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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;

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

•	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 increase in the energy efficiency rider at Entergy Arkansas, as approved by the APSC, effective July 2013.  Energy efficiency revenues are largely offset by costs included in other operation and maintenance expenses and have minimal effect on net income; 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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higher volume in its nuclear fleet resulting from fewer unplanned and refueling outage days in second quarter 2014 as compared to second quarter 2013, partially offset by a larger exercise of resupply options in second quarter 2013 compared to second quarter 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;

•	higher capacity prices;

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

•	an increase in nuclear fuel expenses primarily due to increased generation as a result of fewer outage days, partially offset by lower DOE spent fuel disposal fees.

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a decrease of $22 million in payroll, 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, and other postretirement benefit plan design changes.  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 $14 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;

•	a decrease of $13 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business;

•	a decrease of $10 million in fossil-fueled generation expenses primarily resulting from a lower scope of work done during plant outages in 2014 as compared to the same period in 2013; and

•	a decrease of $5 million due to costs incurred in 2013 related to the implementation of and transition to the MISO RTO.

•	an increase of $8 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 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; and

•	an increase of $6 million in storm damage accruals primarily at Entergy Arkansas effective January 2014, as approved by the APSC, and Entergy Mississippi effective October 2013, as approved by the MPSC.

•	$10 million in expenses incurred in the second 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

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•	$5 million in transmission service credits received in the second quarter 2013.

•

a decrease of $5 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, and other postretirement benefit plan design changes. 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 $4 million due to the absence of expenses from Entergy Solutions District Energy, which was sold in November 2013.

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

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

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

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

•	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 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; and

•	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.

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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 and refueling outage days in the six months ended June 30, 2014 compared to the six months ended June 30, 2013, partially offset by a larger exercise of resupply options in the six months ended June 30, 2013 compared to the six months ended June 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;

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

•	an increase in nuclear fuel expenses primarily due to increased generation as a result of fewer outage days, partially offset by lower DOE spent fuel disposal fees.

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a decrease of $37 million in payroll, 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, and other postretirement benefit plan design changes.  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 $23 million in fossil-fueled generation expenses primarily resulting from a lower scope of work done during plant outages in 2014 as compared to the same period in 2013;

•	a decrease of $19 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business;

•	a decrease of $14 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; and

•	a decrease of $9 million due to costs incurred in 2013 related to the implementation of and transition to the MISO RTO.

•	an increase of $18 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 $14 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; and

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•	an increase of $13 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.

•	$19 million in expenses incurred in the six months ended June 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

•	$8 million in transmission service credits received in the six months ended June 30, 2013.

•

a decrease of $9 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, and other postretirement benefit plan design changes. 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 $7 million due to the absence of expenses from Entergy Solutions District Energy, which was sold in November 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;

•	a decrease in income tax payments of $69 million in the six months ended June 30, 2014 compared to the six months ended June 30, 2013; and

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

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•	the withdrawal of a total of $252 million from Entergy Louisiana’s and Entergy Gulf States Louisiana’s storm reserve escrow accounts in 2013 as a result of Hurricane Isaac.  See Note 2 to the financial statements herein and in the Form 10-K for a discussion of Hurricane Isaac;

•	deposit of Entergy Louisiana bond proceeds with a trustee in June 2014. Entergy Louisiana issued $170 million of 5.0% Series first mortgage bonds in June 2014 and used the proceeds, in July 2014, to redeem, prior to maturity, its $70 million of 6.4% Series first mortgage bonds due October 2034 and its $100 million of 6.3% Series first mortgage bonds due September 2035; and

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

•	a decrease in construction expenditures, primarily in the Utility business, including a decrease in spending on the Ninemile 6 self-build project, spending in 2013 on the generator stator incident at ANO, and spending in 2013 on the Waterford 3 steam generator project, partially offset by an increase in storm restoration spending;

•	a change in collateral deposit activity, reflected in the “Increase in other investments” line on the Consolidated Statement of Cash Flows, as Entergy received net deposits of $28 million in 2014 and returned net deposits of $34 million in 2013.  Entergy Wholesale Commodities’s forward sales contracts are discussed in the “Market and Credit Risk Sensitive Instruments” section below; and

•	$24 million in insurance proceeds received in the first quarter 2014 for property damages related to the generator stator incident at ANO, as discussed above.

