UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, (as definedor a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Securities Exchange Act of 1934).Act.

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).

Entergy Corporation, Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc.,LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., and System Energy Resources, Inc. separately file this combined Quarterly Report on Form 10-Q. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company reports herein only as to itself and makes no other representations whatsoever as to any other company. This combined Quarterly Report on Form 10-Q supplements and updates the Annual Report on Form 10-K for the calendar year ended December 31, 2004,2005, and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2005,2006, filed by the individual registrants with the SEC, and should be read in conjunction therewith.

ENTERGY CORPORATION AND SUBSIDIARIES
INDEX TO QUARTERLY REPORT ON FORM 10-Q
June 30, 20052006

ENTERGY CORPORATION AND SUBSIDIARIES
INDEX TO QUARTERLY REPORT ON FORM 10-Q
June 30, 2006

ENTERGY CORPORATION AND SUBSIDIARIES
INDEX TO QUARTERLY REPORT ON FORM 10-Q
June 30, 2005

FORWARD-LOOKING INFORMATION

In this filing and from time to time, Entergy makes statements concerning its expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Although Entergy believes that these forward-looking statements and the underlying assumptions are reasonable, it cannot provide assurance that they will prove correct. Except to the extent required by the federal securities laws, Entergy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in the statements. Some of those factors (in addition to the risk factors in the Form 10-K as well as others described elsewhere in this report and in subsequent securities filings) include:

• resolution of pending and future rate cases and negotiations, including various performance-based rate discussions and implementation of new Texas legislation, and other regulatory proceedings, including those related to Entergy's System Agreement and Entergy's utility supply plan
• Entergy's ability to manage its operation and maintenance costs
• the performance of Entergy's generating plants, and particularly the capacity factors at its nuclear generating facilities
• prices for power generated by Entergy's unregulated generating facilities, the ability to hedge, sell power forward or otherwise reduce the market price risk associated with those facilities, including the Non-Utility Nuclear plants, the ability to meet credit support requirements, and the prices and availability of power and fuel Entergy must purchase for its utility customers and operations
• Entergy's ability to develop and execute on a point of view regarding prices of electricity, natural gas, and other energy-related commodities
• changes in the financial markets, particularly those affecting the availability of capital and Entergy's ability to refinance existing debt, execute its share repurchase program, 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, interest rates, and foreign currency exchange rates
• Entergy's ability to purchase and sell assets at attractive prices and on other attractive terms
• volatility and changes in markets for electricity, natural gas, uranium, and other energy-related commodities
• 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, the establishment of a regional transmission organization that includes Entergy's utility service territory, and the application of market power criteria by the FERC
• changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown of nuclear generating facilities, particularly those in the northeastern United States
• uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel storage and disposal
• resolution of pending or future applications for license extensions or modifications of nuclear generating facilities
• changes in law resulting from the new federal energy legislation, including the repealeffects of PUHCA repeal
• changes in environmental, tax, and other laws, including requirements for reduced emissions of sulfur, nitrogen, carbon, mercury, and other substances
• the economic climate, and particularly growth in Entergy's service territory
• variations in weather and the occurrence of hurricanes and other storms and disasters, including uncertainties associated with efforts to remediate the effects of Hurricanes Katrina and Rita and recovery of costs associated with restoration including Entergy's ability to obtain financial assistance from governmental authorities in connection with these storms
• advances in technologythe outcome of the Chapter 11 bankruptcy proceeding of Entergy New Orleans, and the impact of this proceeding on other Entergy companies
• the potential effects of threatened or actual terrorism and war
• the effects of Entergy's strategies to reduce tax payments
• the effects of litigation and government investigations
• changes in accounting standards, corporate governance, and securities law requirements
• Entergy's ability to attract and retain talented management and directors

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DEFINITIONS

Certain abbreviations or acronyms used in the text are defined below:

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DEFINITIONS (Continued)

DEFINITIONS (Continued)

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DEFINITIONS(Concluded)

DEFINITIONS(Concluded)

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ENTERGY CORPORATION AND SUBSIDIARIES

MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS

Entergy operates primarily through two business segments: Utility and Non-Utility Nuclear.

• Utilitygenerates, transmits, distributes, and sells electric power in a four-state service territory that includes portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operates a small natural gas distribution business.
• Non-Utility Nuclearowns and operates five nuclear power plants located in the northeastern United States and sells the electric power produced by those plants primarily to wholesale customers. This business also provides services to other nuclear power plant owners.

In addition to its two primary, reportable, operating segments, Entergy also operates the Energy Commodity Services segment and the Competitive Retail Services business. Energy Commodity Services includes Entergy-Koch, LP and Entergy's non-nuclear wholesale assets business. Entergy-Koch sold its businesses in the fourth quarter of 2004 and is no longer an operating entity. In April 2006, Entergy sold the retail electric portion of the Competitive Retail Services business operating in the ERCOT region of Texas, and now reports this portion of the business as a discontinued operation. Entergy reports Energy Commodity Services and Competitive Retail Services as part of All Other in its segment disclosures.

Hurricane Katrina and Hurricane Rita

See the Form 10-K for a discussion of the effects of Hurricanes Katrina and Rita, which in August and September 2005 caused catastrophic damage to portions of the Utility's service territory in Louisiana, Mississippi, and Texas, including the effect of extensive flooding that resulted from levee breaks in and around the greater New Orleans area. Following are updates to the discussion in the Form 10-K.

Community Development Block Grants (CDBG)

As discussed in the Form 10-K, a federal hurricane aid package became law that includes funding for Community Development Block Grants (CDBG) that allows state and local leaders to fund individual recovery priorities. The law permits funding for infrastructure restoration. It is uncertain how much funding, if any, will be designated for utility reconstruction and the timing of such decisions is also uncertain. The U.S. Department of Housing and Urban Development has allocated approximately $10.4 billion for Louisiana, $5.1 billion for Mississippi, and $74 million for Texas, with an additional $1 billion approved by Congress but not yet allocated to the states. The states, in turn, will administer the grants. Entergy is currently preparing applications to seek CDBG funding. In March 2006, Entergy New Orleans, Entergy Louisiana, and Entergy Gulf States-Louisiana provided justification statements to state and local officials. The statements, which will be reviewed by the Louisiana Recovery Authority, include the estimated costs of Hurricanes Katrina and Rita damage, as well as for Entergy New Orleans a lost customer base component intended to help offset the need for storm-related rate increases. The statements include justification for requests for CDBG funding of $718 million by Entergy New Orleans, $472 million by Entergy Louisiana, and $164 million by Entergy Gulf States-Louisiana. As discussed further below, in June 2006 Entergy Mississippi filed a request with the Mississippi Development Authority for $89 million of CDBG funding for reimbursement of its Hurricane Katrina infrastructure restoration costs.

Storm Costs Recovery Filings with Retail Regulators

On July 31, 2006, Entergy Louisiana and Entergy Gulf States filed a supplemental and amending storm cost recovery application with the LPSC, in which Entergy Louisiana and Entergy Gulf States requested that the LPSC (1) review Entergy Louisiana's and Entergy Gulf States' testimony and exhibits relating to the costs associated with Hurricanes Katrina and Rita, and declare that those verified, actual storm-related costs through May 31, 2006 are $466.8 million for Entergy Louisiana and $200.3 million for Entergy Gulf States in the Louisiana jurisdiction and that

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those costs were prudently incurred; (2) declare that the annual revenue requirements associated with the recovery of those costs, based on a ten-year levelized rate are $54.4 million for Entergy Louisiana and $26.2 million for Entergy Gulf States; (3) authorize Entergy Louisiana and Entergy Gulf States to recover the costs through Storm Cost Recovery Riders (SCRRs) proposed by Entergy Louisiana and Entergy Gulf States; (4) declare that the storm costs incurred subsequent to May 31, 2006 are to be filed by Entergy Louisiana and Entergy Gulf States with the LPSC on an annual basis in connection with their annual formula rate plan (FRP) filings, and that the SCRRs be adjusted annually to reflect such costs and any insurance proceeds or CDBG funds actually received, with the adjusted amounts to be collected through the SCRRs to take effect contemporaneous with the effective date of rate changes under the FRP; (5) declare that the storm-related costs incurred by Entergy Louisiana an d Entergy Gulf States meet the conditions set forth in the FRP for exclusion from the sharing provisions in those FRPs and authorize the permanent recovery of storm costs outside of the FRPs adopted by the LPSC for Entergy Louisiana and Entergy Gulf States; and (6) authorize the funding of a storm reserve through securitization sufficient to fund a storm cost reserve of $132 million for Entergy Louisiana and $81 million for Entergy Gulf States. Hearings on the application are scheduled for the first quarter 2007.

In July 2006, Entergy Gulf States filed an application with the PUCT with respect to the $393.2 million of Hurricane Rita reconstruction costs incurred in its Texas retail jurisdiction through March 31, 2006. The filing asks the PUCT to determine that $393.2 million is the amount of reasonable and necessary hurricane reconstruction costs eligible for securitization and recovery, approve the recovery of carrying costs, and approve the manner in which Entergy Gulf States-Texas allocates those costs among its retail customer classes.  If approved, Entergy Gulf States' application will ultimately affect all its retail customers in Texas. Entergy Gulf States' filing does not request recovery of costs through a specific rider on customer bills or through any other means at this time. The hearing before the PUCT on the filing is scheduled for November 2006. This is the first of two filings authorized by a law passed earlier this year in a special session of the Texas Legislature. A second filing will request securitization and recovery of the eligible costs through retail rates and tariffs. Entergy Gulf States expects to make the second filing following the conclusion of the reconstruction cost case.

As discussed in the Form 10-K, in December 2005, Entergy Mississippi filed with the MPSC a Notice of Intent to change rates by implementing a Storm Damage Rider to recover storm damage restoration costs associated with Hurricanes Katrina and Rita totaling approximately $84 million as of November 30, 2005.  In February 2006, Entergy Mississippi filed an Application for an Accounting Order seeking certification by the MPSC of Entergy Mississippi's estimated $36 million of storm restoration costs not included in the December 2005 filing. In March 2006, the Governor signed a law that established a mechanism by which the MPSC may authorize and certify an electric utility financing order and the state may issue general obligation bonds to pay the costs of repairing damage caused by Hurricane Katrina to the systems of investor-owned electric utilities.  Because of the passage of this law and the possibility of Entergy Mississippi obtaining CDBG funds for Hurricane Katrina stor m restoration costs, in March 2006, the MPSC issued an order approving a Joint Stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provided for the review of Entergy Mississippi's total storm restoration costs in the Application for an Accounting Order proceeding.  The Stipulation stated that the procedural schedule of the December 2005 Notice of Intent filing should be suspended until the MPSC issues a final order in the Application for an Accounting Order proceeding. 

In June 2006, the MPSC issued an order certifying Entergy Mississippi's Hurricane Katrina restoration costs incurred through March 31, 2006 of $89 million, net of estimated insurance proceeds. Two days later Entergy Mississippi filed a request with the Mississippi Development Authority for $89 million of CDBG funding for reimbursement of its infrastructure restoration costs. Entergy Mississippi also filed a Petition for Financing Order with the MPSC for authorization of state general obligation bond financing of $169 million for Hurricane Katrina restoration costs and future storm costs. The $169 million amount includes Hurricane Katrina restoration costs plus $80 million to build Entergy Mississippi's storm damage reserve for the future. The amount financed through the bonds will be reduced dollar for dollar by any CDBG funds that Entergy Mississippi receives. Pursuant to the legislation, the MPSC must issue a financing order by the end of October 2006.

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See State and Local Rate Regulationbelow for a discussion of Entergy New Orleans' filings with the City Council directed at recovery of its storm costs.

Insurance Recovery

As discussed more fully in the Form 10-K, Entergy estimates that its net insurance recoveries for the losses caused by Hurricanes Katrina and Rita will be approximately $382 million. Entergy has received $15 million thus far on its insurance claims, as it continues working towards insurance payment of its covered losses.

