In the fourth quarter 2012, Entergy Texas customers were credited $28.4 million.  See Note 2 to the financial statements for a discussion of the System Agreement proceedings;

•	a decrease of $9.1 million in pension contributions.  See “Critical Accounting Estimates” below for a discussion of qualified pension and other postretirement benefits; and

•	$67.2 million of fuel cost refunds in 2012 compared to $73.4 million of fuel cost refunds in 2011.  See Note 2 to the financial statements for discussion of the fuel cost refunds.

•	money pool activity;

•	an increase in transmission construction expenditures due to reliability work performed in 2013; and

•	an increase in distribution construction expenditures due to an increased scope of work in 2013.

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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)	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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•	the issuance of $250 million of 4.10% Series first mortgage bonds in September 2012;

•	the issuance of $50 million of 4.02% Series H notes by the nuclear fuel company variable interest entity in February 2012; and

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

•	the redemption of $152.975 million of pollution control revenue bonds in 2012;

•	the redemption of $70 million of 6.2% Series first mortgage bonds in October 2012;

•	an increase in borrowings of $40 million on the nuclear fuel company variable interest entity’s credit facility in 2013 compared to the repayment of borrowings of $40 million on the nuclear fuel company variable interest entity’s credit facility in 2012; and

•	a decrease of $9.4 million in common stock dividends paid in 2013.

•	the issuance of $250 million of 4.10% Series first mortgage bonds in September 2012;

•	the issuance of $50 million of 4.02% Series H notes by the nuclear fuel company variable interest entity in February 2012;

•	an increase in borrowings of $40 million on the nuclear fuel company variable interest entity’s credit facility in 2012 compared to the repayment of borrowings of $38.3 million on the nuclear fuel company variable interest entity’s credit facility in 2011;

•	the redemption of $152.975 million of pollution control revenue bonds in 2012;

•	the redemption of $70 million of 6.2% Series first mortgage bonds in October 2012; and

•	the partial redemption of $40 million of 6.2% pollution control revenue bonds in 2011.

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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.

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

•	The equity-based long-term incentive programs, including the Long-Term Performance Unit Program, further align the interests of the executives and Entergy Corporation’s shareholders by directly tying the value of the equity awards granted to executives under these programs to the performance of Entergy Corporation’s stock price and total shareholder return.

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•	earnings per share and operating cash flow have both a correlative and causal relationship with shareholder value over the long-term;

•	earnings per share and operating cash flow targets are aligned with externally-communicated goals; and

•	earnings per share and operating cash flow results are readily available in earning releases and SEC filings.

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•	37,156 performance units for Mr. Denault;

•	7,472 performance units for Mr. Forbes and Mr. Mohl;

•	7,442 performance units for Mr. Marsh;

•	7,600 performance units for Mr. West;

•	2,969 performance units for Mr. May;

•	3,000 performance units for Ms. Mount;

•	1.900 performance units for Mr. Fisackerly, Mr. McDonald, Ms. Rainer and Mr. Rice.

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•	12,041 performance units for Mr. Denault;

•	2,636 performance units for Mr. Marsh;

•	3,539 performance units for Mr. Forbes and Mr. Mohl;

•	5,900 performance units for Mr. West;

•	1,597 performance units for Mr. May;

•	1,319 performance units for Ms. Mount;

•	1,200 performance units for Mr. Fisackerly and Mr. McDonald;

•	633 performance units for Ms. Rainer; and

•	1,200 performance units for Mr. Rice.

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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 the subject of a material restatement other than a restatement due to changes in accounting policy; or (ii) a material miscalculation of a performance award occurs, whether or not the financial statements were restated and, in either such case, a lower payment would have been made to the executive officer based upon the restated financial results or correct calculation; or

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

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•	all net after-tax shares paid out under the Long-Term Performance Unit Program, which will pay out entirely in Entergy Corporation stock commencing with the 2012-2014 performance period;

•	all net after-tax shares of Entergy Corporation’s 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 Entergy Corporation’s Chief Executive Officer.

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(1)	The amounts in column (c) represent the actual base salary paid to the Named Executive Officer.  The 2013 changes in base salaries noted in the Compensation Discussion and Analysis for Messrs. Denault, Forbes, Marsh, May, and Mohl were effective upon their promotions and for the other Named Executive Officers in April 2013.

(2)

The amounts in column (d) in 2013 and 2012 for Mr. Fisackerly, Mr. McDonald, Ms. Rainer, and Mr. Rice, in 2012 for Mr. Mohl, and in 2013 for Mr. May represent a cash bonus paid in recognition of their work supporting the move to MISO. The amount for Mr. Forbes represents the cash bonus paid to him pursuant to the Nuclear Retention Plan. See "Nuclear Retention Plan" in Compensation Discussion and Analysis.