•	long-term debt activity providing approximately $7 million of cash in 2014 compared to using $36 million of cash in 2013.  Included in the long-term debt activity is $60 million in 2014 and $605 million in 2013 for the repayment of borrowings on the Entergy Corporation long-term credit facility;

•	Entergy Corporation repaid $136 million of commercial paper in 2014 and issued, in part, $283 million in 2013 to repay borrowings on its long-term credit facility;

•	a net increase of $188 million in 2014 in short-term borrowings by the nuclear fuel company variable interest entities;

•	$70 million in short-term borrowings under the Utility operating companies’ credit facilities in 2013;

•	an increase of $65 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; and

•	the repurchase of $18 million of common stock in 2014.

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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 prior to receiving market-based rate authority under MISO.  The percentage sold assumes completion of the necessary transmission upgrades required for the approved 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’ 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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•	a $9.3 million base rate revenue increase to be phased in on a levelized basis over four years;

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

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

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(a)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension cost.  See Note 6 to the financial statements herein for additional details.

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(a)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension cost.  See Note 6 to the financial statements herein for additional details.

(a)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension cost.  See Note 6 to the financial statements herein for additional details.

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(a)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension cost.  See Note 6 to the financial statements herein for additional details.

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(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost.  See Note 6 to the financial statements herein for additional details.

(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost.  See Note 6 to the financial statements herein for additional details.

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(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost.  See Note 6 to the financial statements herein for additional details.

(a)	These accumulated other comprehensive loss components are included in the computation of net periodic pension cost.  See Note 6 to the financial statements herein for additional details.

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(a)	The interest rate is the rate as of June 30, 2014 that would most likely apply to outstanding borrowings under the facility.

(b)	Borrowings under the Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable at Entergy Arkansas’s option.

(c)	The credit facility allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility.  As of June 30, 2014, $11 million in letters of credit were outstanding.

(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 June 30, 2014, $50 million in letters of credit were outstanding.

(e)	The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility.  As of June 30, 2014, $7.4 million in letters of credit were outstanding.

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

(g)	The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility.  As of June 30, 2014, $23.3 million in letters of credit were outstanding.

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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)	The values exclude lease obligations of $132 million at Entergy Louisiana and $51 million at System Energy, long-term DOE obligations of $181 million at Entergy Arkansas, and the note payable to NYPA of $96 million at Entergy, and include debt due within one year.

(b)	Fair values are classified as Level 2 in the fair value hierarchy discussed in Note 8 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported trades.

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(a)	The values exclude 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 include debt due within one year.

(b)	Fair values are classified as Level 2 in the fair value hierarchy discussed in Note 8 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported trades.

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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 $13 million posted as of June 30, 2014 and $47 million posted and $4 million held as of December 31, 2013, respectively

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(a)	Due to regulatory treatment, the natural gas swaps are marked-to-market through fuel, fuel-related expenses, and gas purchased for resale and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability.  The gains or losses recorded as fuel expenses when the swaps are settled are recovered or refunded through fuel cost recovery mechanisms.

(b)	Due to regulatory treatment, the changes in the estimated fair value of FTRs are recorded through purchased power expense and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability.  The gains or losses recorded as purchased power expense when the FTRs are settled are recovered or refunded through fuel cost recovery mechanisms.

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(a)	No cash collateral was required to be posted as of June 30, 2014 and December 31, 2013, respectively.

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•

Level 1 - Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the entity has the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.  Level 1 primarily consists of individually owned common stocks, cash equivalents (temporary cash investments, securitization recovery trust account, and escrow accounts), debt instruments, and gas hedge contracts.  Cash equivalents includes all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at the date of purchase.

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

-	inputs that are derived principally from or corroborated by observable market data by correlation or other means.

•	Level 3 - Level 3 inputs are pricing inputs that are generally less observable or unobservable from objective sources.  These inputs are used with internally developed methodologies to produce management’s best estimate of fair value for the asset or liability.  Level 3 consists primarily of FTRs and derivative power contracts used as cash flow hedges of power sales at merchant power plants.

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(a)	The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices.  Fixed income securities are held in various governmental and corporate securities.  See Note 9 to the financial statements herein 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

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

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•	a decrease of $27 million in rider revenues due to the absence of System Agreement production cost equalization revenue as compared to the same period in 2013. These revenues are offset in deferred fuel expenses. See Note 2 to the financial statements herein and in the Form 10-K for a discussion of the FERC orders in the System Agreement production cost equalization proceedings; and

•	the decrease in volume/weather, as discussed above.