Entergy New Orleans Bankruptcy

See the Form 10-K for a discussion of the Entergy New Orleans bankruptcy proceeding. Following is an update to the discussion in the Form 10-K. In April 2006, the bankruptcy judge extended the exclusivity period for filing a plan of reorganization by Entergy New Orleans to August 21, 2006.Entergy New Orleans has filed another motion to extend the exclusivity period for filing its plan of reorganization, requesting that the deadline be extended an additional 120 days until December 19, 2006. The court entered an order extending the August 21, 2006 date for Entergy New Orleans' exclusive right to file a plan of reorganization until the court can hear and rule on Entergy New Orleans' motion to extend, which was set for hearing on September 18, 2006. In order to file a plan of reorganization no later than December 2006, Entergy New Orleans believes that it needs resolution of its June 2006 formula rate plan and storm rider filings and commitme nt on timing and amount of CDBG funds. If the motion to extend is granted, Entergy New Orleans will have the exclusive right to file its plan of reorganization until December 19, 2006, and will have until February 15, 2007 to obtain acceptances of its plan by each class of impaired creditors.

In addition, the bankruptcy judge had set a date of April 19, 2006 by which creditors with prepetition claims against Entergy New Orleans must, with certain exceptions, file their proofs of claim in the bankruptcy case. Approximately 500 claims have been filed thus far in Entergy New Orleans' bankruptcy proceeding. Entergy New Orleans is currently analyzing the accuracy and validity of the claims filed, and has begun seeking withdrawal or modification of claims or objecting to claims with which it disagrees.

Since the filing of the bankruptcy proceedings, Entergy New Orleans has not been able to declare and pay dividends on its 4.75% preferred stock for three quarters. As discussed further in the Form 10-K, if dividends with respect to the 4.75% preferred stock are not paid for four quarters, the holders of these shares would have the right to elect a majority of the Entergy New Orleans board of directors.  Entergy New Orleans filed a motion in the bankruptcy court seeking authority to recommence paying dividends to the holders of the 4.75% preferred shares. After a hearing on the motion on May 3, 2006, the court granted Entergy New Orleans the authority to pay dividends to the holders of the 4.75% preferred shares, beginning with the dividend due on July 1, 2006, and thereafter, unless objections are filed by creditors forty-five days in advance of a dividend payment date. If any objections are filed, the matter would be heard by the bankruptcy court. En tergy New Orleans declared and paid the dividend due on July 1, 2006, and intends to declare and pay the dividends on the 4.75% preferred shares each quarter pending resolution of its plan of reorganization.

Municipalization is one potential outcome of Entergy New Orleans' recovery effort. In June 2006 Louisiana passed a law that establishes a governance structure for a public power authority, if municipalization of Entergy New Orleans' utility business is pursued.

As discussed in the Form 10-K, as a result of the Entergy New Orleans bankruptcy proceeding, Entergy deconsolidated Entergy New Orleans for financial reporting purposes retroactive to January 1, 2005. Because Entergy owns all of the common stock of Entergy New Orleans, this change will not affect the amount of net income Entergy records resulting from Entergy New Orleans' operations for any current or prior period, but will result in Entergy New Orleans' net income or loss being presented as "Equity in earnings of unconsolidated equity affiliates" rather than its results being included in each individual income statement line item, as is the case for periods prior to 2005.

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Results of Operations

Entergy's consolidated earnings applicableSecond Quarter 2006 Compared to common stockSecond Quarter 2005

Following are income statement variances for Utility, Non-Utility Nuclear, Parent & Other business segments, and Entergy comparing the second quarter and six months ended June 30, 2005 and 2004 were as follows:

Entergy's income before taxes is discussed below according2006 to the operating segments listed above. See Note 8second quarter 2005 showing how much the line item increased or (decreased) in comparison to the consolidated financial statements herein for more information concerning Entergy's operating segments and their financial results in 2005 and 2004.prior period:

Refer to "ENTERGY CORPORATION AND SUBSIDIARIES -SELECTED OPERATING RESULTS" for further information with respect to Utility operating statistics.

U.S. UTILITY

The increase in earnings for the U.S. Utility for the second quarter 2005 compared to the second quarter 2004 from $195.0 million to $211.7 million was primarily due to higher net revenue partially offset by higher other operation and maintenance expenses and lower other income.Net Revenue

The decrease in earnings for the U.S. Utility for the six months ended June 30, 2005 compared to the six months ended June 30, 2004 from $310.6 million to $302.2 million was primarily due to higher other operation and maintenance expenses and higher depreciation and amortization expenses, partially offset by higher net revenue and lower interest expenses.

Net Revenue

Second Quarter 2005 Compared to Second Quarter 2004

Net revenue, which is Entergy's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue, which is Entergy's measure of gross margin, comparing the second quarter of 20052006 to the second quarter of 2004.2005.

The price applied to unbilled sales variance resulted from an increaseis due to the exclusion in 2006 of the fuel cost component included in the calculation of the price applied to unbilled sales. The increase inEffective January 1, 2006, the fuel cost component is attributable to an increaseno longer included in the price of natural gas, the nuclear refueling outageunbilled revenue calculation at Waterford 3,Entergy Louisiana and the nuclear maintenance outagesLouisiana jurisdiction at River Bend.Entergy Gulf States, which is in accordance with regulatory treatment. Entergy expects that the effect of this factor will be less for its annual results for 2006. See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS -Critical Accounting Estimates" in the Form 10-K and Note 1 to the consolidated financial statements in the Form 10-K for further discussion of the accounting for unbilled revenues.herein.

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The volume/weather variance isresulted primarily duefrom more favorable weather in the second quarter of 2006 compared to the second quarter of 2005 in addition to an increase in electricityweather-adjusted usage. Billed usage totaling 161increased a total of 801 GWh in the residential and commercial sectors.  Industrial sales volume declinedsectors and decreased 87 GWh in the industrial sector. The increase was partially offset by decreased usage during the unbilled period.

The base revenues variance resulted primarily from increases at Entergy Gulf States in the Louisiana jurisdiction effective October 2005 for the 2004 formula rate plan filing and the annual revenue requirement related to the purchase of power from the Perryville generating station, and increases at Entergy Gulf States in the Texas jurisdiction related to an incremental purchased capacity recovery rider that began in December 2005 and a transition to competition rider that began in March 2006. The Attala cost deferral variance resulted from deferred under-recovered Attala power plant costs at Entergy Mississippi that will be recovered through the power management rider. The net income effect of the Attala cost deferral is partially offset by Attala costs in other operation and maintenance expenses, depreciation expense, and taxes other than income taxes.

The fuel recovery variance resulted primarily from the under-recovery in 2005 of fuel costs from retail customers in addition to increased fuel cost recovery in 2006 as a result of special rate contracts.

Non-Utility Nuclear

Net revenue increased for Non-Utility Nuclear primarily due to the losshigher pricing in its contracts to cogeneration, which had been expected, of one large customer.

Gross operating revenues and fuel and purchased power expenses

Gross operating revenues increased from $2.0 billion for the second quarter 2004 to $2.2 billion for the second quarter 2005. The increase includes an increase in fuel cost recovery revenues of $81.7 million resulting primarily from increases in the market prices of natural gas and purchasedsell power. As such, this revenue increase is offset by increased fuel and purchased power expenses. The increases in the price applied to unbilled sales and volume/weather variances, discussed above, also contributedAlso contributing to the increase in gross operating revenues.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

Net revenue, which is Entergy's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the changewas increased generation in net revenue comparing the six months ended June 30, 2005 to the six months ended June 30, 2004.

The price applied to unbilled sales variance resulted from an increase in the fuel cost component included in the price applied to unbilled sales. The increase in the fuel cost component is attributable to an increase in the price of natural gas, the nuclear refueling outage at Waterford 3, and the nuclear maintenance outages at River Bend. See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS -Critical Accounting Estimates" in the Form 10-K and Note 1 to the consolidated financial statements in the Form 10-K for further discussion of the accounting for unbilled revenues.

The deferred fuel cost revisions variance is due toa revised estimate of fuel costs filed for recovery at Entergy Arkansas in the March 2004 energy cost recovery rider, which reduced net revenue in the first quarter of 2004 by $11.5 million. The remainder of the variance is2006 due to a power uprate completed since the 2004 energy cost recovery true-up, made in the firstsecond quarter of 2005, which increased net revenue by $4.0 million.

The rate refund provisions variance is due primarily to accruals recorded in 2004 for potential rate action at Entergy New Orleans and Entergy Gulf States. Included in the current period variance are provisions recorded at Entergy Louisiana in 2005 as a result of LPSC-approved settlements in March 2005 and May 2005. The settlements are discussed in Note 2 to the consolidated financial statements.

The volume/weather variance resulted from decreased usage by residential customers and a decrease in usage during the unbilled sales period. Industrial sales volume was relatively unchanged as the loss to cogeneration, which had been expected, of one large customer waspartially offset by an increasethe effect of refueling outages on available generation output. The total number of refueling days was essentially the same in usage by other customers, primarily in the chemical industry.  See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS -Critical Accounting Estimates" in the Form 10-K and Note 1 to the consolidated financial statements in the Form 10-K for further discussion of the accounting for unbilled revenues.

Gross operating revenues and fuel and purchased power expenses

Gross operating revenues increased from $3.8 billion for the six months ended June 30, 2004 to $4.0 billion for the six months ended June 30, 2005. The increase includes an increase in fuel cost recovery revenues of $151 million resulting primarily from increases in the market prices of natural gas and purchased power. As such, this revenue increase is offset by increased fuel and purchased power expenses. The increase in the price applied to unbilled sales, discussed above, also contributed to the increase in gross operating revenues.

Other Income Statement Variances

Second Quarter 2005 Compared to Second Quarter 2004

Other operation and maintenance expenses increased from $391.7 million for the second quarter 2004of 2006 compared to $432.6 million for the second quarter 2005 primarily due to:

• an increase of $17.9 million2005. However, the outage in payroll and benefits costs;
• an increase of $9.1 million in nuclear expenses for contract and material costs associated with maintenance outages and timing of payroll related expenses; and
• an increase of $5.1 million in estimated loss provisions recorded for the bankruptcy of CashPoint, which managed a network of payment agents for the domestic utility companies.

Other income decreased from $30.5 million for the second quarter 2004 to $20.1 million forof 2006 was at a larger unit, Indian Point 2, while most of the outage days in the second quarter of 2005 primarily due to:

• were at a decrease of $10.1 million at Entergy Gulf States due to a reduction in 2004 in the loss provision for an environmental clean-up site; and
• a decrease of $7.1 million at Entergy Louisiana due to the write-off in June 2005 of a portion of the customer care system investment and the related allowance for equity funds used during construction pursuant to an LPSC-approved settlement.

The decrease was partially offset by an increase of $6.2 million in interest and dividend income primarily due to higher interest on temporary cash investments.

Interest on long-term debt decreased from $97.6 million for the second quarter 2004 to $91.2 million for the second quarter 2005 primarily due to the net retirement of $319 million of long-term debt at the domestic utility companies in 2004. Refer to Note 5 to the consolidated financial statements in the Form 10-K and Note 4 to the consolidated financial statements herein for details of long-term debt.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

Other operation and maintenance expenses increased from $723 million for the six months ended June 30, 2004 to $798 million for the six months ended June 30, 2005 primarily due to:

• an increase of $33.3 million in payroll and benefits costs;
• an increase of $13.2 million in nuclear expenses for contract and material costs associated with maintenance outages and timing of payroll related expenses;
• an increase of $8.1 million in fossil expenses as a result of additional planned off-peak fossil generation maintenance outages; and
• an increase of $5.1 million in estimated loss provisions recorded for the bankruptcy of CashPoint, which managed a network of payment agents for the domestic utility companies.

Depreciation and amortization expenses increased from $385.6 million forthe six months ended June 30,2004 to $398.4 million for the six months ended June 30, 2005 due primarily to an increase in plant in service.