(3)

The amounts in column (e) represent the aggregate grant date fair value of restricted stock, restricted units, and performance units granted under the 2011 Equity Ownership Plan 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 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 2013 are as follows:  Mr. Denault, $7,378,205; Mr. Fisackerly, $245,480; Mr. Forbes, $1,348,185; Mr. Marsh, $1,470,889; Mr. May, $509,644; Mr. McDonald, $245,480; Mr. Mohl, $1,348,716; Ms. Mount, $387,600; Ms. Rainer, $245,480; Mr. Rice, $245,480; and Mr. West, $981,920.

(4)	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.

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

(6)

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 “2013 Pension Benefits”).  None of the increase is attributable to above-market or preferential earnings on non-qualified deferred compensation (see “2013 Non-qualified Deferred Compensation”).  For 2013, the aggregate change in the actuarial present value of Messrs. Fisackerly's, May's, and McDonald's pension benefits was a decrease of $103,400, $80,100, and $116,500, respectively.

(7)	The amounts in column (i) for 2013 include (a) matching contributions by Entergy Corporation under the Savings Plan to each of the Named Executive Officers; (b) dividends paid on restricted stock when vested; (c) life insurance premiums; (d) tax gross up payments on club dues and relocation expenses; and (e) perquisites and other compensation.  The amounts are listed in the following table:

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

(2)

Except as otherwise noted in footnote 6, 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.  If Entergy Corporation’s total shareholder return is not at least 25% of that for the Philadelphia

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(3)	Except as otherwise noted in footnotes 7 and 8, the amounts in column (i) represent shares of restricted stock granted under the 2011 Equity Ownership Plan.  Shares of restricted stock vest over a three-year period, 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 outcome of the applicable performance conditions.  See Notes 3 and 4 to the Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.

(6)

With their promotions, Messrs. Denault, Forbes, Marsh, May and Mohl received pro-rated performance unit awards under the 2011 – 2013 Long-Term Performance Unit Program and 2012 – 2014 Long-Term Performance Unit Program.   For the 2011 - 2013 Long-Term Performance Program, subject to achievement of performance targets, each unit will be converted into the cash equivalent of one share of Entergy Corporation’s common stock on the last day of the performance period (December 31, 2013). For the 2012 - 2014 Long-Term Performance Program, 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, 2014).

(7)	In January 2013, Mr. Forbes was awarded 8,000 restricted units under the 2011 Equity Ownership Plan.  The restricted units will vest on January 2, 2016.

(8)	In May 2013, Mr. West was awarded 21,000 restricted units under the 2011 Equity Ownership Plan.  The restricted units will vest on May 1, 2018.

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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 1/31/2014, 1/31/2015 and 1/31/2016.

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(2)	Consists of options that vested or will vest as follows: 1/2 of the remaining unexercisable options vest on each of 1/26/2014 and 1/26/2015.

(3)	The remaining unexercisable options vested on 1/27/2014.

(4)	Consists of performance units that will vest on December 31, 2015 based on Entergy Corporation’s total shareholder return performance over the 2013-2015 performance period, as described under “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, 2014 based on Entergy Corporation’s total shareholder return performance over the 2012 – 2014 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 1/31/2014, 1/31/2015 and 1/31/2016.

(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 1/26/2014 and 1/26/2015.

(8)	Consists of shares of restricted stock that vested on 1/27/2014.

(9)	Consists of restricted units granted under the 2011 Equity Ownership Plan which will vest on January 2, 2016.

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

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(1)	Includes the January 25, 2013 cash settlement of 8,000 restricted units granted under the 2007 Equity Ownership Plan.

(2)	Includes the June 30, 2013 cash settlement of 1,668 restricted units granted under the 2007 Equity Ownership Plan.

(3)	Includes the April 30, 2013 cash settlement of 15,000 restricted units granted under the 2007 Equity Ownership Plan.

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(1)	During 2006, Mr. Denault entered into an agreement granting an additional 15 years of service under the non-qualified System Executive Retirement Plan if he continues to work for an Entergy System company employer until age 55.  The additional 15 years of service increases the present value of his benefit by $1,595,600.

(2)	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.

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

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(1)

In addition to the payments and benefits in the table, Mr. Denault also would have been entitled to receive his vested pension benefits. If Mr. Denault’s employment were terminated under certain conditions relating to a change in control, he would also be eligible for early retirement benefits. For a description of these benefits, see “2013 Pension Benefits.” In addition, Mr. Denault is subject to the following provisions:

Retention Agreement.  Mr. Denault’s retention agreement provides that, unless his employment is terminated for cause, he will be granted an additional 15 years of service under the System Executive Retirement Plan if he continues to work for an Entergy System company employer until age 55. Because Mr. Denault had not reached age 55 as of December 31, 2013, he is only entitled to this supplemental credited service and System Executive Retirement Plan supplemental benefits in the event of his death or disability.

System Executive Retirement Plan.  If Mr. Denault’s employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan. In the event of a termination related to a change in control, pursuant to the terms of the System Executive Retirement Plan, Mr. Denault would be eligible for subsidized retirement (but not the additional 15 years of service) upon his separation of service even if he does not then meet the age or service requirements for early retirement under the System Executive Retirement Plan or have company permission to separate from employment.

