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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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