Other income, which was $45.4 million for the six months ended June 30, 2005 and $45.5 million for the six months ended June 30, 2004, includes the following:

• a decrease of $10.1 million at Entergy Gulf States due to a reduction in 2004 in the loss provision for an environmental clean-up site;
• a decrease of $7.1 million at Entergy Louisiana due to the write-off in June 2005 of a portion of the customer care system investment and the related allowance for equity funds used during construction pursuant to an LPSC-approved settlement;
• an increase of $10.6 million in interest and dividend income primarily due to higher interest on temporary cash investments; and
• an increase of $9.8 million in the allowance for equity funds used during construction as a result of higher construction expenditures.

Interest on long-term debt decreased from $199.3 million for the six months ended June 30, 2004 to $184.2 million for the six months ended June 30, 2005 primarily due to the net retirement of $319 million of long-term debt at the domestic utility companies in 2004. Refer to Note 5 to the consolidated financial statements in the Form 10-K and Note 4 to the consolidated financial statements herein for details of long-term debt.

NON-UTILITY NUCLEAR

smaller unit, Pilgrim. Following are key performance measures for Non-Utility Nuclear for the second quarterquarters of 2006 and six months ended June 30, 2005 and 2004:

Second Quarter 2005 Compared to Second Quarter 20042005:

The decrease

Parent & Other

Net revenue increased for Parent & Other primarily due to the $14.1 million gain ($8.6 million net-of-tax) realized on the sale of the non-nuclear wholesale asset business' remaining interest in earningsa power development project.

Other Operation and Maintenance Expenses

Other operation and maintenance expenses increased for Non-Utility Nuclear from $63.0$145 million for the second quarter of 2005 to $58.3$155 million wasfor the second quarter of 2006 primarily due to higher operation and maintenance expenses resulting primarily from increased benefits costs and the effects of lower generation associated with planned and unplanned refueling and maintenance outages. Partially offsetting the decrease was an increase in revenues due to higher contract pricing.outage expenses.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004Interest Charges

The increase in earningsInterest charges increased for Non-Utility Nuclear from $131.8 million to $136.2 million wasthe Utility and Parent & Other primarily due to miscellaneous income of $15.8 million net-of-tax resulting from a reduction inadditional borrowing to fund the decommissioning liability for a plant, as discussed in Note 1 to the consolidated financial statements. Also contributing to the increase in earnings was higher contract pricing. The increase in earnings was partially offset by the effects of lower generationsignificant storm restoration costs associated with plannedHurricanes Katrina and unplanned refueling and maintenance outages and higher operation and maintenance expenses resulting primarily from increased benefits costs.Rita.

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Discontinued Operations

PARENT COMPANY & OTHER BUSINESS SEGMENTS

Second Quarter 2005 Compared to Second Quarter 2004

The increase in earnings for Parent Company & Other Business SegmentsIncome from $7.2 million to $16.2 million wasdiscontinued operations increased primarily due to $14.4the $17.1 million of tax benefits in 2005 from the American Jobs Creation Act of 2004 and an increase of $5.5 million from the non-nuclear wholesale assets business primarily due to lower operation and maintenance expenses and proceeds fromgain (net-of-tax) on the sale of SO₂ allowances. The increase was partially offset by a decrease of $13.9 million due to the absence of earnings from Entergy's investment in Entergy-Koch becauseretail electric portion of the sale of Entergy-Koch's energy trading and pipeline businessesCompetitive Retail Services business operating in the fourth quarterERCOT region of 2004, as discussed in the Form 10-K.Texas.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

The decrease in earnings for Parent Company & Other Business Segments from $29.9 million to $19.7 million was primarily due to a decrease of $30.1 million due to the absence of earnings from Entergy's investment in Entergy-Koch due to the sale of Entergy-Koch's energy trading and pipeline businesses in the fourth quarter of 2004, as discussed in the Form 10-K. Also contributing to the decrease in earnings was the favorable settlement of a tax issue, which increased earnings by $11 million in the first quarter of 2004. The decrease was partially offset by $14.4 million of tax benefits in 2005 from the American Job Creations Act of 2004 and an increase of $14.1 million from the non-nuclear wholesale assets business primarily due to lower operation and maintenance expenses and proceeds from the sale of SO₂ allowances.

Income Taxes

The effective income tax rates for the second quarters of 2006 and 2005 were 31.0% and 2004 were 34.8% and 38.0%, respectively. The effective income tax rates for the six months ended June 30, 2005 and 2004 were 34.8% and 36.0%33.9%, respectively. The difference in the effective income tax rate for the second quarter of 2006 versus the federal statutory rate of 35.0% is primarily due to the recognition of an income tax benefit related to ANO 1 steam generator removal cost and the six months ended June 30,favorable resolution of a tax audit issue, partially offset by state income taxes. The difference in the effective income tax rate for the second quarter of 2005 versus the federal statutory rate of 35.0% is primarily due to tax benefits from the American Jobs Creation Act of 2004 and investment tax credit amortization, partially offset by state income taxes and regulatory plantbook and tax differences on utility plant items.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Following are income statement variances for Utility, Non-Utility Nuclear, Parent & Other business segments, and Entergy comparing the six months ended June 30, 2006 to the six months ended June 30, 2005 showing how much the line item increased or (decreased) in comparison to the prior period:

Refer to "ENTERGY CORPORATION AND SUBSIDIARIES -SELECTED OPERATING RESULTS" for further information with respect to Utility operating statistics.

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Net Revenue

Utility

Following is an analysis of the change in net revenue, which is Entergy's measure of gross margin, comparing the six months ended June 30, 2006 to the six months ended June 30, 2005.

The base revenues variance resulted primarily from increases at Entergy Gulf States in the Louisiana jurisdiction effective October 2005 for the 2004 formula rate plan filing and the annual revenue requirement related to the purchase of power from the Perryville generating station, and increases at Entergy Gulf States in the Texas jurisdiction related to an incremental purchased capacity recovery rider that began in December 2005 and a transition to competition rider that began in March 2006. The Attala cost deferral variance resulted from deferred under-recovered Attala power plant costs at Entergy Mississippi that will be recovered through the power management rider. The net income effect of the Attala cost deferral is partially offset by Attala costs in other operation and maintenance expenses, depreciation expense, and taxes other than income taxes.

The fuel recovery variance resulted primarily from adjustments of fuel clause recoveries in Entergy Gulf States' Louisiana jurisdiction, the under-recovery in 2005 of fuel costs from retail customers, and increased recovery in 2006 of fuel costs as a result of special rate contracts. The increase was partially offset by the Entergy Arkansas energy cost recovery true-up made in the first quarter of 2005.

The volume/weather variance resulted primarily from increased usage, including the effect of weather on billed sales, compared to the same period in 2006. Billed usage increased a total of 657 GWh in the residential and commercial sectors and decreased 486 GWh in the industrial sector. The increase was partially offset by decreased usage during the unbilled period.

The transmission revenue variance is primarily due to new transmission customers in 2006. Also contributing to the increase was an increase in rates effective June 2006.

The storm cost recovery variance is due to the return earned on the interim recovery of storm-related costs at Entergy Louisiana and the Louisiana jurisdiction of Entergy Gulf States as allowed by the LPSC effective March 2006.

The price applied to unbilled sales variance is due to the exclusion in 2006 of the fuel cost component in the calculation of the price applied to unbilled sales. Effective January 1, 2006, the fuel cost component is no longer included in the unbilled revenue calculation at Entergy Louisiana and the Louisiana jurisdiction at Entergy Gulf States, which is in accordance with regulatory treatment. Entergy expects that the effect of this factor will be less for its annual results for 2006. See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS -Critical Accounting Estimates" herein.

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Non-Utility Nuclear

Net revenue increased for Non-Utility Nuclear primarily due to higher pricing in its contracts to sell power. Also contributing to the increase in revenues was increased generation in 2006 due to power uprates at certain plants completed in 2005 and 2006 and fewer refueling outages in 2006. Following are key performance measures for Non-Utility Nuclear for the six months ended June 30, 2006 and 2005:

Parent & Other

Net revenue increased for Parent & Other primarily due to the $14.1 million gain ($8.6 million net-of-tax) realized on the sale of the non-nuclear wholesale asset business' remaining interest in a power development project.

Other Operation and Maintenance Expenses

Other operation and maintenance expenses increased for the Utility from $750 million in 2005 to $761 million in 2006 primarily due to the following:

• an increase of $11 million related to storm reserves. This increase does not include costs associated with Hurricanes Katrina and Rita;
• an increase of $9 million in customer service support costs, including an increase in customer write-offs; and
• an increase of $8 million in nuclear costs as a result of higher payroll costs and a non-refueling plant outage at Entergy Gulf States in February 2006.

The increase was partially offset by a decrease of $10 million in benefits and payroll costs and a decrease of $10 million in distribution costs, including lower planned spending for vegetation maintenance.

Other operation and maintenance expenses increased for Non-Utility Nuclear from $288 million in 2005 to $306 million in 2006 primarily due to higher refueling outage expenses.

Other Income

Other income increased for the Utility from $59 million in 2005 to $79 million in 2006 primarily due to an increase in interest income recorded on the deferred fuel costs balance. Other income decreased for Non-Utility Nuclear from $48 million in 2005 to $33 million in 2006 primarily due to miscellaneous income of $26 million in 2005 resulting from a reduction in the decommissioning liability for a plant in conjunction with a new decommissioning cost study. The decrease for Non-Utility Nuclear was partially offset by an increase of $5 million in interest income. The decrease in other income for Parent & Other was primarily due to a decrease in interest income and the proceeds in 2005 from the sale of SO₂ allowances.

Interest Charges

Interest charges increased for the Utility and Parent & Other primarily due to additional borrowing to fund the significant storm restoration costs associated with Hurricanes Katrina and Rita.

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Discontinued Operations

Income from discontinued operations increased primarily due to the $17.1 million gain (net-of-tax) on the sale of the retail electric portion of the Competitive Retail Services business operating in the ERCOT region of Texas.

Income Taxes

The effective income tax rates for the six months ended June 30, 2006 and 2005 were 33.5% and 33.9%, respectively. The difference in the effective income tax rate for the six months ended June 30, 2006 versus the federal statutory rate of 35.0% is primarily due to the recognition of an income tax benefit related to ANO 1 steam generator removal cost and the favorable resolution of a tax audit issue, partially offset by state income taxes. The difference in the effective income tax rate for the six months ended June 30, 2005 versus the federal statutory rate of 35.0% is primarily due to tax benefits from the American Jobs Creation Act of 2004, investment tax credit amortization, and a downward revision in the estimate of federal income tax expense related to tax depreciation. The difference in the effective income tax rate for the second quarter and the six months ended June 30, 2004 versus the federal statutory rate of 35.0% is primarily due toThese factors were partially offset by state income taxes and regulatory plantbook and tax differences on utility plant items, partially offset by the favorable settlement of a tax audit issue and investment tax credit amortization.items.

Liquidity and Capital Resources

See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS -Liquidity and Capital Resources" in the Form 10-K for a discussion of Entergy's capital structure, capital expenditure plans and other uses of capital, and sources of capital. Following are updates to that discussion.

TheDebtor-in-Possession Credit Facility

See the Form 10-K reportedfor a discussion of the Entergy New Orleans debtor-in-possession (DIP) credit facility between Entergy New Orleans as borrower and Entergy Corporation as lender. Following is an update to that discussion.

As discussed in the Form 10-K, the bankruptcy court issued its order in December 2005 giving final approval for the $200 million DIP credit facility, and the indenture trustee for Entergy expected to contribute $185.9 million in 2005 toNew Orleans' first mortgage bonds appealed the order. On March 29, 2006 the bankruptcy court approved a settlement among Entergy New Orleans, Entergy Corporation, and the indenture trustee, and the indenture trustee dismissed its pension plans. Entergy has elected to make additional contributions, and now expects to contribute $253.3 million to its pension plans in 2005. Entergy contributed $117.7 million to its pension plans during the six months endedappeal. As of June 30, 2005.2006, Entergy New Orleans had approximately $40 million of outstanding borrowings under the DIP credit facility.