(2)	In the event of a termination (not due to death or disability) by Mr. Denault for good reason or by Entergy Corporation not for cause (regardless of whether there is a change in control), Mr. Denault would be entitled to receive, pursuant to his

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(3)

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 severance payment pursuant to his retention agreement that would not be based on any outstanding performance periods. The payment would be 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 severance payment was calculated by taking an average of the target performance units from the 2009-2011 Performance Unit Program (22,500 units) and the 2010-2012 Performance Unit Program (22,300 units). This average number of units (22,400 units) multiplied by the closing price of Entergy stock on December 31, 2013 ($63.27) would equal a severance payment of $1,417,248 for the forfeited performance units.

(4)

In the event of his death, disability, termination by Mr. Denault for good reason or by Entergy Corporation not for cause (regardless of whether there is a change in control), all of Mr. Denault’s unvested stock options would immediately vest. In addition, he would be entitled to exercise any unexercised options during a ten-year term extending from the grant date of the options. For purposes of this table, we assumed that Mr. Denault exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2013, and the exercise price of each option share. As of December 31, 2013, the closing stock price for Mr. Denault’s unvested options fell below the exercise prices and accordingly are considered “underwater” and are excluded from the table.

(5)	In the event of his death, disability, termination by Mr. Denault for good reason or by Entergy Corporation not for cause (regardless of whether there is a change in control), all of Mr. Denault’s unvested restricted stock would immediately vest.

(6)	Pursuant to his retention agreement, in the event of a termination by Mr. Denault for good reason or by Entergy Corporation not for cause, Mr. Denault would be eligible to receive company-subsidized COBRA benefits for 18 months.

(7)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Denault would be eligible to receive company-subsidized medical and dental benefits for 18 months.

(8)	As of December 31, 2013, Mr. Denault is not eligible for retirement.

(9)	In December of 2010, Mr. Denault voluntarily agreed to amend his retention agreement to eliminate excise tax gross-up payments.

•	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;

•	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’s reputation;

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

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•	unauthorized disclosure of Entergy’s confidential information.

•	the substantial reduction in the nature or status of his duties or responsibilities;

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

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

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

•	the failure to continue to allow him to participate in programs or plans with opportunities for benefits not materially less favorable than those enjoyed by him under any of the 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 substantial reduction or alteration in the nature or status of his duties or responsibilities;

•	a reduction in his annual base salary;

•	the relocation of his principal place of employment to a location more than 20 miles from his current place of employment;

•	the failure to pay any portion of his compensation within seven days of its due date;

•	the failure to continue in effect any compensation plan in which he participates and which is material to his total compensation, unless other equitable arrangements are made;

•	the failure to continue to provide benefits substantially similar to those that he currently enjoys under any of the pension, savings, life insurance, medical, health and accident or disability plans, or Entergy taking of any other action which materially reduces any of those benefits or deprives him of any material fringe benefits that he currently enjoys;

•	the failure to provide him with the number of paid vacation days to which he is entitled in accordance with the normal vacation policy; or

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

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(1)

In addition to the payments and benefits in the table, if Mr. Fisackerly's employment were terminated under certain conditions relating to a change in control, Mr. Fisackerly also would have been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, see "2013 Pension Benefits." If Mr. Fisackerly's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan.

(2)

In the event of a qualifying termination related to a change in control, Mr. Fisackerly would be entitled to receive pursuant to the System Executive Continuity Plan, a lump sum severance payment equal to the product of one time the sum of (a) his 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 annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 40% target opportunity and a base salary of $296,174 was assumed.

(3)

In the event of a qualifying termination related to a change in control, Mr. Fisackerly would have forfeited his performance units for the 2012-2014 and 2013-2015 performance periods and would have been entitled to receive, pursuant to the 2011 Equity Ownership Plan, a single-sum severance payment that would not be based on any outstanding performance periods. For both the 2012-2014 performance period and the 2013-2015 performance period, the payment would have been calculated using the average annual number of performance units he would have been entitled to receive under each 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. Fisackerly’s severance payment was calculated by taking an average of the target performance units from the 2009-2011 Performance Unit Program (900 units) and the 2010-2012 Performance Unit Program (1,000 units). This average number of units (950 units) multiplied by the closing price of Entergy stock on December 31, 2013 ($63.27) would equal a severance payment of $60,107 for the forfeited performance units.

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(4)

In the event of his death, disability or qualifying termination related to a change in control, all of Mr. Fisackerly’s unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Fisackerly exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2013, and the applicable exercise price of each option share. As of December 31, 2013, the closing stock price of Mr. Fisackerly’s unvested options fell below the exercise prices and accordingly are considered “underwater” and are excluded from the table.

(5)

In the event of his death or disability, Mr. Fisackerly would immediately vest in a pro-rated portion of the 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). 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 death or disability. In the event of his qualifying termination related to a change in control, Mr. Fisackerly would immediately vest in all unvested restricted stock.

