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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;

•

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 proposed 60-month notice period or such other period as approved by the FERC;

•

regulatory and operating challenges and uncertainties and economic risks associated with the Utility operating companies’ move to the MISO RTO, which occurred in December 2013, including the effect of current or projected RTO market rules and system conditions in the MISO markets, the allocation of MISO system transmission upgrade costs, and the effect of planning decisions that MISO makes with respect to future transmission investments by the Utility operating companies;

•	changes in utility regulation, including the beginning or end of retail and wholesale competition, the ability to recover net utility assets and other potential stranded costs, and the application of more stringent transmission reliability requirements or market power criteria by the FERC;

•	changes in the regulation or regulatory oversight of Entergy’s nuclear generating facilities and nuclear materials and fuel, including with respect to the planned 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 or other authorizations required 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, and the effect of those changes on Entergy and its customers;

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

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

•	uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel and nuclear waste storage and disposal and the level of spent fuel disposal fees charged by the U.S. government related to such sites;

•	variations in weather and the occurrence of hurricanes and other storms and disasters, including uncertainties associated with efforts to remediate the effects of hurricanes, ice storms, or other weather events and the recovery of costs associated with restoration, including accessing funded storm reserves, federal and local cost recovery mechanisms, securitization, and insurance;

•	effects of climate change;

•	changes in the quality and availability of water supplies and the related regulation of water use and diversion;

•	Entergy’s ability to manage its capital projects and operation and maintenance costs;

•	Entergy’s ability to purchase and sell assets at attractive prices and on other attractive terms;

•	the economic climate, and particularly economic conditions in Entergy’s Utility service area and the Northeast United States and events and circumstances that could influence economic conditions in those areas, and the risk that anticipated load growth may not materialize;

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

•	changes in the financial markets, particularly those affecting the availability of capital and Entergy’s ability to refinance existing debt, execute share repurchase programs, and fund investments and acquisitions;

•	actions of rating agencies, including changes in the ratings of debt and preferred stock, changes in general corporate ratings, and changes in the rating agencies’ ratings criteria;

•	changes in inflation and interest rates;

•	the effect of litigation and government investigations or proceedings;

•	changes in technology, including with respect to new, developing, or alternative sources of generation;

•	the 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 operation of 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.  Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.

(a)	Parent & Other includes eliminations, which are primarily intersegment activity.

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

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

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

•	an annual base rate increase at Entergy Arkansas, as approved by the APSC, effective January 2014; and

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

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•	lower volume in its nuclear fleet resulting from more refueling outage days in the third quarter 2014 as compared to the third quarter 2013;

•	mark-to-market activity, which was negative for the quarter. See Note 8 to the financial statements herein for discussion of derivative instruments;

•	higher capacity prices, partially offset by lower realized wholesale energy prices; and

•	a decrease in nuclear fuel expenses primarily due to lower DOE spent fuel disposal fees.

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•	an increase of $21 million in nuclear generation expenses primarily due to higher contract labor costs, higher materials costs, and higher NRC fees;

•	an increase of $11 million in energy efficiency costs at Entergy Arkansas and Entergy Texas.  These costs are recovered through energy efficiency riders and have a minimal effect on net income;

•	an increase of $10 million due to administration fees in 2014 related to participation in the MISO RTO. The net income effect is partially offset due to deferrals of these fees in certain jurisdictions. See Note 2 to the financial statements in the Form 10-K for further information on deferrals;

•	an increase of $7 million in storm damage accruals primarily at Entergy Mississippi effective October 2013, as approved by the MPSC, and Entergy Arkansas effective January 2014, as approved by the APSC;

•	an increase of $3 million resulting from costs incurred in the third quarter 2014 related to Baxter Wilson (Unit 1) repairs, including an offset for expected insurance proceeds. See “Baxter Wilson Plant Event” in Note 1 to the financial statements herein for further discussion;

•	an increase of $3 million as a result of higher write-offs of uncollectible customer accounts; and

•	several individually insignificant items.

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a decrease of $40 million in compensation and benefits costs primarily due to fewer employees, an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan.  See "MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS – Critical Accounting Estimates" in the Form 10-K and Note 6 to the financial statements herein for further discussion of benefits costs;

•	a decrease of $11 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business; and

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a decrease of $6 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative, including an offset for partial amortization in the third quarter 2014 of costs deferred in 2013. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Human Capital Management Strategic Imperative” in the Form 10-K for further discussion.

•	an increase in earnings on decommissioning trust fund investments;

•	an increase due to distributions earned on preferred membership interests purchased from Entergy Holdings Company with the proceeds received in August 2014 from the Act 55 storm cost financing. The distributions on preferred membership interests are eliminated in consolidation and have no effect on Entergy's net income because the investment is in another Entergy subsidiary; and

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

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a decrease of $29 million in compensation and benefits costs primarily due to fewer employees, an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See "MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates" in the Form 10-K and Note 6 to the financial statements herein for further discussion of benefits costs; and

•	a decrease of $5 million due to the absence of expenses from Entergy Solutions District Energy, which was sold in November 2013.

•	an increase of $10 million primarily due to higher contract labor costs and higher NRC fees;

•	$10 million incurred in the third quarter 2014 related to the shutdown of Vermont Yankee including severance and retention costs. See “Impairment of Long-Lived Assets” in Note 11 to the financial statements herein for discussion regarding the planned shutdown of the Vermont Yankee plant by the end of 2014; and

•	$5 million in transmission imbalance sales in the third quarter 2013.