As discussed in the Form 10-K, borrowings under the DIP credit facility are due in full, and the agreement will terminate, at the earliest of several times or events, including August 23, 2006. Entergy and Entergy New Orleans have agreed to an amendment to the DIP credit agreement that extends the August 23, 2006 maturity date to August 23, 2007, and this amendment is subject to bankruptcy court approval. Entergy New Orleans has filed a motion with the bankruptcy court to authorize Entergy New Orleans to enter into the amendment, which is set for hearing August 16, 2006.

Capital Structure

Entergy's capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital percentage as of June 30, 2005 is primarily the result of increased debt outstanding due to additional borrowings on Entergy Corporation's revolving credit facility along with a decrease in shareholders' equity, primarily due to repurchases of common stock, both of which are discussed below.

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Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable, capital lease obligations, preferred stock with sinking fund, and long-term debt, including the currently maturing portion. Capital consists of debt, common shareholders' equity, and preferred stock without sinking fund. Net capital consists of capital less cash and cash equivalents. Entergy uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy's financial condition.

In May 2005,As discussed in the Form 10-K, Entergy Corporation terminated itshas in place two separate revolving credit facilities, a $500 million five-year credit facility and a $965 million three-year credit facility. At that time Entergy Corporation entered into a $2 billion,The five-year credit facility which expires in May 2010. As of June 30, 2005, $635 million2010 and the three-year facility expires in borrowings were outstanding on this facility.December 2008. Entergy also has the ability tocan issue letters of credit against the total borrowing capacity of both credit facilities. Following is a summary of the credit facility,borrowings outstanding and letters of credit totaling $83.5 million had been issued against this facility at June 30, 2005. The total unused capacity for this facilityavailable under these facilities as of June 30, 2005 was approximately $1.3 billion. The commitment fee for this facility is currently 0.13% per annum of the unused amount. Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior debt ratings of the domestic utility companies.2006:

Entergy Arkansas, Entergy Louisiana,Gulf States, and Entergy Mississippi and Entergy New Orleans each have 364-day credit facilities available as of June 30, 2006 as follows:

See Note 4 to the consolidated financial statements for additional discussion of Entergy's short-term credit facilities.

Capital Expenditure Plans and Other Uses of Capital

See the table in the Form 10-K under "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS -Liquidity and Capital Resources - Capital Expenditure Plans and Other Uses of Capital," which sets forth the amounts of Entergy's planned construction and other capital investments by operating segment for 20052006 through 2007.2008. Following is an update to that discussion:

In March 2005, Entergy Mississippi signedJuly 2006, Entergy's Non-Utility Nuclear business reached an agreement to purchase Consumers Energy Company's 798 MW Palisades nuclear energy plant located near South Haven, Michigan for $88 million$380 million. Entergy's Non-Utility Nuclear business will acquire the Attala power plant, a 480 MW natural gas-fired, combined-cycle generating facility owned by Central Mississippi Generating Company (CMGC).nuclear fuel, and other assets. In the near-term, Entergy Mississippi plansintends to invest approximately $20 million in facility upgrades atfinance the Attala plant plus $3 million in other costs, bringing the total capital costacquisition through borrowings from Entergy Corporation's revolving credit facilities. As part of the project to approximately $111 million. The Attala plant will be 100 percent owned by Entergy Mississippi, and the acquisition is expected to close in late 2005 or early 2006. The purchase, of the plant is contingent upon obtaining necessary approvals from various federal agencies, state permitting agencies, and the MPSC, including MPSC approval of investment cost recovery. In May and June 2005, Entergy Mississippi made filings at the MPSC to commence proceedings for MPSC approval both of the acquisition and of the investment cost recovery for the plant. Entergy Mississippi and CMGC had pre viouslyEntergy's Non-Utility Nuclear business also executed a 15-year purchased power agreement in July 2004with Consumers Energy for 100 percent100% of the plant's output, and this agreementoutput. Entergy's Non-Utility Nuclear business will expire upon the closeassume responsibility for eventual decommissioning of the acquisition orplant. Consumers Energy will retain $200 million of the current $566 million Palisades decommissioning trust fund balance, and Entergy may return an additional approximately $100 million of the trust fund to Consumers Energy depending upon a pending tax ruling. Also as pa rt of the transaction, Consumers Energy will pay Entergy's Non-Utility Nuclear business $30 million to accept responsibility for spent fuel at the

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decommissioned Big Rock nuclear plant, which is located near Charlevoix, Michigan. Management expects to close the transaction in March 2008, whichever occurs earlier. The planned constructionthe first quarter 2007, pending the approvals of the NRC, the FERC, the Michigan Public Service Commission, and other capital investments table in the Form 10-K includes the estimated cost of the Attala acquisition as a 2006 capital commitment.regulatory agencies.

Cash Flow Activity

As shown in Entergy's Statements of Cash Flows, cash flows for the six months ended June 30, 20052006 and 20042005 were as follows:

Operating Activities

Entergy's cash flow provided by operating activities decreasedincreased by $162$707 million for the six months ended June 30, 20052006 compared to the six months ended June 30, 20042005 primarily due a decrease atto the U.S. Utility. The U.S. following activity:

• Utility provided $535$1,088 million in cash from operating activities in 20052006 compared to providing $669$539 million in 2004. The decrease resulted2005 primarily fromdue to the receipt of an increaseincome tax refund (discussed below), increased collection of $80 milliondeferred fuel costs, and the effect in pension plan contributions, the2005 of a $90 million refund paid to customers in the Louisiana, jurisdiction made as a result of the global settlement, an increase of $72 million in income tax payments, and changes in the timing of fuel cost recovery compared to the prior period. These increased uses of cash were partially offset by various items, including the timing of receivable collections and vendor payments compared to the prior period. The storm restoration spending.
• Non-Utility Nuclear segment also contributed to the decrease. The Non-Utility Nuclear segment provided $235$473 million in cash from operating activities i n 2005in 2006 compared to providing $265$235 million in 2004. This decrease was caused2005 primarily by nuclear refueling outage costs, as this business had one more refueling outagedue to an increase of $130 million in income tax refunds received and an increase in net revenue.
• Parent & Other used $81 million in cash from operating activities in 2006 compared to using $1 million in 2005 primarily due to an increase in cash used of $72 million in the first halfnon-nuclear wholesale assets business primarily due to an increase in taxes paid and interest payments.

Entergy Corporation received a $344 million income tax refund (including $71 million attributable to Entergy New Orleans) as a result of net operating loss carryback provisions contained in the Gulf Opportunity Zone Act of 2005, thanas discussed in the first halfForm 10-K. In accordance with Entergy's intercompany tax allocation agreement, $273 million of 2004.the refund was distributed to the Utility (including Entergy New Orleans) in April 2006, with the remainder distributed primarily to Non-Utility Nuclear.

Investing Activities

InvestingNet cash used in investing activities used $698increased by $380 million of cash for the six months ended June 30, 20052006 compared to using $484 million of cash for the six months ended June 30, 20042005 primarily due to the following activity:

• Construction expenditures were $44$326 million higher in 20052006 than in 2004. The increase is in the U.S. Utility segment, and is2005, primarily due to increases at Entergy Louisiana resulting from an increase in spending on transmission and nuclear projects and an increase of $19.8$261 million in capacity costs that have been deferred and are expected to be recovered over a period greater than twelve months.
• The non-nuclear wholesale assetsthe Utility business received $22 million in 2004 from the salebecause of the Crete power plant.storm restoration expenditures.

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• Entergy LouisianaMississippi purchased the Perryville480 MW Attala power plant in June 2005January 2006 for $162.5$88 million. See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS -Liquidity and Capital Resources" in the Form 10-K for a discussion of this acquisition. In April 2005, the LPSC approved the acquisition and the long-term cost-of-service purchased power agreement under which Entergy Gulf States will purchase 75 percent of the plant's output.

The non-nuclear wholesale assets business received a return of invested capital of $34 million in 2005 from the Top Deer wind power joint venture after Top Deer obtained debt financing.

• Entergy's net investment in other temporary investments decreasedincreased by $188 million during the six months ended June 30, 2005. Entergy had no activity in other temporary investments during the six months ended June 30, 2006.
• Entergy Louisiana purchased the 718 MW Perryville power plant in June 2005 for $162 million.
• The proceeds from the sale of the retail electric portion of the Competitive Retail Services business operating in the ERCOT region of Texas and decreasedthe sale of the non-nuclear wholesale asset business' remaining interest in a power development project.

Financing Activities

Net cash used in financing activities increased by $208$175 million for the six months ended June 30, 2006 compared to the six months ended June 30, 2005. Following is a description of the significant financing activity occurring during the first six months of 2006 and 2005:

• Entergy Louisiana Holdings, Inc. redeemed all $100.5 million of its outstanding preferred stock in June 2006.
• Entergy Corporation increased the net borrowings on its credit facilities by $20 million during the six months ended June 30, 2004. See Note 9 to the consolidated financial statements for additional discussion regarding these investments.
• The U.S. Utility used $64 million in 2005 and $31 million in 2004 for other regulatory investments as a result of fuel cost under-recovery. See Note 1 to the consolidated financial statements in the Form 10-K for discussion of the accounting treatment of these fuel cost under-recoveries.

Financing Activities

Financing activities used $74 million of cash for the six months ended June 30, 20052006 compared to using $392 million of cash for the six months ended June 30, 2004 primarily due to the following activity:

• Net issuances of long-term debt by the U.S. Utility segment provided $108$585 million during the six months ended June 30, 2005 compared to retirements of long-term debt net of issuances using $253 million during the six months ended June 30, 2004.2005. See Note 4 to the consolidated financial statements for a description of the details of long-term debt activity in 2005.Entergy Corporation credit facilities.
• Entergy Corporation repurchased $640 million of its common stock during the six months ended June 30, 2005 compared to $271 million during the six months ended June 30, 2004. SeePart II, Item 2 herein and in the First Quarter 2005 Form 10-Q for details regarding Entergy Corporation's common stock repurchases in 2005.
• Entergy Corporation increased the net borrowings on its credit facility by $585 million during the six months ended June 30, 2005 compared to $255 million during the six months ended June 30, 2004.

See Note 4 to the consolidated financial statements for a descriptionthe details of long-term debt activity in the Entergy Corporation credit facility.six months ended June 30, 2006.

Significant Factors and Known Trends

See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS -Significant Factors and Known Trends" in the Form 10-K for discussions of rate regulation, federal regulation, market and credit risks, utility restructuring, and nuclear matters. Following are updates to the information provided in the Form 10-K.

State and Local Rate Regulation

See the Form 10-K for the chart summarizing material rate proceedings. Following are updates to that chart. See alsoHurricanes Katrina and Ritaabove for updates regarding storm cost recovery proceedings.

Entergy Arkansas

In March 2006, Entergy Arkansas filed with the APSC its annual redetermination of the energy cost rate for application to the period April 2006 through March 2007. The filed energy cost rate of $0.02827 per kWh was proposed to replace the interim rate of $0.01900 per kWh that had been in place since October 2005. The interim energy cost rate is discussed in the Form 10-K, along with the investigation that the APSC commenced concerning Entergy Arkansas' interim energy cost rate. The increase in the energy cost rate is due to increases in the cost of purchased power primarily due to the natural gas cost increase and the effect that Hurricanes Katrina and Rita had on market conditions, increased demand for purchased power during the ANO 1 refueling and steam generator replacement outage in the fall of 2005, and coal plant generation curtailments during off-peak periods due to coal delivery problems.

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On March 31, 2006, the APSC suspended implementation of the $0.02827 per kWh energy cost rate, and ordered that the $0.01900 per kWh interim rate remain in effect pending the APSC proceedings on the energy cost recovery filings. The APSC also extended its investigation into Entergy Arkansas' interim energy cost rate to cover the costs included in Entergy Arkansas' March 2006 filing. The extended investigation does not identify new issues in addition to the four issues listed in the Form 10-K and covers the same time period. On April 7, 2006, the APSC issued a show cause order in the investigation proceeding that ordered Entergy Arkansas to file a cost of service study by June 8, 2006. The order also directed Entergy Arkansas to file testimony to support the cost of service study, to support the $0.02827 per kWh cost rate, and to address the general topic of elimination of the energy cost recovery rider.