(6)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Fisackerly would be eligible to receive company-subsidized COBRA benefits for 12 months.

(7)	As of December 31, 2013, compensation and benefits available to Mr. Fisackerly under this scenario are substantially the same as available with a voluntary resignation.

(8)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

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(1)

In addition to the payments and benefits in the table, Mr. Forbes would have been eligible to retire and entitled to receive his vested pension benefits. For a description of the pension benefits available see "2013 Pension Benefits." In the event of a termination related to a change in control, pursuant to the terms of the System Executive Retirement Plan, Mr. Forbes would be eligible for subsidized early retirement even if he does not have company permission to separate from employment. If Mr. Forbes' employment were terminated for cause, he would not receive a benefit under the System Executive Retirement Plan.

(2)

In the event of a qualifying termination related to a change in control, Mr. Forbes would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to the product of 2.99 times the sum of (a) his 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 annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 60% target opportunity and a base salary of $550,000 was assumed.

(3)

In the event of a qualifying termination related to a change in control, Mr. Forbes would have forfeited his performance units for the 2012-2014 and 2013-2015 performance periods and would have been entitled to receive, pursuant to the 2011 Equity Ownership Plan, a single-sum severance payment that would not be based on any outstanding performance periods. For both the 2012-2014 performance period and the 2013-2015 performance period, the payment would have been calculated using the average annual number of performance units he would have been entitled to receive under each 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. Forbes’ severance payment was calculated by taking an average of the target performance units from the 2009-2011 Performance Unit Program (4,800 units) and the 2010-2012 Performance Unit Program (5,300 units). This average number of units (5,050 units) multiplied by the closing price of Entergy stock on December 31, 2013 ($63.27) would equal a severance payment of $319,514 for the forfeited performance units.

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(4)

In the event of his death, disability or qualifying termination related to a change in control, all of Mr. Forbes’s unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Forbes exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2013, and the applicable exercise price of each option share. As of December 31, 2013, the closing stock price of Mr. Forbes’s unvested options fell below the exercise prices and accordingly are considered “underwater” and are excluded from the table.

(5)

In the event of his death or disability, Mr. Forbes would immediately vest in a pro-rated portion of the 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). 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 death or disability. In the event of his qualifying termination related to a change in control, Mr. Forbes would immediately vest in all unvested restricted stock.

(6)	As Entergy Corporation's Chief Nuclear Officer, Mr. Forbes participates in the Nuclear Retention Program which does not allow for accelerated or prorated payout upon termination of any kind.

(7)

Mr. Forbes’ 8,000 restricted units vest 100% in 2016. Pursuant to his restricted unit agreement, any unvested restricted units will vest immediately in the event of a termination for a reason other than cause, total disability or death. The units will vest upon termination within 24 months of a change in control without cause or by Mr. Forbes with good reason. If Mr. Forbes voluntarily resigned or was terminated for cause, he would forfeit these units.

(8)	Upon retirement, Mr. Forbes 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, Mr. Forbes would not be eligible to receive company-subsidized COBRA benefits.

(9)	As of December 31, 2013, Mr. Forbes is retirement eligible and would retire rather than voluntarily resign. Given that scenario, the compensation and benefits available to Mr. Forbes under retirement are substantially the same as available with a voluntary resignation.

(10)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

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(1)

In addition to the payments and benefits in the table, if Mr. Marsh's employment were terminated under certain conditions relating to a change in control, Mr. Marsh also would have been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, see "2013 Pension Benefits." If Mr. Marsh's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan.

(2)

In the event of a qualifying termination related to a change in control, Mr. Marsh would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to the product of 2.99 times the sum of (a) his annual base salary as in effect at any time within one year prior to the commencement of a of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 40% target opportunity and a base salary of $500,000 was assumed.

(3)

In the event of a qualifying termination related to a change in control, Mr. Marsh would have forfeited his performance units for the 2012-2014 and 2013-2015 performance periods and would have been entitled to receive, pursuant to the 2011 Equity Ownership Plans, a single-sum severance payment that would not be based on any outstanding performance periods. For both the 2012-2014 performance period and the 2013-2015 performance period, the payment would have been calculated using the average annual number of performance units he would have been entitled to receive under each 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. Marsh’s severance payment was calculated by taking an average of the target performance units from the 2009-2011 Performance Unit Program (4,800 units) and the 2010-2012 Performance Unit Program (5,300 units). This average number of units (5,050 units) multiplied by the closing price of Entergy stock on December 31, 2013 ($63.27) would equal a severance payment of $319,514 for the forfeited performance units.

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(4)

In the event of his death, disability or qualifying termination related to a change in control, all of Mr. Marsh’s unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Marsh exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2013, and the applicable exercise price of each option share. As of December 31, 2013, the closing stock price of Mr. Marsh’s unvested options fell below the exercise prices and accordingly are considered “underwater” and are excluded from the table.