•	a decrease in the recovery from customers of deferred fuel costs due to higher fuel and purchased power costs and System Agreement production cost equalization payments in 2013; and

•	a higher volume of lower-priced nuclear generation in 2014 as a result of the ANO extended outage in 2013.

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•	a decrease of $56.7 million in rider revenues due to the absence of System Agreement production cost equalization revenue as compared to the same period in 2013. These revenues are offset in deferred fuel expenses. See Note 2 to the financial statements herein and in the Form 10-K for a discussion of the FERC orders in the System Agreement production cost equalization proceedings; and

•	a decrease of $7.9 million in fuel cost recovery revenues as a result of lower fuel rates.

•	a decrease in the recovery from customers of deferred fuel costs due to lower fuel rates and System Agreement production cost equalization payments in 2013; and

•	a higher volume of lower-priced nuclear generation in 2014 as a result of the ANO extended outage in 2013.

•	an increase of $6.7 million in nuclear generation expenses primarily due to a higher level of capitalization of nuclear labor costs in 2013 as a result of the generator stator incident at ANO;

•	an increase of $6.6 million in energy efficiency costs.  These costs are recovered through the energy efficiency rider and have a minimal effect on net income;

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•	an increase of $3.3 million due to increases in storm damage accruals effective January 2014, as approved by the APSC;

•	the effects in 2013 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;

•	an increase of $2.1 million in transmission expenses primarily due to vegetation maintenance and higher transmission service expenses;

•	an increase of $1.7 million due to administration fees in 2014 related to participation in the MISO RTO;

•	an increase of $1.6 million due to the amortization in 2014 of human capital management costs that were deferred in 2013, as approved by the APSC. See Note 2 to the financial statements in the Form 10-K for further discussion of the deferral of these costs;

•	an increase of $1.6 million in fossil-fueled generation expenses primarily due to higher plant outage costs in 2014; and

•	an increase of $1.2 million due to the amortization in 2014 of costs deferred in 2013 related to the transition and implementation of joining the MISO RTO, as discussed above.

•	a decrease of $14 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;

•	a decrease of $4.7 million in compensation and benefits costs primarily due to an increase in the discount rates

•	a decrease of $3.1 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business; and

•	several individually insignificant items.

•	an increase of $12.8 million in energy efficiency costs. These costs are recovered through the energy efficiency rider and have a minimal effect on net income;

•	an increase of $7.2 million in nuclear generation expenses primarily due to a higher level of capitalization of nuclear labor costs in 2013 as a result of the generator stator incident at ANO;

•	an increase of $7.1 million due to an increase in storm damage accruals effective January 2014, as approved by the APSC;

•	an increase of $3.6 million due to administration fees in 2014 related to participation in the MISO RTO;

•	the effects in 2013 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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•	an increase of $3.2 million due to the amortization in 2014 of human capital management costs that were deferred in 2013, as approved by the APSC. See Note 2 to the financial statements in the Form 10-K for further discussion of the deferral of these costs; and

•	an increase of $2.6 million due to higher transmission service expense in 2014.

•	a decrease of $14 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;

•

a decrease of $10.2 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and fewer employees. 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 $4.7 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 $4.3 million related to a true-up to the 2013 energy efficiency filing for fixed costs to be collected from customers in 2014.

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•	a decrease in income tax payments of $209.8 million. Entergy Arkansas made income tax payments of $211.4 million 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 in 2013 related to the generator stator incident at ANO, as discussed above; and

•	$8.8 million in insurance proceeds received in the first quarter 2014 for property damages related to the generator stator incident at ANO, as discussed above.

•	a $68 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period;

•	an increase of $24.7 million in pension contributions in 2014; and

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

•	money pool activity;

•	approximately $41 million in spending in 2013 related to the generator stator incident at ANO, as discussed above; and

•	$24.2 million in insurance proceeds received in the first quarter 2014 for property damages related to the generator stator incident at ANO, as discussed above.

•	fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and

•	an increase of $6.9 million in storm restoration spending in 2014.

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

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

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

•	the net borrowings of $39.7 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2014 compared to net repayments of $6.8 million in 2013;

•	common stock dividends of $15 million paid in 2013; and

•	money pool activity.