Entergy Arkansas filed for rehearing of the APSC's orders, asking that the energy cost rate filed in March 2006 be implemented in May 2006 subject to refund, asserting that the APSC did not follow appropriate procedures in suspending the operation of the energy cost recovery rider, and asking the APSC to rescind its show cause order. On May 8, 2006 the APSC denied Entergy Arkansas' requests for rehearing. Entergy Arkansas appealed the APSC's decision, but later filed a motion to dismiss the appeal following the APSC's decision described below.

In June 2006, Entergy Arkansas once again filed a motion with the APSC seeking to implement the redetermined energy cost rate of $0.02827 per kWh. After a hearing the APSC approved Entergy Arkansas' request and the redetermined rate was implemented in July 2006, subject to refund pending the outcome of the APSC energy cost recovery investigation. Because of the delay in implementing the redetermined energy cost rate, Entergy Arkansas estimated in its motion that $46 million of energy costs would remain under-recovered at December 31, 2006.

A hearing in the APSC energy cost recovery investigation is scheduled for October 2006.

On June 7, 2006, Entergy Arkansas filed the cost of service study ordered by the APSC. On that date Entergy Arkansas also filed notice with the APSC that it intends to file for a change in base rates within 60 to 90 days of its notice. Entergy Arkansas expects to make that filing in August 2006.

See "System Agreement Litigation" herein for a discussion of Entergy's compliance filing in that proceeding. If the FERC approves the compliance tariff as filed, then payments under that tariff will be classified as energy costs, which would then be included in setting the retail energy cost rate as part of the normal working of the energy cost recovery rider.  As noted above the APSC has given notice that it is considering the prospective elimination of the energy cost recovery rider.  Therefore, Entergy Arkansas plans to propose an alternative to the energy cost recovery rider for recovery of the costs allocated to it as a result of the System Agreement litigation should the energy cost recovery rider be lawfully terminated by the APSC.  A separate exact recovery rider, similar to the energy cost recovery rider or a production cost allocation rider, would ensure that Entergy Arkansas' customers pay only the amount allocated by the FERC. 

In March 2006, the LPSC approved an uncontested stipulated settlement in Entergy Gulf States' formula rate plan filing for the 2004 test year. The settlement includes a settlement proposal to resolve various dockets covering a rangerevenue requirement increase of issues$36.8 million and calls for Entergy Gulf States and Entergy Louisiana.to apply a refund liability of $744 thousand to capacity deferrals. The settlement resulted in credits totaling $76 million for retail electricity customers in Entergy Gulf States' Louisiana service territory and credits totaling $14 million for retail electricity customers of Entergy Louisiana. The settlement dismissed Entergy Gulf States' fourth, fifth, sixth, seventh, and eighth annual earnings reviews, Entergy Gulf States' ninth post-merger earnings review and revenue requirement analysis, the continuation of a fuel review for Entergy Gulf States, dockets established to consider issues concerning power purchases for Entergy Gulf States and Entergy Louisiana for the summers of 2001, 2002, 2003, and 2004, all prudence issues associated with decisions made through May 2005 relatedrefund liability pertained to the nuclear plant uprates at issueperiods 2004-2005 as well as the interim period in these cases, and an LPSC docket concerning retail i ssues arising under the System Agreement. The settlement does not include the System Agreement case at FERC. In addition, Entergy Gulf States agreed not to seek recovery from customers of $2which a $37.8 million of excess refund amounts associated with the fourth through the eighth annual earnings reviews and Entergy Louisiana agreed to forgo recovery of $3.5 million of deferred 2003 capacity costs associated with certain power purchase agreements. The credits were issuedrevenue increase was in connection with April 2005 billings. Entergy Gulf States and Entergy Louisiana had reserved for the approximate refund amounts.

The settlement includes the establishment of a three-year formula rate plan for Entergy Gulf States that, among other provisions, establishes an ROE mid-point of 10.65% for the initial three-year term of the plan and permits Entergy Gulf States to recover incremental capacity costs outside of a traditional base rate proceeding. Under the formula rate plan, over- and under-earnings outside an allowed range of 9.9% to 11.4% will be allocated 60% to customers and 40% to Entergy Gulf States. In addition, there is the potential to extend the formula rate plan beyond the initial three-year effective period by mutual agreement of the LPSC and Entergy Gulf States. Under the settlement, there was no change to Entergy Gulf States' retail rates at that time.

In June 2005, the Alliance for Affordable Energy and an individual plaintiff filed an appeal in the 19^th Judicial District Court for the parish of East Baton Rouge, Louisiana. The plaintiffs allege that neither Entergy Gulf States nor the LPSC published notice that a formula rate plan was to be considered as part of the settlement and that the LPSC order should be set aside as null and void and without effect because the Louisiana Constitution requires that notice be published when a utility files a proposed rate schedule that would result in a change in rates. Management believes the plaintiffs' claim is without merit and expects to intervene in the proceeding to oppose the appeal.place.

In June 2005,May 2006, Entergy Gulf States made its formula rate plan filing with the LPSC for the 2005 test year ending December 31, 2004.year. The filing shows a net revenue deficiency of $2.58 million indicating that no refund liability exists.Entergy Gulf States' return on equity was within the allowed bandwidth. The filing also indicates that under the formula rate plan rider for approved capacity additions, a prospective$7.1 million rate increase of $23.8 million is required in order for Entergy Gulf States to earn the authorized ROE mid-pointrecover LPSC-approved incremental

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deferred and ongoing capacity requirements. The filing is subject to a period of 10.65%. Subject to the consideration of comments expected to be filed by the LPSC staffStaff review, and intervenors in the third quarter 2005, rate changes associated with the formula rate plan are scheduled to take effect with the first billing cycle in October 2005.  Any disputed issues will be subject to further investigation by the LPSC, with any resolution of such issues being made effective October 2005.

Regarding Entergy Louisiana's January 2004 rate filing, in March 2005, the LPSC staff and Entergy Louisiana filed a proposed settlement that includes an annual base rate increase of approximately $18.3 million that was implemented, subject to refund, effective with May 2005 billings. In May 2005, the LPSC approved a modified settlement which, among other things, reduces depreciation and decommissioning expense due to assuming a life extension of Waterford 3 and results in no change in rates. Subsequently, in June 2005, Entergy Louisiana made a revised compliance filing with the LPSC supporting a revised depreciation rate for Waterford 3, which reflects the removal of interim additions, and a rate increase from the purchase of the Perryville power plant, which results in a net $0.8 million annual rate reduction. Entergy Louisiana reduced rates effective with the first billing cycle in June 2005 and expects to refund excess revenue collected during May 2005, including interest, in the third quarter of 2005.September 2006.

The May 2005 rate settlement with the LPSC includes the adoption of a three-year formula rate plan for Entergy Louisiana, the terms of which include an ROE mid-point of 10.25% for the initial three-year term of the plan and permit Entergy Louisiana to recover incremental capacity costs outside of a traditional base rate proceeding. Under the formula rate plan, over- and under-earnings outside an allowed regulatory earnings range of 9.45% to 11.05% will be allocated 60% to customers and 40% to Entergy Louisiana. The initial formula rate plan filing will be in May 2006 based on a 2005 test year with rates effective September 2006. In addition, there is the potential to extend the formula rate plan beyond the initial three-year effective period by mutual agreement of the LPSC and Entergy Louisiana.

In July 2004, Entergy Gulf States filed with the LPSC an application for a change in its rates and charges seeking an increase of $9.1 million in gas base rates in order to allow Entergy Gulf States an opportunity to earn a fair and reasonable rate of return. In June 2005, the LPSC unanimously approved Entergy Gulf States' proposed settlement that includes a $5.8 million gas base rate increase effective the first billing cycle of July 2005 and a rate stabilization plan with an ROE mid-point of 10.5%.-Texas

As discussed in Note 2 to the consolidated financial statements in the Form 10-K, in August 2005, Entergy Gulf States filed with the PUCT in July 2005 a requestan application for implementationrecovery of an incremental purchased capacity recovery rider, consistent with the recently passed Texas legislation discussed below under "Utility Restructuring." The rider requests $23.1 million annually in incremental revenues on a Texas retail basis which represents the incremental purchased capacity costs, including Entergy Gulf States' obligationits transition to purchase power from Entergy Louisiana's recently acquired Perryville plant, over what is already in Entergy Gulf States' base rates.competition costs. Entergy Gulf States has reached an agreement with parties with respectrequested recovery of $189 million in transition to the date upon which cost recovery and cost reconciliation would begin.competition costs through implementation of a 15-year rider to be effective no later than March 1, 2006. The parties have agreed that$189 million represents transition to competition costs Entergy Gulf States will implementincurred from June 1, 1999 through June 17, 2005 in preparing for competition in its service area, including attendant AFUDC, and all carrying costs projected to be incurred on the rider after approval by the PUCT which could be up to 185 days from the date of filing but will reconcile and recover incremental purchased capacity costs incurred beginn ing September 1, 2005. The September 1, 2005 agreed upon date for the beginning of the cost recovery and cost reconciliation as well as the requested amount and the processes for implementing the rider are subject to PUCT action and approval. If approved by the PUCT, the rider would be subject to semi-annual modifications and reconciliation in conjunction with Entergy Gulf States' fuel reconciliation proceedings. Also see "Utility Restructuring" below for discussion of the provisions in the Texas legislation regarding Entergy Gulf States' ability to file a general rate case and for recovery of transition to competition costs.costs through February 28, 2006. The $189 million is before any gross-up for taxes or carrying costs over the 15-year recovery period. Entergy Gulf States reached a unanimous settlement agreement on all issues with the active parties in the transition to competition cost recovery case. The agreement allows Entergy Gulf States to recover $14.5 million per year in transition to competition costs over a 15-year period. Entergy Gulf States implemented interim rates based on this revenue level on March 1, 2006. The PUCT approved the settlement agreement in June 2006.

Entergy Louisiana

In May 2005, the MPSC approved a joint stipulation entered into between the Mississippi Public Utilities Staff and2006, Entergy Mississippi regarding Entergy Mississippi's annualLouisiana made its formula rate plan filing with the LPSC for the 2005 test year. The filing shows that providesEntergy Louisiana's return on equity was within the allowed bandwidth. The filing also indicates that under the formula rate plan rider for no change in rates based onapproved capacity additions, a performance adjusted ROE mid-point$121 million rate increase is required to recover LPSC-approved incremental deferred and ongoing capacity requirements. Entergy Louisiana requested recovery of 10.50%, establishing an allowed regulatory earnings rangethe capacity deferrals over a three-year period, including carrying charges. $51 million of 9.1%the rate increase is associated with these deferrals. The remaining $70 million of the rate increase is associated with ongoing capacity costs. The filing is subject to 11.9%.a period of LPSC Staff review, and rate changes associated with the formula rate plan are scheduled to take effect with the first billing cycle of September 2006.

Entergy Mississippi

In March 2006, Entergy Mississippi made its annual scheduled formula rate plan filing with the MPSC.  The filing was amended by an April 2005,2006 filing.  The amended filing showed that an increase of $3.1 million in electric revenues is warranted.  The MPSC has approved a settlement providing for a $1.8 million rate increase, which will be implemented in August 2006.

In June 2006, Entergy New Orleans made its annual scheduled formula rate plan filings with the City Council.  The filings show various alternatives to reflect the effect of Entergy New Orleans' lost customers and decreased revenue. Entergy New Orleans' recommended alternative adjusts for lost customers and assumes that a decreasethe City Council's June 2006 decision to allow recovery of $0.2all Grand Gulf costs through the fuel adjustment clause stays in place (a portion of Grand Gulf costs was previously recovered through base rates). Under that alternative, annual increases of $6.4 million in electric base rate revenues is warranted and an(an increase of $3.94.4%) and $22.8 million in gas base rate revenues is(an increase of 160.9%) are warranted. The filings triggered the prescribed four-month period for review by the City Council's Advisors and other parties, and rate adjustments, if any, could be implemented as soon as September 2005.the first billing cycle of November 2006.