(5)

In the event of his death or disability, Mr. Marsh would immediately vest in a pro-rated portion of the 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). 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 death or disability. In the event of his qualifying termination related to a change in control, Mr. Marsh would immediately vest in all unvested restricted stock.

(6)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Marsh would be eligible to receive company-subsidized COBRA benefits for 18 months.

(7)	As of December 31, 2013, compensation and benefits available to Mr. Marsh under this scenario are substantially the same as available with a voluntary resignation.

(8)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

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(1)

In addition to the payments and benefits in the table, if Mr. May's employment were terminated under certain conditions relating to a change in control, Mr. May also would have been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, see "2013 Pension Benefits." If Mr. May's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan.

(2)

In the event of a qualifying termination related to a change in control, Mr. May would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to the product of two times the sum of (a) his 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 annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 40% target opportunity and a base salary of $330,000 was assumed.

(3)

In the event of a qualifying termination related to a change in control, Mr. May would have forfeited his performance units for the 2012-2014 and 2013-2015 performance periods and would have been entitled to receive, pursuant to the 2011 Equity Ownership Plan, a single-sum severance payment that would not be based on any outstanding performance periods. For both the 2012-2014 performance period and the 2013-2015 performance period, the payment would have been calculated using the average annual number of performance units he would have been entitled to receive under each 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. May’s severance payment was calculated by taking an average of the target performance units from the 2009-2011 Performance Unit Program (2,000 units) and the 2010-2012 Performance Unit Program (2,200 units). This average number of units (2,100 units) multiplied by the closing price of Entergy stock on December 31, 2013 ($63.27) would equal a severance payment of $132,867 for the forfeited performance units.

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(4)

In the event of his death, disability or qualifying termination related to a change in control, all of Mr. May's unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. May exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2013, and the applicable exercise price of each option share. As of December 31, 2013, the closing stock price of Mr. May’s unvested options fell below the exercise prices and accordingly are considered “underwater” and are excluded from the table.

(5)

In the event of his death or disability, Mr. May would immediately vest in a pro-rated portion of the 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). 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 death or disability. In the event of his qualifying termination related to a change in control, Mr. May would immediately vest in all unvested restricted stock.

(6)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. May would be eligible to receive company-subsidized COBRA benefits for 18 months.

(7)	As of December 31, 2013, compensation and benefits available to Mr. May under this scenario are substantially the same as available with a voluntary resignation.

(8)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

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(1)

In addition to the payments and benefits in the table, if Mr. McDonald would have been eligible to retire and entitled to receive his vested pension benefits. For a description of the pension benefits available see "2013 Pension Benefits." In the event of a termination related to a change in control, pursuant to the terms of the System Executive Retirement Plan, Mr. McDonald would be eligible for subsidized early retirement even if he does not have company permission to separate from employment. If Mr. McDonald’s employment were terminated for cause, he would not receive a benefit under the System Executive Retirement Plan.

(2)

In the event of a qualifying termination related to a change in control, Mr. McDonald would be entitled to receive pursuant to the System Executive Continuity Plan, a lump sum severance payment equal to the product of one time the sum of (a) his 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 annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 50% target opportunity and a base salary of $345,220 was assumed.

(3)

In the event of a qualifying termination related to a change in control, Mr. McDonald would have forfeited his performance units for the 2012-2014 and 2013-2015 performance periods and would have been entitled to receive, pursuant to the 2011 Equity Ownership Plan, a single-sum severance payment that would not be based on any outstanding performance periods. For both the 2012-2014 performance period and the 2013-2015 performance period, the payment would have been calculated using the average annual number of performance units he would have been entitled to receive under each 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. McDonald’s severance payment was calculated by taking an average of the target performance units from the 2009-2011 Performance Unit Program (900 units) and the 2010-2012 Performance Unit Program (1,000 units). This average number of units (950 units) multiplied by the closing price of Entergy stock on December 31, 2013 ($63.27) would equal a severance payment of $ $60,107 for the forfeited performance units.

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(4)

In the event of his retirement, death, disability or qualifying termination related to a change in control, all of Mr. McDonald's unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. McDonald exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2013, and the applicable exercise price of each option share. As of December 31, 2013, the closing stock price of Mr. McDonald’s unvested options fell below the exercise prices and accordingly are considered “underwater” and are excluded from the table.

(5)

In the event of his death or disability, Mr. McDonald would immediately vest in a pro-rated portion of the 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). 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 death or disability. In the event of his qualifying termination related to a change in control, Mr. McDonald would immediately vest in all unvested restricted stock.

(6)	Upon retirement, 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, Mr. McDonald would not be eligible to receive company-subsidized COBRA benefits.

(7)	As of December 31, 2013, Mr. McDonald is retirement eligible and would rather retire than voluntary resign. Given that scenario, the compensation and benefits available to Mr. McDonald under retirement are substantially the same as available with a voluntary resignation.