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(a)	Parent & Other includes eliminations, which are primarily intersegment activity.

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

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

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

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

•	an increase in purchased power capacity costs at Entergy Louisiana and Entergy Gulf States Louisiana that are recovered through base rates set in the annual formula rate plan mechanisms; and

•	an annual base rate increase at Entergy Arkansas, as approved by the APSC, effective January 2014.

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

•

higher volume in its nuclear fleet resulting from fewer unplanned outage days in the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013, partially offset by a larger exercise of resupply options in the nine months ended September 30, 2013 compared to the nine months ended September 30, 2014 provided for in purchase power agreements where Entergy Wholesale Commodities may elect to supply power from another source when the plant is not running. Amounts related to the exercise of resupply options are included in the GWh billed in the table below; and

•	mark-to-market activity, which was positive for the nine months ended September 30, 2014. See Note 8 to the financial statements herein for discussion of derivative instruments.

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a decrease of $93 million in compensation and benefits costs primarily due to fewer employees, an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan.  See "MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS – Critical Accounting Estimates" in the Form 10-K and Note 6 to the financial statements herein for further discussion of benefits costs;

•	a decrease of $30 million in fossil-fueled generation expenses primarily resulting from an overall lower scope of work done in 2014 as compared to the same period in 2013;

•	a decrease of $30 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business; and

•	a decrease of $11 million resulting from costs incurred in 2013 related to the generator stator incident at ANO, including an offset for insurance proceeds. See “ANO Damage and Outage” below for further discussion of the incident.

•	an increase of $30 million in nuclear generation expenses primarily due to higher contract labor costs, higher materials costs, and higher NRC fees;

•	an increase of $28 million due to administration fees in 2014 related to participation in the MISO RTO. The net income effect is partially offset due to deferrals of these fees in certain jurisdictions. See Note 2 to the financial statements in the Form 10-K for further information on deferrals;

•	an increase of $25 million in energy efficiency costs at Entergy Arkansas and Entergy Texas.  These costs are recovered through energy efficiency riders and have a minimal effect on net income;

•	an increase of $21 million in storm damage accruals primarily at Entergy Arkansas effective January 2014, as approved by the APSC, and at Entergy Mississippi effective October 2013, as approved by the MPSC;

•	an increase of $10 million resulting from costs incurred in 2014 related to Baxter Wilson (Unit 1) repairs, including an offset for expected insurance proceeds. See “Baxter Wilson Plant Event” in Note 1 to the financial statements herein for further discussion; and

•	an increase of $5 million as a result of higher write-offs of uncollectible customer accounts.

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a decrease of $52 million in compensation and benefits costs primarily due to fewer employees, an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See "MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates" in the Form 10-K and Note 6 to the financial statements herein for further discussion of benefits costs; and

•	a decrease of $12 million due to the absence of expenses from Entergy Solutions District Energy, which was sold in November 2013.

•	an increase of $28 million primarily due to higher contract labor costs and higher NRC fees;

•	$25 million incurred in the nine months ended September 30, 2014 related to the shutdown of Vermont Yankee including severance and retention costs. See “Impairment of Long-Lived Assets” in Note 11 to the financial statements herein for discussion regarding the planned shutdown of the Vermont Yankee plant by the end of 2014; and

•	$13 million in transmission imbalance sales in 2013.

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

•	proceeds of $310 million received from the LURC in August 2014 as a result of the Louisiana Act 55 storm cost financing. See Note 2 to the financial statements herein and in the Form 10-K and “Hurricane Isaac” above for a discussion of the Act 55 storm cost financing;

•	a decrease in income tax payments of $60 million in the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013; and

•	approximately $27 million in spending in 2013 related to the generator stator incident at ANO, as discussed previously.

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•	the deposit of a total of $268 million into Entergy Louisiana’s and Entergy Gulf States Louisiana’s storm escrow accounts in 2014;

•	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; and

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

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

•	a change in collateral deposit activity, reflected in the “Decrease (increase) in other investments” line on the Consolidated Statement of Cash Flows, as Entergy received net deposits of $37 million in 2014 and returned net deposits of $49 million in 2013.  Entergy Wholesale Commodities’s forward sales contracts are discussed in the “Market and Credit Risk Sensitive Instruments” section below;

•	a decrease in nuclear fuel purchases due to variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and

•	$29 million in insurance proceeds received in 2014 for property damages related to the generator stator incident at ANO, as discussed above.

•	long-term debt activity providing approximately $132 million of cash in 2014 compared to using $180 million of cash in 2013.  Included in the long-term debt activity is $10 million in 2014 and $645 million in 2013 for the repayment of borrowings on the Entergy Corporation long-term credit facility;

•	Entergy Corporation repaid $269 million of commercial paper in 2014 and issued $351 million in 2013;

•	a net increase of $153 million in 2014 in short-term borrowings by the nuclear fuel company variable interest entities; and

•	an increase of $67 million in treasury stock issuances in 2014 primarily due to a larger amount of previously repurchased Entergy Corporation common stock issued in 2014 to satisfy stock option exercises.

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(a)	Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts, or options that mitigate price uncertainty that may require regulatory approval or approval of transmission rights. Positions that are no longer classified as hedges are netted in the planned generation under contract.

(b)	Transaction under which power is supplied from a specific generation asset; if the asset is not operating, 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 11 to the financial statements herein.  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 and in the Form10-K.

(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

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(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’ wind investment. The decrease in planned net MW in operation beginning in 2017 is due to the expiration of a non-affiliated 75 MW contact.

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