In May 2005,At the same time as it made its formula rate plan filings, Entergy New Orleans also filed with the City Council a request to implement two storm-related riders. With the first rider, Entergy New Orleans seeks to recover over a ten-year period the $114 million in electric restoration costs and the $25 million in gas restoration costs that it has actually spent through March 31, 2006. Entergy New Orleans also proposed semiannual filings to update the rider for continuationadditional restoration spending and also to consider the receipt of CDBG funds or insurance proceeds that it may

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receive. With the second rider, Entergy New Orleans seeks to establish over a ten-year period a $150 million storm reserve to provide for the risk of another storm. Entergy New Orleans requested that the City Council consider the proposed riders within the same time frame as the formula rate plan and generation performance-based rate plan for an additional three years. The filing requests a target equity componentplans, which would allow implementation as soon as the first billing cycle of the capital structure of 45%, an increase from the current target of 42%.November 2006.

Federal Regulation

System Agreement Litigation

On June 1, 2005,See the FERC issuedForm 10-K for a decision in the System Agreement litigation. The domestic utility companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the termsdiscussion of the System Agreement which has been approved bylitigation proceedings at the FERC. In April 2006, Entergy filed with the FERC its compliance filing to implement the provisions of the FERC's decision. The filing amends the System Agreement litigation proceedings are described into provide for the Form 10-K.

The FERC decision concluded, among other things, that:

• The System Agreement no longer roughly equalizescalculation of production costs, average production costs, and payments/receipts among the domestic utility companies.
• In ordercompanies to reachthe extent required to maintain rough production cost equalization pursuant to the FERC will impose a bandwidth remedy allowing for a maximum spread of 22 percent (expressed by the FERC as +/- 11%) between the total annual production costs of the highest costFERC's decision, and lowest cost domestic utility companies.
• When calculating the production costs for this purpose, output from the Vidalia hydroelectric power plant will not reflect the actual Vidalia price formakes clear that year butall payments/receipts will be priced at that year's average MSS-3 price, reducing the amount of Vidalia costs reflected in the comparison of the domestic utility companies' total productionclassified as energy costs.
• The remedy ordered by FERC calls for no refunds andpayments/receipts would be effective based on the calendar year 2006 production costs, with any payments/receipts among the first potential reallocation payments, if required, expecteddomestic utility companies to be made in twelve equal monthly installments, commencing in June 2007.

Motions to intervene without protest were filed by the City of New Orleans, the MPSC, the Louisiana Energy Users Group, and Occidental Chemical Corporation. Protests to the compliance filing were filed by the APSC, the LPSC, Arkansas Electric Energy Consumers, Inc. (AEEC), and the Arkansas Attorney General (Arkansas AG). Among other things, the LPSC urged the FERC: (1) to require any payments/receipts to commence in January 2007, rather than June 2007, and to require such payments to be made in a single lump sum payment, rather than in twelve equal monthly installments, or in the alternative to require a paying utility company to complete all payments within the calendar year following the year in which the disparity occurred; (2) to find that the bandwidth remedy is analogous to a "cost-of-service tariff with deferred billing," as opposed to a prospective remedy, so that a utility company could be required to make a payment based on a previous year's production costs even if such utilit y company has exited the System Agreement and so that interest would be due on the amount of any payment; and (3) to order interest on any payments to the extent they are not made in a single lump sum amount. In addition to the above issues, the LPSC and the other parties filing protests urged the FERC to require the bandwidth calculation to be set forth in a separate service schedule within the System Agreement, rather than the existing Service Schedule MSS-3 as proposed by Entergy. The APSC's protest urged the FERC to require that the bandwidth formula include all bandwidth payments as a production cost of the paying utility company for the year in which the payment is made, instead of excluding such costs as proposed in the compliance filing. The AEEC, among other things, urges the FERC to segregate the capacity and energy cost components of any bandwidth payments/receipts. The domestic utility companies responded to the issues raised in the protests and urged the FERC to approve the compliance filing as submitted by Entergy. The LPSC filed a reply to Entergy's response reasserting its previous positions and alleging, among other things, that Entergy was trying to delay the bandwidth payment in an effort to protect purported excess profits at Entergy Arkansas.

Separately, in July 2006 the LPSC filed with the FERC a Motion for Summary Disposition on the same issues that the LPSC had raised in its protests to the compliance filing. The domestic utility companies filed an answer urging the FERC to reject the LPSC's Motion for Summary Disposition and asking the FERC for summary disposition of several issues in favor of the domestic utility companies' positions.

The FERC's June 2005 orderdecision in the System Agreement proceeding is currently pending before the United States Court of Appeals for the D.C. Circuit. The parties to the proceeding reached agreement on a proposed briefing schedule that would result in the various parties submitting initial and reply briefs between August and November 2006. The proposed briefing schedule has been submitted to the Court of Appeals.

The FERC's decision would reallocate total production costs of the domestic utility companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility companies whose production costs are more than 11% below Entergy System average production costs to domestic utility companies whose production costs are abovemore than the Entergy System average production costs. Ancost, with payments going first to those

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domestic operating utilities whose total production costs are farthest above the Entergy System average. For purposes of the Entergy Arkansas rate filings discussed above in "State and Local Rate Regulation" that are expected to be made in mid-August 2006, an assessment of the potential effects of the FERC's June 2005 order, requires assumptions regardingas amended by its December 2005 order on rehearing, has been calculated on the future total production costbasis of each domestic utility company, which assumptions includea 2006 test year, using a 2006 gas price that consists of a non-weighted average of twelve months of gas prices calculated as follows: January through May 2006 are actual, volume-weighted monthly averages of day-ahead cash prices as reported byEnergy Intelligence Natural Gas Week; the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power.  Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy ArkansasJune 2006 price is the l east dependent upon gas-fired generation.  Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costsFirst of the domestic utility companies.  Considerable uncertainty exists regarding future gas prices. Annual averageMonth Index price as reported byPlatts Inside FERC's Gas Market Report; the July 2006 price is the 5/31/06 NYMEX Henry Hub settlement price; and August through December 2006 are 30 calendar - -day rolling averages as of May 31, 2006 of forward NYMEX Henry Hub gas contracts.  For example the August 2006 price is an average of all the daily NYMEX settlement prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004August 2006 contract for each trading day from the period and averaging $3.43/mmBtu during5/2/06 - - 5/31/06 inclusive.  A similar calculation is made using the ten-year period 1995-2004 and $4.58/mmBtu duringdaily settlements of the five-year period 2000-2004.  Recent market conditions haveSeptember 2006 through December 2006 NYMEX contracts to arrive at those monthly prices. This resulted in an average annual gas prices that have averaged $5.85/mmBtu for the twelve months ended December 2004. During the 12 month period July 1, 2004 to June 30, 2005 forward gas contracts for eachprice of the next four years based on daily NYMEX close averaged $6.68/mmBtu (2006), $6.25/mmBtu (2007), $5.88/mmBtu (2008) and $5.58/mmBtu (2009).$7.49/mmBtu. If the FERC's June 2005 order, as amended by its December 2005 order on rehearing, becomes final and if thesean annual average gas prices occurprice of $7.49/ mmBtu occurs for 2006 as assumed, the following potential annual production cost reallocationsreallocation among the domestic utility companies could result during the 2007-2010 period:result:

If natural gas prices deviateIn calculating the production costs for this purpose under the FERC's order, output from the Vidalia hydroelectric power plant does not reflect the actual Vidalia price for the year but is priced at that year's average price paid by $1/mmBtu upEntergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the domestic utility companies' total production costs.

APSC Complaint at the FERC

In June 2006, the APSC filed a complaint with the FERC against Entergy Services as the representative of Entergy Corporation and the domestic utility companies, pursuant to Sections 205, 206 and 207 of the Federal Power Act. The APSC states that "The purpose of the complaint is to institute an investigation into the prudence of Entergy's practices affecting the wholesale rates that flow through its System Agreement." The complaint requests, among other things, that the FERC disallow any costs found to be imprudent, with a refund effective date to be set at the earliest possible time. Specific areas of requested investigation include:

• The domestic utility companies' transmission expansion and planning process, including the construction, or down,lack thereof, of economic transmission upgrades;
• The domestic utility companies' wholesale purchasing practices, including the potential savings due to integration of independent power producers into their economic dispatch;
• The domestic utility companies' alleged failure to retire their aging, inefficient gas- and oil-fired generation; and
• The alleged failure to construct or acquire coal capacity for the generation portfolio of Entergy Louisiana.

The complaint also requests that the FERC exercise its authority under Section 207 of the FPA to investigate the adequacy of Entergy's transmission system and direct it to make all necessary upgrades to ensure that its transmission facilities provide reliable, adequate and economic service.

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On July 31, 2006, the domestic utility companies submitted their answer to the APSC complaint. In their answer, the domestic utility companies acknowledge that while the FERC is expectedthe appropriate forum to consider the issues raised in the APSC's complaint, the APSC has provided no probative evidence supporting its allegations and has not met the standards under the Federal Power Act (FPA) to have a matter set for hearing. Under the FPA standards, the APSC must create "serious doubt" as to the propriety of the challenged actions. As indicated in the domestic utility companies' answer, the APSC complaint does not raise a "serious doubt" but instead largely relies on unsupported assertions, many of which have been investigated in other proceedings. In those limited instances when the APSC complaint references "evidence" in an attempt to support its request for a hearing, the "evidence" to which it refers in fact does nothing to support its position but, rather, shows that Entergy Arkansas' annual payments will changehas acted prudently. As further indicated in the same direction by approximately $60 to $70 million.

Various pending motions for rehearing and clarificationdomestic utility companies' answer, following the issuance of the FERC's June 2005System Agreement decision, all of the production costs of the domestic utility companies are now inputs to a formula rate that will result in bandwidth payments among the domestic utility companies in order wereto roughly equalize production costs. Based on well-established Supreme Court precedent, the FERC has exclusive jurisdiction over all inputs that will be included in the System Agreement bandwidth formula rates filed byin compliance with the FERC's System Agreement decision and retail regulators are preempted from taking any action that disturbs the FERC's findings with respect to these production cost inputs and the FERC-determined allocation of production costs among the domestic utility companies. The domestic utility companies believe that their conduct with respect to these issues has been prudent and will vigorously defend such conduct.

Several parties tohave intervened in the proceeding, including the LPSC,MPSC, the APSC, the MPSC,LPSC, and the City Council,Council. The LPSC's answer and by Entergy Services, Inc., on behalf ofcomments in response to the domestic utility companies. Among other things, the LPSC's motion urgedAPSC Complaint ask the FERC to "clarify"investigate whether Entergy Arkansas' withdrawal from the System Agreement is fair, just, and reasonable.

In 2004, the APSC commenced an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interests of its customers. Citing its concerns that the FERC'sbenefits of its continued participation in the current form of the System Agreement have been seriously eroded, in December 2005, Entergy Arkansas submitted its notice that it will terminate its participation in the current System Agreement effective 96 months from December 19, 2005 or such earlier date as authorized by the FERC. Entergy Arkansas indicated, however, that a properly structured replacement agreement could be a viable alternative. In June 2006 the APSC issued an order requires the payments and receipts,in its investigation requiring Entergy Arkansas President Hugh McDonald to file testimony in response to several questions involving details of what action Entergy Arkansas or Entergy has taken to insure that Entergy Arkansas' customers are protected from additional costs including those related to the extent any are required,following area s: construction of new generating plants located outside of Arkansas, costs of the Entergy New Orleans bankruptcy, and costs associated with restoration of facilities damaged by Hurricanes Katrina and Rita. Mr. McDonald was also directed to be made in 2006 based on production costs incurred in 2004 and 2005. Entergy does not believe that this request for "clarification" is consistent with the FERC order and submitted a response urgingdescribe actions taken since December 19, 2005 to encourage or persuade the FERC to reject this interpretation and instead find thatauthorize Entergy Arkansas to exit the annual remedy order by the FERC would be evaluated based on calendar year 2006 production costs, with the first potential payments/receipts, if any were required, made in 2007.