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

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

•	an increase in deferred fuel expense due to higher fuel cost recovery revenues as compared to prior year and the timing of receipt of System Agreement payments and credits to customers.

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•	an increase of $91.5 million in electric fuel cost recovery revenues primarily due to higher fuel rates;

•	an increase of $31.1 million in gross wholesale revenues primarily due to the timing of System Agreement payments and credits to customers and sales in the MISO market;

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

•	an increase of $9.9 million in natural gas fuel cost recovery revenues primarily due to higher fuel rates.

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

•	an increase in deferred fuel expense due to higher fuel cost recovery revenues as compared to prior year and the timing of receipt of System Agreement payments and credits to customers.

•	the deferral of investment gains from the River Bend decommissioning trust in 2013 in accordance with regulatory treatment. The gains resulted in an increase in 2013 in other income and a corresponding increase in regulatory charges with no effect on net income; and

•	the deferral in 2014 of non-fuel MISO-related charges, as approved by the LPSC. The deferral of non-fuel MISO-related charges is partially offset in operation and maintenance expenses. See Note 2 to the financial statements in the Form 10-K for further discussion of the recovery of non-fuel MISO-related charges.

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a decrease of $4.6 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and fewer employees.  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 $2.9 million in nuclear generation expenses primarily due to lower nuclear labor costs; and

•	a decrease of $2.4 million due to costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business.

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a decrease of $7.4 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and fewer employees.  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 $5.3 million in nuclear generation expenses primarily due to lower nuclear labor costs; and

•	a decrease of $4 million due to costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business.

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a decrease of $56 million in income tax payments for the six months ended June 30, 2014 compared to the six months ended June 30, 2013. Entergy Gulf States Louisiana had income tax payments of $61.7 million in 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The payments resulted primarily from the reversal of temporary differences for which Entergy Gulf States Louisiana had previously claimed a tax deduction;

•	lower nuclear refueling outage spending at River Bend. River Bend had a refueling outage in 2013 and did not have one in 2014; and

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an increase in the recovery of fuel and purchased power costs including System Agreement bandwidth remedy payments of $10.1 million received in the second quarter 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. In the second quarter 2014, Entergy Gulf States Louisiana customers were credited $3.7 million. See Note 2 to the financial statements herein and in the Form 10-K for a discussion of the System Agreement proceedings.

•	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;

•	a decrease in nuclear construction expenditures as a result of spending on nuclear projects during the River Bend refueling outage in 2013. River Bend had a refueling outage in 2013 and did not have one in 2014; and

•	a decrease in transmission construction expenditures due to a decreased scope of work performed in 2014.

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

•	an increase in fossil-fueled generation expenditures as a result of an increased scope of work in 2014; and

•	money pool activity.

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•	payments of $14.8 million on credit borrowings for the six months ended June 30, 2014 compared to an increase of $144.7 million in credit borrowings for the six months ended June 30, 2013 against the nuclear fuel company variable interest entity credit facility;

•	the issuance of $70 million of 3.38% Series R notes by the nuclear fuel company variable interest entity in February 2013; and

•	money pool activity.

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a decrease of $5.2 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and fewer employees.  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 $4.8 million in fossil-fueled generation expenses primarily due to an overall lower scope of work done as compared to prior year;

•	a decrease of $2.1 million due to costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business; and

•	a decrease of $1.9 million in nuclear generation expenses primarily due to lower materials costs.

•

a decrease of $7.5 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and fewer employees.  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 $3.6 million relating to the sale of surplus oil inventory in 2014;

•	a decrease of $3.0 million due to costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business; and

•	a decrease of $2.8 million in fossil-fueled generation expenses primarily due to an overall lower scope of work done as compared to prior year.

•	an increase of $4.9 million due to administration fees in 2014 related to the participation in the MISO RTO. The LPSC approved deferral of these expenses resulting in no net income effect; and

•	an increase of $4.4 million in transmission expenses primarily due to higher equalization expenses and additional transmission services.

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•	receipts of $187 million from the storm reserve escrow account in 2013;

•	deposit of bond proceeds with a trustee in June 2014. Entergy Louisiana issued $170 million of 5.0% Series first mortgage bonds in June 2014 and used the proceeds, in July 2014, to redeem, prior to maturity, its $70 million of 6.4% Series first mortgage bonds due October 2034 and its $100 million of 6.3% Series first mortgage bonds due September 2035; and

•	an increase 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.