(8)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

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(1)

In addition to the payments and benefits in the table, if Mr. Mohl's employment were terminated under certain conditions relating to a change in control, Mr. Mohl also would have been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, see "2013 Pension Benefits." If Mr. Mohl's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan.

(2)

In the event of a qualifying termination related to a change in control, Mr. Mohl would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to the product of 2.99 times the sum of (a) his annual base salary as is effect at any time within one year prior to the commencement of a of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 60% target opportunity and a base salary of $560,000 was assumed.

(3)

In the event of a qualifying termination related to a change in control, Mr. Mohl would have forfeited his performance units for the 2012-2014 and 2013-2015 performance periods and would have been entitled to receive, pursuant to the 2011 Equity Ownership Plan, a single-sum severance payment that would not be based on any outstanding performance periods. For both the 2012-2014 performance period and the 2013-2015 performance period, the payment would have been calculated using the average annual number of performance units he would have been entitled to receive under each 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. Mohl’s severance payment was calculated by taking an average of the target performance units from the 2009-2011 Performance Unit Program (4,800 units) and the 2010-2012 Performance Unit Program (5,300 units). This average number of units (5,050 units) multiplied by the closing price of Entergy stock on December 31, 2013 ($63.27) would equal a severance payment of $319,514 for the forfeited performance units.

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(4)

In the event of his death, disability or qualifying termination related to a change in control, all of Mr. Mohl’s unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Mohl exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2013, and the applicable exercise price of each option share. As of December 31, 2013, the closing stock prices of Mr. Mohl’s unvested options fell below the exercise prices and accordingly are considered “underwater” and are excluded from the table.

(5)

In the event of his death or disability, Mr. Mohl would immediately vest in a pro-rated portion of the 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). 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 death or disability. In the event of his qualifying termination related to a change in control, Mr. Mohl would immediately vest in all unvested restricted stock.

(6)

Pursuant to the provisions of Mr. Mohl’s retention agreement, if Mr. Mohl is terminated without cause prior to September 18, 2014, the date Mr. Mohl becomes retirement eligible, Mr. Mohl would receive a severance payment of $7,538,650, upon satisfaction of certain terms and conditions. This amount includes, in addition to a severance payment calculated on the basis of his base salary and target annual bonus, a payment of $2,200,000 plus the benefits he would be eligible for under the System Executive Retirement Plan as if he were retirement eligible reduced by any benefits payable under any of Entergy Corporation’s qualified or non-qualified retirement plans. See “Executive Compensation - Compensation Discussion And Analysis -Retention Agreements and Other Compensation Arrangements.”

(7)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Mohl would be eligible to receive company-subsidized COBRA benefits for 18 months.

(8)	As of December 31, 2013, compensation and benefits available to Mr. Mohl under this scenario are substantially the same as available with a voluntary resignation.

(9)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

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(1)

In addition to the payments and benefits in the table, if Ms. Mount's employment were terminated under certain conditions relating to a change in control, Ms. Mount also would have been entitled to receive her vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, see "2013 Pension Benefits." If Ms. Mount's employment were terminated for cause, she would forfeit her benefit under the System Executive Retirement Plan.

(2)

In the event of a qualifying termination related to a change in control, Ms. Mount would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to the product of 2.00 times the sum of (a) 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) her annual incentive, calculated using the average annual target opportunity under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 48% target opportunity and a base salary of $286,700 was assumed.

(3)

In the event of a qualifying termination related to a change in control, Ms. Mount would have forfeited her performance units for the 2012-2014 and 2013-2015 performance periods and would have been entitled to receive, pursuant to the 2011 Equity Ownership Plan, a single-sum severance payment that would not be based on any outstanding performance periods. For both the 2012-2014 performance period and the 2013-2015 performance period, the payment would have been calculated using the average annual number of performance units she would have been entitled to receive under each Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which her termination occurs, assuming all performance goals were achieved at target. For purposes of the table, the value of Ms. Mount’s severance payment was calculated by taking an average of the target performance units from the 2009-2011 Performance Unit Program (2,000 units) and the 2010-2012 Performance Unit Program (2,200 units). This average number of units (2,100 units) multiplied by the closing price of Entergy stock on December 31, 2013 ($63.27) would equal a severance payment of $132,867 for the forfeited performance units.

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(4)

In the event of her death, disability or qualifying termination related to a change in control, all of Ms. Mount's unvested stock options would immediately vest. In addition, she would be entitled to exercise her stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Ms. Mount exercised her options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2013, and the applicable exercise price of each option share. As of December 31, 2013, the closing stock price of Ms. Mount’s unvested options fell below the exercise prices and accordingly are considered “underwater” and are excluded from the table.

(5)

In the event of her death or disability, Ms. Mount would immediately vest in a pro-rated portion of the 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). 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 her death or disability. In the event of her qualifying termination related to a change in control, Ms. Mount would immediately vest in all unvested restricted stock.

(6)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Ms. Mount would be eligible to receive company-subsidized COBRA benefits for 18 months.