Management believes that any changes in the allocation of production costs resulting from the FERC's June 2005 order and related retail proceedings should result in similar rate changes for retail customers. The timing of recovery of these costs in rates could be the subject of additional proceedings before Entergy's retail regulators. Although the outcome and timing of the FERC and other proceedings cannot be predicted at this time, Entergy does not believe that the ultimate resolution of these proceedings will have a material effect on its financial condition or results of operations.

See the Form 10-K for discussion of the proceeding that the LPSC commenced before itself regarding the System Agreement. As noted above in "State and Local Rate Regulation," the settlement of various issues involving Entergy Gulf States and Entergy Louisiana that was approved by the LPSC has resolved the System Agreement proceeding before the LPSC, which has been dismissed without prejudice.

Transmission

See the Form 10-K forsooner than 96 months, and to describe current and future actions related to development of a discussion of the petition for declaratory order that Entergyreplacement system agreement. Responsive testimony was filed with the FERCAPSC in January 2005 regarding Entergy's July 2006. A public hearing for the purpose of cross-examination of Mr. McDonald on his testimony and for questioning by the APSC was also conducted in July 2006.

Independent Coordinator of Transmission (ICT) proposal. On March 22, 2005, the FERC issued a declaratory order concluding that: (1) because the Southwest Power Pool (SPP) was the only entity identified as potentially being selected as the ICT and because the SPP is already a "public utility" there was no need to rule on the question of whether the functions of the ICT, alone, would serve to make the ICT a "public utility;" (2) Entergy will continue to be the "transmission provider" for transmission service across its system and that "the presence of SPP as the ICT will not change the existing balance of jurisdiction between [the FERC] and Entergy's retail regulators;" and (3) the FERC "is prepared to grant Entergy's proposed transmission pricing proposal on a two-year experimental basis, subject to certain enhancement and monitoring and reporting co nditions." The enhancements referred to by the FERC involve more fully specifying the responsibilities and duties of the ICT, including defining the ICT's role in the preparation of various transmission expansion plans and the performance of studies related to the granting of transmission or interconnection service. Before Entergy's ICT proposal can be implemented, however, Entergy is required to submit further filings with the FERC regarding the modifications and clarifications to the ICT proposal.

OnIn April 8, 2005 several intervenors filed an Emergency Request for Clarification and Request for Expedited Commission Action seeking to have the FERC: (1) clarify the ICT's role in administering the Available Flowgate Capacity (AFC) methodology; (2) clarify the ICT's role in developing the transmission base plan; (3) clarify what the FERC meant when it required Entergy to provide firm transmission rights to customers that pay for supplemental transmission upgrades; and (4) clarify and confirm following Entergy's filing that the FERC will assess SPP's status as being independent of Entergy.

On April 21, 2005 Entergy filed a request for clarification or rehearing of the FERC's March 22 declaratory order requesting that the FERC clarify the respective role of Entergy and the ICT in developing the inputs or criteria used to create the base plan and in preparing certain studies regarding system expansion. The request for clarification further requests that the FERC clarify that the initial two-year period will commence with the actual start date of ICT operations. In the event that the FERC denies Entergy's request for clarification, then Entergy will seek rehearing on these issues. However, in its request, Entergy requested that FERC not rule on these issues at this time but, instead, that the FERC wait to evaluate these issues until such time as Entergy has filed the more detailed tariff sheets and protocols in its subsequent filing to implement the ICT. Separately, Entergy submitted a letter advising the FERC that it intended to submit on or about May 27, 2005 the filing t o implement the ICT proposal. A joint request for rehearing of the ICT declaratory order was also filed by the City Council, the LPSC, and the MPSC in which the retail regulators expressed their concerns that the findings reached in the declaratory order may result in an expansion of authority of the ICT "that is unnecessary to achieve the [FERC's] goals and is very likely to result in significant increases in the start-up and operational costs of the ICT." The retail regulators request that the FERC not act on their request for rehearing until Entergy has submitted its filing to implement the ICT. The intervenors filed a separate request for rehearing on April 21, 2005 urging the FERC to impose additional conditions on the approval of the ICT and also re-urging the FERC to reject the pricing proposal contained in the ICT proposal.

On May 12, 20052006 the FERC issued an order clarifying certain aspects ofapproving with modification Entergy's ICT proposal filed in May 2005. In its March 22 order. In the May 12 order, the FERC indicated thatFERC: (1) Entergy is to work with the ICT and Entergy's stakeholders to develop procedures by which the ICT will calculate AFCs; (2) Entergy must specifically define the transmission rights that a customer that pays for supplemental upgrades will receive for such payments; (3) the FERC will review the ICT's contract to ensure that the ICT can perform its functions in an independent manner even if SPP is chosen as the ICT; and (4) the initial two-year period will start once the ICT becomes operational.

On May 27, 2005, the domestic utility companies filed the enhanced ICT proposal with the FERC. Entergy believes that the filing is consistent with the FERC guidance received in both the FERC's March 22 and May 12 orders on the ICT. Among other things, the enhanced ICT filing states that the ICT will (1) grant or deny transmission service on the domestic utility companies' transmission system; (2) administer the domestic utility companies' OASIS node for purposes of processing and evaluating transmission service requests and ensuring compliance with the domestic utility companies' obligation to post transmission-related information; (3) develop a base plan for the domestic utility companies' transmission system that will result in the ICT making the determination on whether something should be rolled into the domestic utility companies' transmission rates or directly assigned to the customer requesting or causing an upgrade to be constructed; (4) serve as the reliability coordinator for t he Entergy transmission system; and (5) oversee the operation of the weekly procurement process. The enhanced ICT proposal clarifies the rights that customers receive when they fund a supplemental upgrade and also contains a detailed methodology describing the process by which the ICT will evaluate interconnection-related investments already made on the Entergy System for purposes of determining the future allocation of the uncredited portion of these investments.

On June 3, 2005 a group of generators filed with the FERC a request that the FERC schedule a technical conference on the enhanced ICT proposal in order for Entergy to provide additional information on the enhanced ICT proposal. In response, a stakeholder meeting was held in New Orleans on June 30, 2005. Interventions and comments on the filing are due by August 5, 2005.

In addition, as discussed in the Form 10-K, Entergy Louisiana and Entergy Gulf States have filed an application with the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. An LPSC hearing on the ICT proposal is currently scheduled for August 2005, however certain intervenors have recently requested that the hearing be delayed until mid-September 2005.

FERC's Supply Margin Assessment

See the Form 10-K for a discussion of the FERC's supply margin assessment and, in particular, the order issued by the FERC in December 2004 pursuant to Section 206 of the Federal Power Act (FPA).  On June 30, 2005, the FERC issued an order addressing Entergy's delivered price test (DPT) analysis.  The FERC found that material questions of fact exist that may affect the results of the DPT submitted by Entergy.  These issues include, for example, whether the entire Entergy control area is the appropriate relevant geographic market or whether there exist binding transmission constraints such that it is more appropriate to define more than one geographic market within the Entergy control area.  Accordingly, the FERC initiated an evidentiary hearing to address the impact of any transmission constraints on the appropriate scope of the relevant market; which information will be required prior to the FERC making a determination on whether Entergy has market power within its con trol area. On July 22, 2005, Entergy notified the FERC that it was withdrawing its request for market-based rate authority for sales within its control area. Instead, the domestic utility companies and their affiliates will transact at cost-based rates for wholesale sales within the Entergy control area. Entergy indicated that it will file the proposed cost-based rate schedules within 60 days.Additionally, Entergy reserves its right to request market-based rate authority for sales within its control area in the future. The FERC ALJ in the proceeding issued an order that cancelled a pre-hearing conference set for July 26, 2005, set a deadline of August 8, 2005 for objections to Entergy's notice of withdrawal, and stated that if no objections were filed by August 8, 2005 Entergy's withdrawal notice will have disposed of all pending issues in the proceeding. The relinquishment of market-based rates for sales within the Entergy control area is not expecte d to have a material effect on the financial results of Entergy.

Additionally, on May 5, 2005, the FERC issued an order addressing the remaining prongs in the market-based rate proceeding: transmission market power, barriers to entry/reciprocal dealing, and affiliate abuse.  The FERC granted rehearing in part and instituted a proceeding under Section 206 of the FPA to investigate whether Entergy satisfies the FERC's transmission market power and affiliate abuse/reciprocal dealing standards for the granting of market-based rate authority, and established a refund effective date pursuant to the provisions of Section 206, for purposes of the additional issues set for hearing.  However, the FERC decided to hold that investigation in abeyance pending the outcomes of the ICT proceeding and the affiliate purchased power agreements proceeding.  The FERC declined to require a hearing on the remaining prong regarding barriers to entry.  On June 6, 2005, Entergy sought rehearing of the May 5 Order and that request for rehearing is pending .

Interconnection Orders

See the Form 10-K for a discussion of the ALJ Initial Decision and FERC order directing Entergy Louisiana to refund, in the form of transmission credits, approximately $15 million in expenses and tax obligations previously paid by a generator. Entergy's request for rehearing was denied by the FERC.

Available Flowgate Capacity Proceedings

See the Form 10-K for a discussion of proceedings at the FERC involving Entergy's Available Flowgate Capacity (AFC) methodology. On March 22, 2005, the FERC issued an order contemporaneously with the ICT declaratory order discussed above that holds the AFC hearing in abeyance pending action on Entergy's upcoming ICT filing. The order holding the hearing in abeyance further indicated that it would cancel the hearing when the ICT begins to perform its functions. On April 8, 2005 several intervenors filed Emergency Motions for Interim Relief and Expedited Commission Action requesting that, during the interim period before the implementation of the ICT, the FERC (1) institute an audit process to examine and modify Entergy's current AFC process; and (2) require SPP to become involved in the AFC stakeholder process and order certain modifications to Entergy's stakeholder process. The audit process being proposed by the intervenors would not involve an independent auditor, but instead wou ld be an investigation performed by a representative from the intervenors, Entergy, and possibly SPP.  On April 25, 2005, Entergy filed its response to the emergency motion urging the FERC to reject the intervenors' request for the "audit" because the type of investigation proposed by the intervenors would be neither independent nor fair and would only distract from the implementation of the ICT.  Instead, Entergy has proposed that the ICT conduct an independent review of the AFC process and procedures as part of its transition to assuming the identified ICT responsibilities, including the calculation of the AFCs.  Entergy further indicated that it would welcome SPP's participation in the current stakeholder process. On April 21, 2005, the intervenors filed a separate request for rehearing arguing that the FERC must allow the AFC hearing to proceed in parallel withapproved the establishment of the ICT. See "Transmission" aboveICT, with modifications; (2) approved Entergy's proposed pricing policy, with modifications; (3) approved the implementation of a weekly procurement process (WPP); and (4) ordered Entergy to submit a compliance filing and an executed contract with the Southwest Power Pool (SPP), the approved ICT, within 60 days of the order. Several parties have filed requests for further discussionrehearing of AFC.the FERC order, and those requests are still pending.

Utility Restructuring

Previous developmentsThe proposed modifications include, among other things: (1) Entergy must file with the FERC the criteria used to grant and information relateddeny transmission service, including calculating available flowgate capacity; (2) the FERC extended the initial term of the ICT from two years to electric industry restructuring are presented in Note 2four years; and Entergy is precluded from terminating the ICT prior to the consolidated financial statementsend of the four year period; (3) the

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 establishment of a transmission users group that will provide input directly to the ICT on the effectiveness of the ICT Proposal and also will propose to the FERC an appropriate means by which they could be given access to inputs in the Form 10-K. The following are updatesprocess and models under the direction of the ICT; (4) with regard to any dispute between the Form 10-K.