•	the issuance of $170 million of 5.0% Series first mortgage bonds in June 2014 compared to the issuance of $100 million of 4.7% Series first mortgage bonds in May 2013;

•	the issuance of $40 million of 3.92% Series H Notes by the nuclear fuel company variable interest entity in February 2014;

•	a decrease of $65.4 million in common equity distributions in 2014;

•	money pool activity; and

•	an increase in borrowings of $23.9 million on the nuclear fuel company variable interest entity’s credit facility in 2014 compared to the repayment of borrowings of $12.9 million in 2013.

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

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

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

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

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•	an increase of $19.6 million in gross wholesale revenues due to the timing of receipt of System Agreement payments and an increase in sales to affiliated customers;

•	an increase of $11 million in fuel cost recovery revenues primarily due to higher fuel rates;

•	an increase of $7.1 million due to the formula rate plan increase, as discussed above;

•	an increase of $4.3 million primarily due to an increase in the storm damage rider, as discussed above; and

•	an increase of $3.8 million due to an increase in the power management rider, as approved by the MPSC, effective February 2014.

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•	an increase of $29.9 million in gross wholesale revenues due to an increase in sales to affiliated customers and the timing of receipt of System Agreement payments;

•	an increase of $26 million in fuel cost recovery revenues primarily due to higher fuel rates;

•	an increase of $15.4 million due to the formula rate plan increase, as discussed above;

•	an increase of $13.2 million due to an increase in the power management rider, as approved by the MPSC, effective February 2014;

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

•	an increase of $8.6 million primarily due to an increase in the storm damage rider, as discussed above.

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•	a decrease of $6.1 million in fossil-fueled generation expenses resulting from a lower scope of work done during plant outages in 2014 as compared to the same period in 2013, partially offset by Baxter Wilson (Unit 1) repair activities in 2014, as discussed below;

•	a decrease of $3.3 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 $2.8 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and fewer employees. 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.

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•	the timing of payments to vendors;

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

•	an increase of $8.4 million in income tax refunds in the six months ended June 30, 2014 as compared to the six months ended June 30, 2013. The income tax refunds in 2014 were refunds of income taxes paid in accordance with intercompany state income tax sharing arrangements.

•	the issuance of $100 million of 3.75% Series first mortgage bonds in March 2014;

•	the payment, at maturity, of $100 million of 5.15% Series first mortgage bonds in February 2013;

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

•	borrowings of $70 million on Entergy Mississippi’s credit facilities in the six months ended June 30, 2013.

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•	an increase of $40.1 million in gross wholesale revenue primarily due to increased sales to affiliate customers;

•	an increase of $10.2 million in gas fuel cost recovery revenues due to higher fuel rates;

•	an increase of $7.4 million in electric fuel cost recovery revenues due to an increase in volume; and

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

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

•	an increase in gas-fired generation as a result of a prior year outage; and

•	an increase in gas purchased for resale as a result of an increase in price and volume.

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•	money pool activity;

•	a decrease in fossil-fueled generation construction expenditures due to spending in 2013 on various projects; and

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

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•	a decrease of $3.3 million in fossil-fueled generation expenses resulting from an overall lower scope of work done compared to prior year;

•	a decrease of $2.6 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business;

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a decrease of $2.3 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and fewer employees.  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 $1.2 million in contract work relating primarily to vegetation maintenance.

•	a decrease of $5.8 million in fossil-fueled generation expenses resulting from an overall lower scope of work done compared to prior year;

•	a decrease of $4 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business;

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a decrease of $3.1 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, and fewer employees.  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 $1.4 million in contract work relating primarily to vegetation maintenance.

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•	$86.1 million of fuel cost refunds in the first quarter 2013. See Note 2 to the financial statements in the Form 10-K for discussion of the fuel cost refunds;

•	System Agreement bandwidth remedy payments of $48.6 million received in the second quarter 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period; and

•	the remaining $9.5 million of System Agreement bandwidth remedy receipts resulting from FERC’s October 2011 order for the period June - December 2005 were credited to Entergy Texas customers in the first quarter 2013.

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

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(a)	See Note 12 to the financial statements in the Form 10-K for additional discussion of the stock-based compensation plans.

(b)	Maximum amount of shares that may yet be repurchased relates only to the $500 million plan and 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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