(7)	As of December 31, 2013, compensation and benefits available to Ms. Mount under this scenario are substantially the same as available with a voluntary resignation.

(8)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

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(1)

In addition to the payments and benefits in the table, if Ms. Rainer's employment were terminated under certain conditions relating to a change in control, Ms. Rainer also would have been entitled to receive her vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, see "2013 Pension Benefits." If Ms. Rainer's employment were terminated for cause, she would forfeit her benefit under the System Executive Retirement Plan.

(2)

In the event of a qualifying termination related to a change in control, Ms. Rainer would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to the product of 1.00 times the sum of (a) 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) her annual incentive, calculated using the average annual target opportunity under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 40% target opportunity and a base salary of $291,000 was assumed.

(3)

In the event of a qualifying termination related to a change in control, Ms. Rainer would have forfeited her performance units for the 2012-2014 and 2013-2015 performance periods and would have been entitled to receive, pursuant to the 2011 Equity Ownership Plan, a single-sum severance payment that would not be based on any outstanding performance periods. For both the 2012-2014 performance period and the 2013-2015 performance period, the payment would have been calculated using the average annual number of performance units she would have been entitled to receive under each Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which her termination occurs, assuming all performance goals were achieved at target. For purposes of the table, the value of Ms. Rainer’s severance payment was calculated by taking an average of the target performance units from the 2009-2011 Performance Unit Program (900 units) and the 2010-2012 Performance Unit Program (1,000 units). This average number of units (950 units) multiplied by the closing price of Entergy stock on December 31, 2013 ($63.27) would equal a severance payment of $60,107 for the forfeited performance units.

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(4)

In the event of her death, disability or qualifying termination related to a change in control, all of Ms. Rainer's unvested stock would immediately vest. In addition, she would be entitled to exercise any unexercised options during a ten-year term extending from the grant date of the options. For purposes of this table, we assumed that Ms. Rainer exercised her options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2013, and the exercise price of each option share. As of December 31, 2013, the closing stock price of Ms. Rainer’s unvested options fell below the exercise prices and accordingly are considered “underwater” and are excluded from the table.

(5)

In the event of her death or disability, Ms. Rainer would immediately vest in a pro-rated portion of the 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). 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 her death or disability. In the event of her qualifying termination related to a change in control, Ms. Rainer would immediately vest in all unvested restricted stock.

(6)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Ms. Rainer would be eligible to receive company-subsidized COBRA benefits for 12 months.

(7)	As of December 31, 2013, compensation and benefits available to Ms. Rainer under this scenario are substantially the same as available with a voluntary resignation.

(8)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

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(1)

In addition to the payments and benefits in the table, if Mr. Rice's employment were terminated under certain conditions relating to a change in control, Mr. Rice also would have been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, see "2013 Pension Benefits." If Mr. Rice's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan.

(2)

In the event of a qualifying termination related to a change in control, Mr. Rice would be entitled to receive pursuant to the System Executive Continuity Plan, a lump sum severance payment equal to the product of one time the sum of (a) his 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 annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 40% target opportunity and a base salary of $257,144 was assumed.

(3)

In the event of a qualifying termination related to a change in control, Mr. Rice would have forfeited his performance units for the 2012-2014 and 2013-2015 performance periods and would have been entitled to receive, pursuant to the 2011 Equity Ownership Plan, a single-sum severance payment that would not be based on any outstanding performance periods. For both the 2012-2014 performance period and the 2013-2015 performance period, the payment would have been calculated using the average annual number of performance units he would have been entitled to receive under each 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. Rice’s severance payment was calculated by taking an average of the target performance units from the 2009-2011 Performance Unit Program (900 units) and the 2010-2012 Performance Unit Program (1,000 units). This average number of units (950 units) multiplied by the closing price of Entergy stock on December 31, 2013 ($63.27) would equal a severance payment of $60,107 for the forfeited performance units.

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(4)

In the event of his death, disability or qualifying termination related to a change in control, all of Mr. Rice's unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Rice exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2013, and the applicable exercise price of each option share. As of December 31, 2013, the closing stock price of Mr. Rice’s unvested options fell below the exercise prices and accordingly are considered “underwater” and are excluded from the table.

(5)

In the event of his death or disability, Mr. Rice would immediately vest in a pro-rated portion of the 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). 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 death or disability. In the event of his qualifying termination related to a change in control, Mr. Rice would immediately vest in all unvested restricted stock.

(6)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Rice would be eligible to receive company-subsidized COBRA benefits for 12 months.

(7)	As of December 31, 2013, compensation and benefits available to Mr. Rice under this scenario are substantially the same as available with a voluntary resignation.

(8)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

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(1)

In addition to the payments and benefits in the table, if Mr. West’s employment were terminated under certain conditions relating to a change in control, Mr. West also would have been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, see “2013 Pension Benefits.” If Mr. West’s employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan.