Retail-Texas

In June 2005, a Texas law was enacted which provides that:

• ICT and Entergy Gulf States is authorized byconcerning transmission service requests, transmission planning, and interconnection requests, the legislationICT's position will prevail during the pendency of the dispute resolution; and (5) the WPP must be operational within approximately 14 months of the FERC order or the FERC may reevaluate all approvals to proceed with a jurisdictional separation into two vertically integrated utilities, one subject solelythe ICT.

  Entergy made its compliance filing with the FERC on May 24, 2006, including the executed ICT agreement with SPP. Entergy informed the FERC that, assuming it has received all required approvals, Entergy intends to install SPP as the retail jurisdictionICT within 30 days of FERC approval of the ICT agreement. Several parties have filed protests regarding Entergy's compliance filing, and consideration of Entergy's compliance filing is pending at the FERC.

  The LPSC and one subject solelyvoted to approve the retail jurisdiction of the PUCT;

• the portions of all prior PUCT orders requiring Entergy Gulf States to comply with any provisions of Texas law governing transition to retail competition are void;
• Entergy Gulf States must file a plan by January 1, 2006, identifying the power region(s) to be considered for certification and the steps and schedule to achieve certification;
• Entergy Gulf States must file a transition to competition plan no later than January 1, 2007, that would address how Entergy Gulf States intends to mitigate market power and achieve full customer choice, including potential construction of additional transmission facilities, generation auctions, generation capacity divestiture, reinstatement of a customer choice pilot project, establishment of a price to beat, and other measures;
• Entergy Gulf States' rates are subject to cost-of-service regulation until retail customer choice is implemented;
• Entergy Gulf States may not file a general base rate case in Texas before June 30, 2007, with rates effective no earlier than June 30, 2008, but may seek before then the recovery of certain incremental purchased power capacity costs, adjusted for load growth, not in excess of five percent of its annual base rate revenues (as discussed above in "State and Local Regulation,"ICT proposal in July 2005 Entergy Gulf States filed a request for implementation of an incremental purchased capacity recovery rider); and
• Entergy Gulf States may recover over a period not to exceed 15 years reasonable and necessary transition to competition costs incurred before the effective date of the legislation and not previously recovered, with appropriate carrying charges.

Retail-Louisiana2006.

In November 2001, the LPSC decided not to move forward with retail open access for any customers at this time. The LPSC instead directed its staff to hold collaborative group meetings concerning open access from time to time, and to have the LPSC staff monitor developments in neighboring states and to report to the LPSC regarding the progress of retail access developments in those states. In September 2004, in response to a study performed by the Louisiana State University Center for Energy Studies that evaluated a limited industrial-only retail choice program, the LPSC asked the LPSC staff to solicit comments and obtain information from utilities, customers, and other interested parties concerning the potential costs and benefits of a limited choice program, the impact of such a program on other customers, as well as issues such asstranded costs and transmission service. Comments from interested parties were filed with the LPSC in Janua ry 2005. A technical conference was held in April 2005 and in May 2005 interested parties filed reply comments to arguments made at the technical conference. Entergy stated that it believes that there is no new information or credible evidence that would justify altering the LPSC's previous conclusion that retail access is not in the public interest.

Federal Legislation

In late July 2005 the U.S. Congress passed broad new energy legislation, the Energy Policy Act of 2005. The legislation contains electricity provisions that, among other things:

• Repeal the Public Utility Holding Company Act of 1935 (PUHCA), effective six months after enactment of the Energy Policy Act. As a registered holding company system, Entergy is subject to PUHCA. Some of the more significant effects of PUHCA are that it limits the operations of a registered holding company system to a single, integrated public utility system; regulates transactions among affiliates within a holding company system; governs the issuance, acquisition, and disposition of securities and assets by registered holding companies and their subsidiaries; limits the entry by registered holding companies and their subsidiaries into businesses other than electric or gas utility businesses; and requires SEC approval for certain utility mergers and acquisitions. Certain consumer protection authorities were transferred to the FERC, including new authority over utility mergers and acquisitions, and to the state or local regulatory commissions.
• Codifies the concept of participant funding, a form of cost allocation for transmission interconnections and upgrades, and allows FERC to apply participant funding in all regions of the country. Participant funding helps ensure that a utility's native load customers only bear the costs that are necessary to provide reliable transmission service to them and not bear costs required by generators who seek to deliver power to other regions.
• Provides financing benefits, including loan guarantees and production tax credits, for new nuclear plant construction, and reauthorizes the Price-Anderson Act, the law that provides an umbrella of insurance protection for the payment of public liability claims in the event of a major nuclear power plant incident.
• Revises current tax law treatment of nuclear decommissioning trust funds by allowing regulated and nonregulated taxpayers to make deductible contributions to fund the entire amount of estimated future decommissioning costs.
• Provides a more rapid tax depreciation schedule for transmission ass ets to encourage investment.
• Creates mandatory electricity reliability guidelines with enforceable penalties to help ensure that the nation's power transmission grid is kept in good repair and that disruptions in the electricity system are minimized.  Entergy already voluntarily complies with National Electricity Reliability Council standards, which are similar.
• Establishes conditions for the elimination of the Public Utility Regulatory Policy Act's (PURPA) mandatory purchase obligation from qualifying facilities.

The President is expected to sign the Energy Policy Act in August 2005. The Energy Power Act requires several rulemakings by the FERC and other government agencies in order to implement its provisions. Therefore, it will be some time before a full assessment of its effect on Entergy and the energy industry can be completed.

Market and Credit Risks

Commodity Price Risk

Power Generation

As discussed more fully in the Form 10-K, somethe sale of electricity from the power generation plants owned by Entergy's Non-Utility Nuclear business and Energy Commodity Services business, unless otherwise contracted, is subject to the fluctuation of market power prices. Following is an updated summary of the amount of the Non-Utility Nuclear business' output that is sold forward under physical or financial contracts (2006 represents the remaining two quarters of the year):

1. 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.

See the Form 10-K for a discussion of Non-Utility Nuclear's value sharing agreements with NYPA involving energy sales from the Fitzpatrick and Indian Point 3 power plants and a discussion of the Vermont Yankee PPA price adjustment clause.

Some of the agreements to sell the power produced by Entergy's Non-Utility Nuclear power plants and the wholesale supply agreements entered into by Entergy's Competitive Retail business contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements. The Entergy subsidiary maywill be required to provide collateral based upon the difference between the current market and contracted power prices in the regions where the Non-Utility Nuclear and Competitive Retail businesses sellsells power. The primary form of the collateral to satisfy these requirements would be an Entergy Corporation guaranty.  Cash and letters of credit are also acceptable

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 forms of collateral.  At June 30, 2005,2006, based on power prices at that time, Entergy had in place as collateral $922.7$1,275 million of Entergy Corporation guarantees $81.0for wholesale transactions, including $100 million of whichguarantees that support letters of credit. The assurance requirement associated with Non-Utility Nuclear is estimated to increase by an amount up to $445 million if gas prices increase $1 per MMBtu in both the short- and long-term markets. In the event of a decrease in Entergy Corpo ration'sCorporation's credit rating to specified levels below investment grade, Entergy maywill be required to replace Entergy Corporation guarantees with cash or letters of credit under some of the agreements.

Central States Compact Claim

The Low-Level Radioactive Waste Policy ActIn addition to selling the power produced by its plants, the Non-Utility Nuclear business sells installed capacity to load-serving distribution companies in order for those companies to meet requirements placed on them by the ISO in their area. Following is a summary of 1980 holds each state responsible for disposal of low-level radioactive waste originating in that state, but allows states to participate in regional compacts to fulfill their responsibilities jointly.  Arkansas and Louisiana participate in the Central Interstate Low-Level Radioactive Waste Compact (Central States Compact or Compact).  Commencing in 1998, Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana made a series of contributions to the Central States Compact to fund the Central States Compact's development of a low-level radioactive waste disposal facility to be located in Boyd County, Nebraska.  In December 1998, Nebraska, the host state for the proposed Central States Compact disposal facility, denied the compact's license application for the proposed disposal facility.  Several parties, including the commission that governs the compact (the Compact Commission), filed a lawsuit against Nebraska seeking damages resulting from Nebraska's denial of the proposed facility's license.  After a trial, the U.S. District Court concluded that Nebraska violated its good faith obligations regarding the proposed waste disposal facility and rendered a judgment against Nebraska in the amount of $151 million.  In August 2004, Nebraska agreed to pay the Compact $141 million in settlement ofNon-Utility Nuclear business' installed capacity that is currently sold forward, and the judgment. In July 2005, the Compact Commission decided to distribute a substantial portion of the proceeds from the settlement to the nuclear power generators that had contributed funding for the Boyd County facility, including Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana. On August 1, 2005, Nebraska paid the fullblended amount of the settlement toNon-Utility Nuclear business' planned generation output and installed capacity that is currently sold forward (2006 represents the Compact, and the Compact distributed from the settlement proceeds $23.6 million to Entergy Arkansas, $19.9 million to Entergy Gulf States, and $18.4 million to Entergy Louisiana.  Management is still analyzing the accounting treatmentremaining two quarters of the receip ts, but expects that some portion of the receipts could result in income for Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana.year):

Critical Accounting Estimates

See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS -Critical Accounting Estimates" in the Form 10-K for a discussion of the estimates and judgments necessary in Entergy's accounting for nuclear decommissioning costs, unbilled revenue, impairment of long-lived assets, qualified pension and other postretirement benefits, and other contingencies. The followingFollowing is an update to the information provided in the Form 10-K.that discussion.

Nuclear Decommissioning CostsUnbilled Revenue

InAs discussed in Note 10 to the consolidated financial statements, effective January 1, 2006, Entergy Louisiana and the Louisiana portion of Entergy Gulf States reclassified the fuel component of unbilled accounts receivable to deferred fuel and will no longer include the fuel component in their unbilled revenue calculations, which is in accordance with regulatory treatment.

Recently Issued Accounting Pronouncements

FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes" (FIN 48) was issued in July 2006 and is effective for Entergy in the first quarter of 2005, Entergy's Non-Utility Nuclear business recorded2007. The FASB's objective in issuing this interpretation is to increase comparability among companies in financial reporting of income taxes. FIN 48 establishes a reduction of $26.0 million in its decommissioning cost liability in conjunction with"more-likely-than-not" recognition threshold that must be met before a new decommissioning cost study as a result of revised decommissioning costs and changes in assumptions regarding the timing of when the decommissioning of a plant will begin. The revised estimate resulted in miscellaneous income of $26.0 million ($15.8 million net-of-tax), reflecting the excess of the reductiontax benefit can be recognized in the financial statements. If a tax deduction is taken on a tax return, but does not meet the more-likely-than-not recognition threshold, an increase in income tax liability, overabove what is payable on the amount of undepreciated asset retirement cost.

In the second quarter of 2005, Entergy Louisiana recorded a revisiontax return, is required to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for Waterford 3 that reflected an expected life extension for the plant. The revised estimate resulted in a $153.6 million reduction in its decommissioning liability, along with a $49.2 million reduction in utility plant and a $104.4 million reduction in the related regulatory asset.

Recently Issued Accounting Pronouncements

In the first quarter 2005, FASB issued FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143" (FIN 47). FIN 47 requires companies to recognize at fair value a liability for a conditional asset retirement obligation when incurred, which is generally upon an asset's acquisition, construction, development, or through its normal operation. A conditional asset retirement obligation is generally a legal obligation to incur costs to remove an asset or part of an asset, such as an obligation to comply with environmental regulations and requirements. The obligation is conditional because there is currently no legal requirement to retire or remove the facility that the affected asset is a part of. FIN 47 requires that uncertainty about the timing or method of settlement of a conditional asset retirement obligation be factored into the measurement of the liability when sufficient information becomes available. FIN 4 7 will be effective for Entergy no later than December 31, 2005.recorded. Entergy does not believeexpect that the adoption of FIN 4748 will be material tomaterially affect its financial position, or results of operations, because it estimates that any conditional asset retirement obligations required to be recognized under FIN 47 would be offset by a regulatory asset because of the expected recovery of these future costs in rates.or cash flows.

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