(2)

In the event of a qualifying termination related to a change in control, Mr. West would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to the product of 2.99 times the sum of (a) his 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 annual incentive, calculated using the average annual target opportunity under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 70% target opportunity and a base salary of $612,726 was assumed.

(3)

In the event of a qualifying termination related to a change in control, Mr. West would have forfeited his performance units for the 2012-2014 and 2013-2015 performance periods and would have been entitled to receive, pursuant to the 2011 Equity Ownership Plan, a single-sum severance payment that would not be based on any outstanding performance periods. For both the 2012-2014 performance period and the 2013-2015 performance period, the payment would have been 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. West’s severance payment was calculated by taking an average of the target performance units from the 2009-2011 Performance Unit Program (4,800 units) and the 2010-2012 Performance Unit Program (5,300 units). This average number of units (5,050 units) multiplied by the closing price of Entergy stock on December 31, 2013 ($63.27) would equal a severance payment of $319,514 for the forfeited performance units.

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(4)

In the event of his death, disability or qualifying termination related to a change in control, all of Mr. West’s unvested stock options would immediately vest. In addition, he would be entitled to exercise any unexercised options during a ten-year term extending from the grant date of the options. For purposes of this table, we assumed that Mr. West exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2013, and the exercise price of each option share. As of December 31, 2013, the closing stock price of Mr. West’s unvested options fell below the exercise prices and accordingly are considered “underwater” and are excluded from the table.

(5)

In the event of his death or disability, Mr. West would immediately vest in a pro-rated portion of the 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). 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 death or disability. In the event of his qualifying termination related to a change in control, Mr. West would immediately vest in all unvested restricted stock.

(6)

Mr. West’s 21,000 restricted units vest 100% in 2018. Pursuant to his restricted unit agreement, any unvested restricted units will vest immediately in the event of a termination for a reason other than cause, total disability or death. The units will vest upon termination within 24 months of a change in control without cause or by Mr. West with good reason. If Mr. West voluntarily resigned or was terminated for cause, he would forfeit these units.

(7)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. West would be eligible to receive company-subsidized COBRA benefits for 18 months.

(8)	As of December 31, 2013, compensation and benefits available to Mr. West under this scenario are substantially the same as available with a voluntary resignation.

(9)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

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

•	the merger or consolidation of Entergy Corporation (unless Entergy Corporation's 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

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•	a change in the composition of Entergy Corporation's board such that, during any two-year period, the individuals serving at the beginning of the period no longer constitute a majority of Entergy Corporation's board at the end of the period.

•	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 injurious to Entergy Corporation or any of its subsidiaries;

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

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

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

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

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

•	he or she is required to be based outside of the continental United States at somewhere other than the 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 employment is purported to be terminated other than in accordance with the System Executive Continuity Plan.

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

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

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

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

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

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•	all unvested stock options will vest immediately;

•	vested stock options will expire ten years from the grant date; and

•	restricted units may be subject to specific death benefits depending on the restricted unit agreement (as noted, where applicable, in the tables above).

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

(2)

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.  For directors of Entergy Corporation the phantom units are issued under the Service Recognition Program for Outside Directors.  All non-employee directors are credited with units for each year of service on the Board.  In addition, Messrs. Edwards and Hintz have deferred receipt

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(1)

Includes the Equity Ownership Plan, which was approved by the shareholders on May 15, 1998, the 2007 Equity Ownership Plan and the 2011 Equity Ownership Plan.  The 2007 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 12, 2006, and 7,000,000 shares of Entergy Corporation common stock can be issued, with no more than 2,000,000 shares available for non-option grants.  The 2011 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 6, 2011, and 5,500,000 shares of Entergy Corporation common stock can be issued from the 2011 Equity Ownership Plan, with no more than 2,000,000 shares available for incentive stock option grants.  The Equity Ownership Plan, the 2007 Equity Ownership Plan and the 2011 Equity Ownership Plan (the “Plans”) are administered by the Personnel Committee of the Board of Directors (other than with respect to awards granted to non-employee directors, which awards are administered by the entire Board of Directors).  Eligibility under the Plans is limited to the non-employee directors and to the officers and employees of an Entergy System employer and any corporation 80% or more of whose stock (based on voting power) or value is owned, directly or indirectly, by Entergy Corporation.  The Plans provide for the issuance of stock options, restricted shares, equity awards (units whose value is related to the value of shares of the Common Stock but do not represent actual shares of Common Stock), performance awards (performance shares or units valued by reference to shares of Common Stock or performance units valued by reference to financial measures or property other than Common Stock) and other stock-based awards.

(2)	Entergy has a Board-approved stock-based compensation plan. However, effective May 9, 2003, the Board has directed that no further awards be issued under that plan. As of December 31, 2013, all options outstanding under the plan were either exercised or expired.

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•	Whether the proposed transaction is on terms at least as favorable to Entergy Corporation or the subsidiary as those achievable 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 or subcommittee deems relevant.

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

(b)	Includes fees for tax advisory services.

(c)	100% of fees paid in 2013 and 2012 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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